ML20137P712

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Proposed Tech Spec Changes to Reflect Design Change in Progress to Complete Installation of Drywell Chilling Water Sys
ML20137P712
Person / Time
Site: Grand Gulf Entergy icon.png
Issue date: 01/29/1986
From:
MISSISSIPPI POWER & LIGHT CO.
To:
Shared Package
ML20137P677 List:
References
TAC-60587, TAC-60588, TAC-60589, TAC-60590, TAC-60591, TAC-60592, NUDOCS 8602050305
Download: ML20137P712 (53)


Text

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES MAXIMUM SYSTEM AND PENETRATION ISOLATION TIME VALVE NUM3B NUMBER VALVE GROUP (a) (Seconds)

Containment (Continued)

Main Steam Line B21-F019-A 19(0) 1 20 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-B 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) 6B 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

.o Vent Air Exh.

gg Cont. Purge and Vent Air Exh.

M41-F035-(A) 35(0) 7 4 cjgc.

g 9%,__..,__ -.. em,^

P72-r:23- e 36(I) 6A 33 l cao Water Return c:c -+ Pl:nt S;rvice P"-F050-A 36(0) 6A 33 l Water Return P72- Fl22- A 8h$

OQ -+ Pl:nt 5:rvie: P"-F053-A 37(0) 6A 33 l o"

ca Water Supply P72-FI 21- A Chilled Water P71-F150-(A) 38(0) 6A 12 08 0

a) a.a. Supply

- Drywell 0.hHled.

GRAND GULF-UNIT 1 3/4 6-31 Amendment No. __lj l

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND DRYWELL ISOLATION VALVES Drewell Chdk1 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 P53-F007-B 335(0) 6A 7

-* Plant Service P44-f 075-?, 331(I) 6A 32 l

Water Return P72- F12 5 A

-+ Plant Service "

331(0) 6A 32 l Water Return -P44-f077 P 72- r:26- 5

,A Plant Service Pit-F071-B 332(0) 6A 32 l Water Return P 72- r : 2 4-6 RWCU Pump Suction G33-F250-A 337(I) 8 35 RWCU Pump Suction G33-F251-B 337(0) 8 35 Combustible Gas E61-F003B-B 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-F005B-B 340(0) 5 84 Con.

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

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

Drywell Air Purge M41-F015-(A) 345(I) 7 4 Supply Drywell Air Purge M41-F013-(B) 345(0) 7 4 Supply Drywell Air Purge M41-F016-(A) 347(I) 7 4 Exhaust Drywell Air Purge M41-F017-(B) 347(0) 7 4 Exhaust Equipment Drains P45-F009-(A) 348(I) 6A 6

~ Equipment Drains P45-F010-(B) 348(0) 6A 6 Floor Drains P45-F003-(A) 349(I) 6A 6 Floor Drains P45-F004-(B) 349(0) 6A 6 Service Air P52-F195-B 363(0) 6A 16 Chemical Sump P45-F096-A 364(I) 6A 9 Disch.

Chemical Sump P45-F097-B 364(0) 6A 9 Disch.

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

Reactor Water B33-F019-B 465(I) 10 36 Sample Line Reactor Water B33-F020-A 465(0) 10 36 Sample Line GRAND GULF-UNIT 1 3/4 6-34 i A m end. ment No. ---- I

TABLE 3.6.4-1 (Continued)

CONTAINMENT AND QRYWELL 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)Id) 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)

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)

HPCS Discharge E22-F201 26(I)

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

HPCS Test Line E22-F302 27(0)(,,))

HPCS Test Line E22-F301 i LPCS Pump Suction E21-F031 27(0)(d) 30(0)(

l LPCS Discharge E21-F006-(A) 31(I)

LPCS Discharge E21-F200 31(I)

LPCS Discharge E21-F207 LPCS Test Line E21-F217 31(I)(d)

LPCS Test Line E21-F218 32(0)(d) 32(0) l l CRD Pump C11-F122 33(I)

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

Water Supply Service Air P52-F122 41(I)

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

^

TABLE 3.6.4-1 (Continued)

CCNTAINMENT AND DRYWELL ISOLATION VALVES SYSTEM AND PENETRATION VALVE NUMBER NUMBER Drywell (Continued)

CRD to Recirc. B33-F017A 326(0)

Pump A Seals Instrument Air P53-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

--+- "':nt Strei : P40-f075 P72-M17 332(I) l Water Supply Condensate Flush B33-F204 333(I)

Conn.

Condensate Flush B33-F205 333'0)

Conn.

Combustible Gas E61-F002A 339(0)

Control Combustible Gas E61-F002B 338(0)

Control Combustible Gas E61-F004A 340(0)

Control Combustible Gas E61-F004B 340(0)

Control Upper Containment G41-F265 342(0)

Pool Drain CRD to Recirc. B33-F013B 346(I)

Pump B Seals CRD to Recirc. B33-F017B 346(0)

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

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) l Sys.

Containment NA 343(I)(0)

Leak Rate System Dr3well CMiled i

l l

\

GRAND GULF-UNIT 1 3/4 6-42 Amendment Mo.  !

i

TABLE 3.6.4-1 (Continued)

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

CRD T/C C11-F128 33(0)

Cont. Purge M41-F042 34(0)

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

Exhaust T/C p 72-Fi 67 DCW -P5W-supply T/C Nt-r333 37(0) l Plant Chilled P71-F232 38(0)

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

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

T/C Service Air T/C P52-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(I)

Upper Cont. Pool T/C Aux. Bldg. Fir. P45-F275 60(0)

& Equip. Drain Tk. to Suppr.

Pool T/C Aux. B1dg. 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 i (future use)

! Combustible Gas E61-F017 65(0)

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

Detector T/C i

l RHR "B" Test Line E12-F321 67(0)(c)

T/C RHR "B" Test Line E12-F351 67(0)(c) i T/C RHR "B" Test Line E12-F331 67(0)(c)

T/C

! GRAND GULF-UNIT 1 3/4 6-44 Amendment NE- l

4 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 l

BREAKER SETPOINT TIME SYSTEM / COMPONENT NUMBER (Amperes) (Seconds) AFFECTED 52-1112-21 800 0.100 480 V RECEPTACLE 52-1112-22 5 0.100 MOV-STM TUNNEL COOLER INLET (hfPfkF$505-UI 52-1112-24 32 0.100 MOV CLEANUP LINE RECIRC LOOP A (Q1G33F100-N) 52-1112-27 24 0.100 RESIN TANK AGITATOR (NIG360020-N) 52-1112-28 38 0.100 MOV RWCU HEAT

EXCHANGER BYPASS (NIG33F104-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 (TB1B33C001A) 52-1112-37 800 0.100 480 V RECEPTACLE 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) 52-1113-21 60 0.100 DRYWELL EQUIP DRAIN SUMP PUMP (N1P45C002B-N) 52-1113-30 28 0.100 MOV RWCU HX OUTL ISOL VLV (NIG33F254-N)

GRAND GULF-UNIT 1 3/4 8-23 AnvendJnenh Mo. -  !

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 NUM8ER (Amperes) (Seconds) AFFECTE0 52-1251-13 800 0.100 CNTMT CLR FAN COIL UNIT FAN (N1M418001C-N) 52-1251-15 32 0.100 MOV - RWCS HX INL ISOL VLV (N1G33F256-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 (NIG33F031-N) 52-1251-20 320 0.100 CNTMT EQUIP DRAIN PUMP (N1P45C0048-N) 52-1251-22 32 0.100 MOV - RWCU TO FLT "S" ISOL VLV l (NIG33F255-N) 52-1251-26 1200 0.100 LIGHTING XFNR 1X112 (NIR185112-D) 52-1251-28 5 0.100 MOV - STM TUNNEL COOLER INLET

,m, ..e,ar._us g

fN1P72f150BM' 52-1252-23 60 0.100 DRYWELL FLOOR DRAIN SUMP PUMP (N1P45C0018-N) 52-1252-27 500 0.100 FUEL TRANSFER

! SYS M CONSOLE I

(N1F11E015-MC) 52-1411-01 38 0.100 MOV - VESSEL NEAD VENTILATION (Q1B21F002-N)

>~

l GRAND GULF-UNIT 1 3/4 8-26 l

l

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 0.100 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 SLC 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 P0OL MAKE-UP VALVE (Q1E30F001A-A) 52-1531-24 12.5 0.100 MOV - DRYWELL COOLER ISOLATION (Q1r44r07C ^' l (Q1P72 rlR5-S)'

52-1531-25 8 0.100 MOV - REACTOR WATER SAMPLE (Q1833F020-A)

GRAND GULF-UNIT 1 3/4 8-29 Arnenalmed No. _. l

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 (NIM 518006A-A) 52-1542-14 5 0.100 MOV - DRWELL COOLER INLET (N1"'4T055-A) l

(# 1 P7tfl15-A) 52-1542-15 5 0.100 MOV - DRYWELL COOLER INLET (N1P4"T05- A) l (N1 P72fill- A) 52-1542-16 5 0.100 MOV - DRWELL COOLER INLET (N1"T050-A) l (NIP 72r131-A) 52-1542-17 5 0.100 MOV - DRWELL COOLER INLET (N1"'4 TOC 1-A) l (t/1P72 F j i 1.A) 52-1542-18 5 0.100 MOV - DRYWELL C,OOLER m,n..rar,_ INLETs l

("iPil'FiO[-Eh 52-1542-19 5 0.100 MOV - DRYWELL COOLER INLET

,u,n..emee_.s l

5;iki&TH "$

52-1542-21 800 0.100 SLCS OPERATING HEATER (NIC41D002) 52-1542-22 24 0.100 DRWL PURGE COMP AUX OIL PUMP (Q1E61C001A-A) 52-1542-23 500 0.100 REFUELING PLATFORM A55Y (Q1F15E003-A) 52-1542-26 175 0.100 DRYWELL RECIRC FAN (N1M51C001-A)

GRAND GULF-UNIT 1 3/4 8-31 Amendment Alo. -

l 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 52-1542-29 1200 0.100 STBY LIQ CONTROL SYS MIXING HEATER (Q1C410003) 52-1611-10 12.5 0.100 MOV - DRYWELL COLL TK OUTLET ISOLATION-(Q1G41F044-B)

<-- Dt W 52-1611-15 12.5 0.100 MOV --96W-CTMT l STM TNL CLR ISOL l

(Q1PT070hf (asp 72FI23~

52-1611-16 50 0.100 MOV-RHR RX ,;0 SPR INBD ISOL (Q1E12F394-B) 52-1611-25 12.5 0.100 MOV - ORYWELL CLG WTR ISOL (Q1P42F117-B) 52-1611-31 12.5 0.100 MOV - DRYWELL CLG WTR INL ISOL (Q1P42F114-B) 52-1611-32 32 0.100 MOV - CTMT CLG WTR ISOLATION (Q1P42F068-B) c ocw l 52-1611-42 12.5 0.100 MOV -P6W- STEAM l TUNNEL CLR ISOL (Q1P"F07' ",) l

, (Q1P72F124-0) l 52-1611-43 12.5 0.100 MOVASW-STEAM l D TUNNEL CLR ISOL l *'

'a'""e^"

l

&{P75I55-5$

52-1611-44 38 0.100 MOV - SERVICE AIR j DRYWELL ISOLATION (Q1P52F195-B)

GRAND GULF-UNIT 1 3/4 8-32 Amendment No._y, l

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 52-1642-10 320 0.100 DRWELL COOLER FAN COIL UNIT .

(N1M51B006B-B) 52-1642-14 12.5 0.100 MOV - DRWELL COOLER INLET (N1P'"r^00 0) l (NJ/272Fl%- B )

52-1642-15 12.5 0.100 MOV - DRWELL COOLER INLET (N1P"'iC00 C' l (N1P/2. Fil7-Bh 52-1642-16 12.5 0.100 MOV - DRWELL COOLER INLET l

-(N1^44iG60-5})

(IVIP 72F/10-0 52-1642-17 12.5 0.100 M0V - DRWELL COOLER INLET (MIP'"r002 C) l (NIP 72Fil -B) 52-1642-18 12.5 0.100 M0V - DRWELL COOLER INLET l I

-(N1Pe4i004 C)

(plP7Z Fic2- 13) 52-1642-19 12.5 0.100 MOV - DRWELL COOLER INLET (N1P44r000 C) l (uip12fl35-a) 52-1642-21 24 0.100 DRWL PURGE COMP AUX OIL PUMP (Q1E61C001B-B) 52-1642-29 175 0.100 DRWL RECIRC FAN (N1M51C002B)

GRAND GULF-UNIT 1 3/4 8-37 h encimeA Mo. l

TABLE 3.8.4.1-1 (Continued)

PRIMARY CONTAINMENT PENETRATION CONOUCTOR 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 52-1P222-27 15 4.0 DRWL. COOLERS SERVICE WATER CONT.

TRANSMITTER (TT - N044) 52-1P251-13 15 4.0 PUMP VALVE SOLEN 0ID CONT. CKT. &

TEMPERATURE FOR REACTOR WATER CLEAN UP SYS.

52-1P252-37 15* 4.0 CONTAINMENT EQUIP.

HATCH (Q1M23Y007-1) 52-1P252-38 15* 4.0 CONTAINMENT EQUIP.

HATCH (Q1M23Y007-2)

Depell C.hillect 4.0 "LmMT SE"J.' ICE I 52-1P411-19 15 WATER SYS. CONTROL VALVE INDICATION

,,m..,,mmm,1 l

($P7[ZLR5N 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-IP412-25 20 4.G UTILITY POWER FOR REMOTE SIGNAL CONDITIONING PANEL l

GRAND GULF-UNIT 1 3/4 8-42 gygg 4, _l t

Dr3 well C W 5 3shem __

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 Q1P44 FOS 3 QiP72F/21 Continuous Plant SW Sy;t:7 4 01P44F050 0 2 P72 f/ 2% Continuous Pl&nt SW Syster 4 Q1P00F075 42P7271%f Continuous -Plant SW Sy;ter 4 Q1P44F070 esp 72pi23 Continuous Plant SW Sy;ter Q1PF074 G2f7Z### Continuous P! nt SY Sy;te-Q1P^

  • F 07 G12 ' [ M%u P 1 = '? '5 'M Q1P44F042 Continuous Plant SW System Q1P44F054 Continuous Plant SW System Q1P44F067 Continuous Plant SW System Q1P45F096 Continuous Floor & Eqmt. Drain System Q1P45F097 Continuous Floor & Eqmt. Drain System Q1PS2F195 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 Centinuous Floor & Eqmt. Drain System GRAND GULF-UNIT 1 3/4 8-53 pmegmerd. No. -
2. (NLS-85/07)

SUBJECT:

Technical Specification 6.10.2.1, page f-20 DISCUSSION:

The subject technical specification requires retention of " Records of Quality Assurance activities required by the Operational Quality Assurance Manual" for the duration of the Unit Operating License. It is proposed to add the words "not listed in Section 6.10.1" to the subject specification.

JUSTIFICATION:

The items specified in Technical Specifications 6.10.1.a. b and d are

" Records of Quality Assurance activities required by the Operational Quality Assurance Manual." Specification 6.10.1 requires a retention period of five (5) years for these items, while 6.10.2 requires that such records be retnined for the duration of the Unit Operating License.

Appendix A to ANSI N45.2.9-1974 requires a retention pericd of five (5) years for the items listed in specifications 6.10.1.a b & d, which indicates that 6.10.1 is the applicable specification for these items.

The proposed change will clarify the technical specifications and preclude the occurrence of misinterpretation or conflicting requirements for these items.

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated because the change involves only a clarification to the technical specifications.

The proposed change does not create the possibility of a new or different kind of accident from any previously evaluated because the change is only a clarification and does not affect plant safety.

The proposed change does not involve a significant reduction in the margin of safety because the change is only administrative in nature and does not affect a margin of safety.

Therefore, the proposed change invoh es no significant hazards considerations.

J14 MISC 85121702 - 1

a ADMINISTRATIVE CONTROLS 6.10 RECORD RETENTION (Continued)

d. Records of surveillance activities, inspections and calibrations required by these Technical Specifications.
e. Records of changes made to the procedures required by Specification 6.8.1.
f. Records of radioactive shipments.
g. 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:

a. Records and drawing changes reflecting unit design modifications made to systems and equipment described in the Final Safety Analysis Report.
b. Records of new and irradiated fuel inventory, fuel transfers and assembly burnup histories.
c. Records of radiation exposure for all individuals entering radiation control areas.
d. Records of gaseous and liquid radioactive material released to the environs.
e. Records of transient or operational cycles for those unit components identified in Table 5.7.1-1.
f. Records of reactor tests and experiments.
g. Records of training and qualification for current members of the unit 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 Manuale listcot in Sec.tiou 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.
m. Records of analyses required by the radiological environmental monitoring program.

GRAND GULF-UNIT 1 6-20 Amenotme,A vo. -

3. (NPE-85/16)

SUBJECT:

Technical Specifications 3.6.5 pages 3/4 6-46, -47.

DISCUSSION: Operating License Condition 2.C. (35), Post-LOCA Vacuum Breaker Position Indicators, states that prior to startup following the first refueling outage, Mississippi Power &

Light (MP&L) shall install position indicators with redundant indication and alarm in the control room for the check valves associated with the Drywell Post-LOCA Vacuum Breakers.

MP&L is now in the process of developing a design change to satisfy the license condition. Technical specification changes are needed to supplement this design change. It is proposed to revise the subject technical specifications by deleting the temporary and 31 day surveillance requirements on the Drywell Post-LOCA Vacuum Breakers.

In support of the proposed technical specification changes, MP&L is providing as an attachment a description of the vacuum breaker position switch design for complying with O.L. condition 2.C.(35).

This design change is scheduled for implementation not later than startup following the first refueling outage. As done on several recent Technical Specification changes involving design changes to the plant, it is requested that the NRC issue the change with an open effective date and require that MP&L notify the NRC within 30 days of the effective date of implementation of the affected technical specification changes.

JUSTIFICATION: Amendment No. 4 to Facility Operating License NPF-13, dated October 14, 1982, added the Operating License condition and technical specification changes associated with this proposed change. The Safety Evaluation associated with Amendment 4 stated that MP&L intended to provide non-contact type position indication switches on the vacuum breaker check valves at a future date.

l On May 24, 1985, in a letter to Mr. Harold R. Denton from Mr. O. D. Kingsley, MP&L described proposed changes to add single proximity type indicator switches (see attached drawing) to the vacuum breaker check valves. Separate position indication for each of the six check valves would be provided in the control room with a single common l

l J14 MISC 85122301 - 1

.. ~,-_ --

annunciator alarm. The redundancy of position indication as required by the license condition would be met (1) between the vacuum relief lines by providing single switches on redundant check valves (i.e., F004 A and F004 B) and (2) within the vacuum relief lines by providing check valve and MOV isolation valve position indication (i.e., F004 A and F005 A) in each line.

In a response from the Nuclear Regulatory Commission (NRC),

dated July 23, 1985, to the above submittal the NRC staff concluded that the design of the position switches for the drywell vacuum breaker check valves was acceptable.

The proposed change will delete the surveillance requirements placed in the Unit I technical specifications by Amendment No. 4 to NPF-13. The proposed change will also delete the 31 day surveillance requirements for the Drywell Post-LOCA vacuum breakers.Section XI of the ASME Bofler and Pressure Vessel Code for inservice pump and valve test procedures provides the rules and requirements for testing to verify operational readiness of valves (and their actuating and position indicating systems) in light-water cooled nuclear power plants.Section XI of the ASME code requires that the valves associated with the Post-LOCA Vacuum Breaker System be exercised at least once every 3 months unless such operation is not practical during plant operation. MP&L has been unable to determine the bases for the present 31 day surveillance interval in the technical specifications, however, MP&L believes that the 3 month test program as stated in Section XI of the ASME code is adequate to ensure safe and reliable valve operation during a postulated LOCA. In order to eliminate the need to revise plant procedures which reference the surveillance requirements of 4.6.5.b, MP&L proposes that the remaining requirements of 4.6.5.b not be renumbered, but that 4.6.5.b.1 be " DELETED."

Action requirements for the post-LOCA vacuum breaker motor operated isolation valves are included in technical specification 3.6.4 for the drywell isolation function.

Present technical specification 3.6.5 contains the surveillance requirements in relation to the drywell post-LOCA vacuum breaker function but does not contain action requirements for these valves. In order to clarify the action statements, the proposed change will add the appropriate actions to be taken if an isolation valve is found to be inoperable. If an isolation valve is l

inoperable, the action statement will require the associated drywell post-LOCA vacuum breaker to be declared inoperable and that the provisions of Action a be followed for an l' inoperable post-LOCA vacuum breaker.

I I J14 MISC 85122301 - 2 i-L

SIGNIFICANT HAZARDS CONSIDERATIONS:

The proposed amendment to the technical specifications results from a design change required to comply with Operating License Condition 2.C.(35). This design change adds position indicators on six check valves used as vacuum relief paths from the containment into the drywell. In addition to position indication, an alarm will be installed in the control room to indicate position movement of the six vacuum breaker check valves to the operators. This design change is conservative in nature in that it adds instrumentation not presently installed in the plant that will aid in ensuring that the vacuum breaker check valves stay in the closed position during normal plant operation.

The present surveillance requirements for the drywell post-LOCA vacuum breakers in specification 3/4.6.5 are augmented by a " Note 1" which applies until restart from the first refueling outage. The " Note 1" requirements were implemented due to the lack of remote position indication on the vacuum breakers, and are no longer needed when the above described design change is implemented. Consistent with commission guidance on applying the three criteria of 10CFR50.92(c), this proposed change would involve no significant hazards consideration. [48 FED. REG. 14864, 14870 (1983)]

The present 31 day surveillance requirement in specification 3/4.6.5 is not reflective of ASME Section XI testing intervals. Operability of the vacuum breakers including position indication is assured by compliance with ASME Section XI testing as implemented in Grand Gulf Surveillance procedures.

The proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated because the addition of position indication and control room alarm for the drywell vacuum breakers is a required improvement to the present design and will aid operators in determining change of position of these valves. The change to the surveillance interval is consistent with ASME Section XI recommendations and will ensure operational readiness of the vacuum breakers.

The proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated because the addition of position indication is a required improvement to present design and does not affect the accident analysis.

J14 MISC 85122301 - 3

The proposed change does not involve a significant reduction in the margin of safety because no margin of safety is affected by this change. The proposed position indication will help assure proper positioning of the vacuum breakers and the proposed surveillances are consistent with ASME Section XI recommendations.

Therefore, the proposed change involves no significant hazards considerations.

J14 MISC 85122301 - 4

CONTAINMENT SYSTEMS 3/4.6.5 DRYWELL POST-LOCA VACUUM BREAKERS LIMITING CONDITION FOR OPERATION 3.6.5 All drywell post-LOCA vacuum breakers shall be OPERABLE and closed.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With one drywell post-LOCA vacuum breaker inoperable for opening but known to be closed, restore the inoperable vacuum breaker to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
b. With one drywell post-LOCA vacuum breaker open, restore the open vacuum breaker to the closed position within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT SHUT-DOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
c. With the position indicator of ac OPERABLE drywell post-LOCA vacuum breaker inoperable, verify the vacuum breaker ic be closed at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by local indication. Otherwise declaic the vacuum breaker inoperable.

(Sec Nctc 1)

SURVEILLANCE REQUIREMENTS 4.6.5 Each drywell post-LOCA vacuum breaker shall be:

a. Verified closed at least once per 7 days.
b. Demonstrated OPERABLE: ~
1. n A ce per 31 days by:

Cycling the va aker and isol ve(s) through Deleted. - a) at least one complete c 1 travel.

Verif

  • position indicator OPERABL ving expected b) ve movement during the cycling test. (See Note
2. At least once per 18 months by:

a) Verifying the pressure differential required to open the vacuum breaker, from the closed position, to be less than or equal to 1.0 psid, and (Sec Netc 1) l b) Verifying the position indicator OPERABLE by performance of a CHANNEL CALIBRATION. (See Nete 1) [

d.. tuitb a. Vatuum breake.r hola.EIo n va.1 v e in operable; ol.ecla.re the. o.ssoc.iole1 d.rpell post - LotA v a.cuum breaker ineperable 0 nd. Sollow the r egulremed:s of ACTIOt/ a above. .

GRAND JULF-l,. 1 3/4 6-46 A rn end.menh MO. - i

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

3. By verifying the OPERABILITY of the vacuum breaker isolation valve differential pressure actuation instrumentation with the opening setpoint of -1.0 to 0.0 psid (Drywell minus Containment) by performance of a:

a) CHANNEL CHECK at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, b) CHANNEL FUNCTIONAL TEST at least once per 31 days, and c) CHANNEL CALIBRATION at least once per 18 months.

s Note 1: Until restart after the first refueling outage, the following uirements shall apply:

3.6.5

c. With the position 'ndicator of an OPERABLE drywell t-LOCA isolation valve for a vacuum b aker inoperable, verify th solation valve to be closed at least once pe 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by local in ~ ation. Otherwise declare the isolation valve inoper le.

4.6.5.b.1

b. Verifying the position indicato or vacuum breaker isolation valve OPERABLE by observing expect valve mov nt during the cycling test.

4.6.5.b.2 At least once per 18 ths by:

a) ifying the pressure differential required to en the vacuum breaker, from the closed position, to be less than equal to 1.0 psid, and b) Verifying the position indicator for the vacuum breaker iso ion valve OPERABLE by performance of a CHANNEL CALIBRATION.

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4

4. (NS-85/02) i

SUBJECT:

Technical Specification 3.12.1.b. page 3/4 12-1 i DISCUSSION: It is proposed to delete the reference to 6.9.1.13.f in the l l

subject technical specification for the Radiological l' Environmental Monitoring Program. Mississippi Power & Light l Company (MP&L) submitted a proposed change to Facility Operating License NPF-13 in a letter to Mr. Harold R. Denton from Mr. J.

P. McCaughy (AECM-84/0319), dated June 22, 1984, deleting Section 6.9.1.13.f on thirty day written reports. The deletion

! of the reference to 6.9.1.13.f in the subject technical specification was inadvertently omitted in the June 22, 1984 submittal.

JUSTIFICATION: Section 6.9.1.13 of the Grand Gulf technical specifications concerning thirty day written reports was deleted in response to Generic Letter 83-43 issued by the NRC on December 19, 1983.

This generic letter provided policy guidance regarding the I

implementation of technical specification changes required as a result of Section 50.73 to 10 CFR 50, " Licensee Event l

Reporting System." By deleting Section 6.9.1.13, MP&L intended

, to delete all references to that section from affected technical

! specifications. However, the deletion of the reference to 6.9.1.13 in technical specification 3.12.1.b was inadvertently missed and should be deleted at this time to provide an administratively correct specification.

SIGNIFICANT HAZARD CONSIDERATION:

The proposed change does not involve a significant increase in the probability or consequences of an accident previously i evaluated because this change is purely administrative in nature and reflects that section 6.9.1.13.f was deleted when Amendment 13 to Facility Operating License NPF-13 was issued, i The proposed change does not create the possibility of a new or '

l different kind of accident from any accident previously

! evaluated because no accident analyses are affected by this l change.

l The proposed change does not involve a significant reduction in

l. the margin of safety because of the purely administrative nature

! of the change.

1 In its guidance on applying the criteria of 10CFR50.92(c), the Commission stated that amendments involving purely i administrative changes, such as to correct an error or to achieve consistency throughout the technical specifications, would not involve significant hazards consideration. [48 FED.

REG. 14864, 14870 (1983)) The proposed change falls into this category and therefore involves no significant hazards consideratica.

I ,

f J13 MISC 85121701 - 1 6

,,,,,,.# .,----.,--v.-,-,.---ww,,,-,--,-,-y__.-,-..-.-,.....---,,.-%.,y-.-..-v-~.,, w.,, y-,, - , . .em _,.,w._,.,. . , . - - - .

3/4.12 RADIOLOGICAL ENVIRONMENTAL MONITORING

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

APPLICABILITY: At all times.

ACTION:

a. With the radiological environmental monitoring program not being conducted as specified in Table 3.12.1-1, prepare and submit to the Commission, in the Annual Radiological Environmental Operating Report 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, m: r-t te Occ '"-

cetic " 6.9.113.' 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) + *> 1.0 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.

c. If milk or broad leaf vegetation sampling is relocated from one or more of the sample locations required by Table 3.12.1-1, identify new locations for obtaining replacement samples and add them to the i radiological environmental monitoring program within 30 days. In addition, report the cause(s) of the unavailability of samples and l the new locations for obtaining replacement samples in the next Semi-

! annual Radioactive Effluent Release Report. Include in this report the revised ODCM figure (s) and table (s) reflecting the new locations.

The specific locations from which samples were unavailable may then be deleted from the radiological environmental monitoring program and the table (s) in the ODCM, provided the locations from which the replace-ment samples were obtained are added to the table (s) as replacement locations.

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

GRAND GULF-UNIT 1 3/4 12-1 bebe^T NO.

l l

5. (NPE-85/13)

SUBJECT:

Technical Specification 3.1.3.1 Action d, Tables 3.3.1-1, ,

4.3.1.1-1 and 2.2.1-1, pages 3/4 1-4, 3/4 3-3, 3/4 3-8,  !

and 2-4. Operating License page 14.

DISCUSSION: The proposed technical specification and operating license changes result from a design change to add diverse and redundant Scram Discharge Volume (SDV) level instrumentation and redundant 'l vent and drain valves.

It is proposed to revise Tables 3.3.1-1 and 4.3.1.1-1 such that the applicable technical specification requirements for the SDV Water Level-High instrumentation apply to the transmitter / trip unit and the float switch separately. It is also proposed to revise Table 2.2.1-1 adding a list of both types of instrumentation to identify individual setpoint requirements.  ;

Operating License Condition 2.C.(41) is proposed to be added to j Facility Operating License NPF-29. This new license condition will provide a one time exception to the provisions of Specification 4.0.4 to allow entry into Operational Conditions 1 and 2 prior to performing Surveillance Requirement

4.1.3.1.4.a for the new scram discharge volume vent and drain I valves. .

I i

This design change is scheduled for implementation not later i than startup following the first refueling outage. As done on

several recent Technical Specification changes involving design changes to the plant, it is requested that the NRC issue the l

change with an open effective date and require that MPLL notify the NRC within 30 days of the effective date of implementatien of the affected technical specification changes.

I l JUSTIFICATION: The proposed design change associated with this technical specification change modifies the SDV design to meet the requirements of the NRC Generic study, "BWR Scram Discharge Volume System Safety Evaluation," of December 1, 1980. This

design change has been required by the NRC for implementation prior to startup following the first scheduled refueling outage

[ Operating License Condition 2.C(15)]. The supporting technical specification change is conservative in nature since it adds requirements not previously incorporated into the technical specifications. The proposed operating license condition is necessary to allow testing of the new scram discharge volume vent and drain valves.

J14 MISC 86011503 - 1

. . ~. _ _ . -. -

The purpose of this design change is to provide diverse redundant level switches (IC11-LSN013A-D) and redundant vent and drain valves (1C11-F180 and IC11-F181) for scram discharge volume isolation. The level switches (IC11-LSN013A-D) are float type switches manufactured by Magnetrol (Model No. 5.0-751) and have an accuracy of + .25 inches. These new switches provide independent trip signals to the reactor protection system in

, addition to the existing analog level transmitters (IC11-LT-N012A-D). Attached to this change is a drawing of the now existing design and a drawing showing placement of the new

system components. This modification will minimize the potential for a common mode failure due to a drain or a vent valve not closing and resulting in an uncontrolled loss of coolant. This change affects the Reactor Protection System Instrumentation i only. The Control Rod Block Instrumentation remains unchanged.

Technical Specification 3/4.1.3.1 presently provides Action Statement and Surveillance Requirements for scram discharge

' volume drain and vent valves. These present requirements are tpplicable to the new vent and drain valves being added by this i design change. Present Action d is written to address only one scram discharge volume vent valve and one drain valve. The change to Action d will ensure that the present valves and the

. added vent and drain valves are equally addressed in the action provisions.

Entry into Operational Conditions 1 or 2 requires the 18 month surveillance requirement be completed on the scram discharge volume as stated in Specification 4.1.3.1.4.a. However, this specification requires a normal control rod configuration of less than or equal to 50% rod density which cannot be achieved without first entering Operational Condition 1 or 2. An exception to the provisions of Specification 4.0.4 for Surveillance Requirement 4.1.3.1.4.a was granted for the present scram discharge volume vent and drain valves by Amendment 10 to l- NPE-13 dated September 23, 1983. This previous one time l exemption required Surveillance Requirement 4.1.3.1.4.a to be performed within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after achieving a normal control rod configuration of less than or equal 50% rod density. MP&L feels

[

that this restriction requiring a reactor scram within 72 hcurs

' of reaching less than or equal to 50% rod density should not be

! imposed for the newly added scram discharge volume vent and drain valyes. The new valves are in series with and located downstream of the present valves. The present valves provide an

operable scram discharge volume and their operability is not affected by the addition of the new valves. Proposed License Condition 2.C.(41) will allow these new drain and vent valves to be tested per Specification 4.1.3.4.a during the first orderly shutdown but no later than the second refueling outage after reaching less than or equal to 50% rod density. Functional

- testing of the new valves will be accomplished as part of the design change package closure and prior to restart after the i first refueling cutage. This functional testing and the

! J14 MISC 86011503 - 2

performance of Specification 4.1.3.4.a as proposed by new License Condition 2.C.(41) will provide adequate assurance that the new vent and drain valves will perform properly as backups to the presently installed vent and drain valves.

Attached to this submittal is an update to the logic diagrams for the reactor protection system instrumentation in Table 3.3.1-1. These logics were originally submitted to the Nuclear Regulatory Commission (NRC) in a letter to Mr. Harold R. Denton from Larry F. Dale dated May 8, 1984 (AECM-84/0093).

SIGNIFICANT HAZARDS CONSIDERATION:

The design change associated with this proposed technical specification change will provide redundant trip signals to the reactor protection system when the scram discharge volume is filled with water. This redundant signal to RPS will help to ensure that the reactor is shutdown before the scram discharge volume is filled to the point that sufficient volume is not available to accept the discharge from the control rod drive.

The addition of the redundant scram discharge volume vent and drain valves in series with the present valves provides additional assurance that the scram discharge volume will isolate on a reactor scram signal.

The proposed license condition allows a one time exception to the provisions of Specification 4.0.4 so that plant conditions necessary to satisfy the intent of Specification 4.1.3.1.4.a can be achieved. The requested exception to Specification 4.0.4 for the new vent and drain valves is similar to the exception granted by Amendment 10 to NPF-13 for the presently installed valves. The new vent and drain valves are backups to the present valves. The present valves are_ operable, perform the isolation function for the scram discharge volume, and do i

not require an exception to the provisions of Specification 4.0.4.

The proposed change does not involve a significant increase in

! the probability or consequences of an accident previously

, evaluated because it is a required improvement that is conservative in nature since it adds requirements not currently listed in the technical speciff /

  • ions. The proposed license condition allows Surveillanet det trement 4.1.3.1.4.a to be performed for the new vert c. 4, in valves at a scheduled plant shutdown thus prevtqting ., 2nnecessary reactor scram.

The present vent and drain valves are operable thus ensuring l- that the isolation function is performed when required. The new vent and drain valves are required improvements added as backups to the present valves. This design change increases the reliability of the reactor protection system and the scram discharge volume isolation function.

J14 MISC 86011503 - 3 3

The proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated because the design change associated with this technical specification change adds redundant reactor protection trip signals and redundant scram discharge volume isolation valves which increases the reliability of these systems.

The proposed change does not involve a significant reduction in the margin of safety because with the addition of redundant level switches and vent and drain valves, the margin of safety is increased. The probability of failures involving loss of coolant from the scram discharge volume is decreased with the addition of redundant vent and drain valves. The probability of receiving a reactor scram signal from high water level in the scram discharge volume is increased with the addition of the redundant level switches. Thus the reliability of the reactor protection system is increased by this design change.

Therefore, the proposed change involves no significant hazards considerations.

J14 MISC 86011503 - 4

(b) Provide the second level undervoltage protection for Division 3 power supply (Item No. 373, T.S. Table 3.3.3-2).

(c) Incorporate a bypass or coincident logic in all Division 1 and 2 diesel generator protective trips, except for trips on diesel engine overspeed and generator differential current (Item No. 808, T.S. 4.8.1.1.2.d.16.d).

(38) Control Room Leak Rate (Section 6.2.6, SSER #6)

MP&L shall operate Grand Gulf Unit I with an allowable control room leak rate not to exceed 590 cfm. Upon restart of construction of Unit 2 control room, MP&L will be permitted to operate at a leak rate of 760 cfm as evaluated in SSER No. 6.

(39) Temporary Secondary Contairment Boundary Change For a period of time not to exceed 144 cumulative hours, the provisions of Specification 3/4.6.6.1 may be applied to the railroad bay area including the exterior railroad bay door on the auxiliary building in lieu of the present secondary containment boundaries that isolate the railroad bay area.

While the railroad bay area is being used as a secondary containment boundary, the railroad bay door may be opened for the purpose of moving trucks in and out provided the four hour limitation in ACTION a of Technical Specification 3.6.6.1 is reduced to one hour. A fire watch shall be established in the railroad bay area while the door is being used as a secondary containment boundary.

(40) Temporary Ultimate Heat Sink Change With the plant in OPERATIONAL condition 4 SSW cooling tower basin A may be considered OPERABLE in accordance with Technical Specification 3.7.1.3 with less than a 30 day supply of water (without makeup) during the time that SSW basin B is drained to replace its associated service water pump provided:

(a) SSW basin A water level is maintained greater than or equal to 87".

(b) At least two sources of water (other than normal makeup with one source not dependent on offsite power) are available for makeup to SSW basin A.

This license condition may remain in effect until plant startup following the outage scheduled for fall 1985.

(40 s e c. an,4) cQ.

J160LM85101101 - 3

Insert to Operating License Page 14 (41) Scram Discharge Volume Test For the scram discharge volume surveillance test required in Section 4.1.3.1.4.a. the provisions of Specification 4.0.4 are suspended provided that the surveillance requirement is performed during the first orderly shutdown but no later than the second refueling outage after reaching less than or equal to 50% rod density in OPERATIONAL CONDITIONS 1 or 2.

This exception applies to the scram discharge volume vent and drain valves added by design change to comply with License Condition 2.C.(15).

J14 MISC 86011503 - 5

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION (Continued)

2. If the inoperable control rod (s) is inserted, within one hour disarm the associated' directional control valves ** either:

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

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

3. The provisions of Specification 3.0.4 are not applicable.
c. With more than 8 control rods inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
d. With h scram discharge volume vent valve and/or M e. scram discharge l volume drain valve inoperable, close the inoperable valve (s) within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, restore the inoperable valve (s) to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least HOT SHUT 00WN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

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

a. At least once per 31 days verifying each valve to be open,* and
b. At least once per 92 days cycling each valve through at least one complete cycle of full travel.

4.1.3.1.2 When above the low power setpoint of the RPCS, all withdrawn control rods not required to have their directional control valves disarmed electrically or hydraulically shall be demonstrated OPERABLE by moving each control rod at least one notch:

I a. At least once per 7 days, and

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

  • These valves may be closed intermittently for testing under administrative l

controls.

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

GRAND GULF-UNIT 1 3/4 1-4 AwM ,or I AO.

, TABLE 3.3.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION E

9 APPLICABLE MINIMUM E OPERATIONAL

{

FUNCTIONAL UNIT CONDITIONS OPERABLE CHANNELS PER TRIP SYSTEM (a) ACTION

9. Scram Discharge Volume Water Level - High '
10. Turbine Stop Valve - Closure 1(h) 4 6
11. Turbine Control Valve Fast Closure, Valve Trip System Oil Pressure - Low i fh) 2 6 w 12. Reactor Mode Switch Shutdown 1 Position 1, 2 2 1 w 3, 4 2 0 5 2 7

3

13. Manual Scram 1, 2 2 1 3, 4 2 8 5 2 9
a. Transmitter / Trip Unit 1 2 1 A 5(8} 2 3
b. Float Switch 1 3 2 1 5 2 3 3

9 s

+

0

a. Transsitter/ Trip (Init S M R b) 1,2,5
b. Float Switch NA M R 1,2,5 c3 TABLE 4.3.1.1-1 (Continued) 5 g REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS

@ CHANNEL OPERATIONAL q CHANNEL FUNCTIONAL CHANNEL CALIBRATION CONDITIONS FOR WHICH SURVEILLANCE REQUlkEO CHECK TEST 4 FUNCTIONAL UNIT

$ 9. Scram Discharge Volume Water

'; M 1, 2, b H Level - High --M-e -

I9)

10. Turbine Stop Valve - Closure 5 M R 1 1
11. Turbine Control Valve Fast Closure Valve Trip System 011 Pressure - Low S M R I9) 1
12. Reactor Mode Switch Shutdown Position NA R NA 1,2,3,4,5
13. Manual Scran NA M NA 1,2,3,4,5 (a) Neutron detectors may be excluded from CHANNEL CALIBRATION.

T (b) The IRM and SRM channels shall be determined to overlap for at least 1/2 decade during each CD startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be deter-mined to overlap for at least 1/2 decade during each controlled shutdown, if not performed

! within the previous 7 days.

(c) [ DELETED]

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

THERMAL POWER. Adjust the APRM channel if the absolute difference is greater tiian 2% of RATED 1 THERMAL POWER. Any APRM channel gain adjustment made in compliance with Specification 3.2.2 shall not be included in determining the absolute difference.

> (e) This calibration shall consist of the adjustment of the APRM flow biased channel to conform to a.

calibrated flow signal.

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

o s (g) Calibrate trip unit at least once per 31 days.

2 D- (h) Verify measured drive flow to be less than or equal to established drive flow at the existing flow con-3 trol valve position.

m (i) This calibration shall consist of verifying the 6 1 1 second simulated thermal power time constant.

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

(k) Not applicable when DRYWELL INTEGRITY is not required.

D D

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

L

e TABLE 2.2.1-1 REACTOR PROTECI!ON SYSTEM INSTRUMENTATION SETPOINTS m

ALLOWABLE E TRIP SETPOINT VALUES c3 FUNCTIONAL UNIT cn

% 1. Intermediate Range Monitor, Neutron Flux-High 1 120/125 divisions i 122/125 divisions of full scale of full scale T

g 2. Average Power Range Monitor:

Q a. Neutron Flux-High, Setdown 1 15% of RATED 5 20% of RATED THERMAL POWER THERMAL POWER g

b. Flow Biased Simulated Thermal Power-High
1) Flow Biased 1 0.66 W+48%, with 1 0.66 W+51%, with a maximum of a maximum of
2) High Flow Clamped i 111.0% of RATED $ 113.0% of RATED THERMAL POWER THERMAL POWER
c. Neutron Flux-High 1 118% of RATED 1 120% of RATED THERMAL POWER THERMAL POWER
d. Inoperative NA NA
3. Reactor Vessel Steam Dome Pressure - High i 1064.7 psig i 1079.7 psig to
4. Reactor Vessel Water Level - Low, Level 3 1 11.4 inches above 1 10.8 inches above a instrument zero" instrument zero"
5. Reactor Vessel Water Level-High, Level 8 1 53.5 inches above 5 54.1 inches above instrument zero* instrument zero"
6. Main Steam Line Isolation Valve - Closure 1 6% closed 5 7% closed
7. Main Steam Line Radiation - High i 3.0 x full power i 3.6 x full power background background
8. Drywell Pressure - High 5 1.23 psig 5 1.43 psig
9. Scram Discharge Volume Water Level - High 1 C^" ef full Kele 1 0 % ef fell Kele
10. ' Turbine Stop Valve - Closure 1 40 psig** 1 37 psig
11. Turbine Control Valve Fast Closure, 3 Trip 011 Pressure - Low 1 44.3 psig** 3 42 psig a

NA

[ 12. Reactor Mode Switch Shutdown Position NA NA NA 3 13. Manual Scram m

h *See Bases Figure B 3/4 3-1.

    • Initial setpoint. Final setpoint to be determined during startup test program. Any s equis ed thange to p this setpoint shall be submitted to the Commission within 90 days of test completion.
a. Transmitter / Trip Unit g 60% of full scale $ 63% of full scale
b. Float Switch 5 64" g 65"

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Attachernt 1 AECM-84/0093 Page 2 DEFINITIONS FOR

" CHANNELS", " TRIP SYSTEMS", AND " TRIP FUNCTIONS" FOR REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE 3.3.1-1 Trip Unit Parameter Logic C51-K601A (3)IRM-Neutron Flux High g IC51-K601E (3)IRM-Neutron Flux High I lC51-K601 A (3)IRM-Inoperative l C51-K601E (3)IRM-Inoperative  ;

IC51-Z405A (3)APRM-Neutron Flux High, Setdown g lC51-2405E (3)APRM-Neutron Flux High, Setdown I

lC51-Z409A APRM-Flow Biased Thermal Power-Hi 3C51-Z409E APRM-Flow Biased Thermal Power-Hi I I

lC51-Z401A APRM-Neutron Flux High lC51-Z401E APRM-Neutron Flux High g lC51-Z401A APRM-Inoperative APRM-Inoperative lC51-Z401E lB21-PIS-N678A *Rx Steam Dome Pressure High l Any "A" Trip Logic l l One .

j _ __ ____ _ _____ J l lB21-LIS-N680A RPV Level 3 I I

'B21-LS-N683A (1)RPV Level 8 '

'B21-ZS-N101A (1)MSIV Closure Either B21-ZS-N102A (1)MSIV Closure J Both-IB21-ZS-N101D l (1)MSIV Closure q I lB21-ZS-N102D (1)MSIV Closure Either lD17-RITS-K610A MSL Radiation High I C71-PIS-N650A Drywell Pressure High l IC11-LIS-N601A SDV Water Level High  ;

lC11-LS-N013A SDV Water Level High I

lC71-PIS-N606A (2)Turb Stop Valve Closure Both-IC71-PIS-N606E (2)Turb Stop Valve Closure d I IC71-PIS-N605A (2)Turb Control Valve Fast Closure ,

IC71-HSS-M602 ** Rx Mode Switch Shutdown i IC71-HS-M600A Manual Scram i l i l__ .- -- -______- --- J (1) This CHANNEL is automatically bypassed when the Reactor Mode Switch is not in the RUN position.

(2) This CHANNEL is automatically bypassed when turbine first stage rressure is less than 30% of the value of turbine first stage pressure at valves wide open steam flow, equivalent to less than 40% rated thermal power.

(3) This CHANNEL is automatically bypassed when the Reactor Mode Switch is in the RUN position.

  • One Channel (Typical of 28 shown on this page) l
    • There is only one Reactor Mode Switch which operates relays in both Trip Systems A and B. The Reactor Mode Switch and its associated contacts constitute one Channel.

Revised as of January 29, 1986 Lisd17

Attechm:nt 1 AECM-84/0093 Page 3 DEFINITIONS FOR

" CHANNELS", " TRIP SYSTEMS", AND " TRIP FUNCTIONS" FOR REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE 3.3.1-1 (Continued)

Trip Unit Parameter Logic p - - - .. . -- --- .

gC51-K601C (3)IRM-Neutron Flux High i IC51-K601G (3)IRM-Neutron Flux High I IC51-K601C (3)IRM-Inoperative '

IC51-K601G (3)IRM-Inoperative '

IC51-Z405C (3)APRM-Neutron Flux High, Setdown l IC51-Z405G (3)APRM-Neutron Flux High, Setdown ,

APRM-Flow Biased Thermal Power-Hi ,

f51-Z409C C51-Z409G APRM-Flow Biased Thermal Power-Hi i IC51-Z401C APRM-Neutron Flux High i IC51-Z401G APRM-Neutron Flux High C51-Z401C APRM-Inoperative '

,'C51-Z401G APRM-Inoperative '

'B21-PIS-N678C Any "C" Trip Logic g

  • RxSteamDomePressureHigh] -----
One, lB21-LIS-N680C RPV Level 3 IB21-LS-N683C (1)RPV Level 8 I lB21-ZS-N101C (1)MSIV Closure Either i I

IB21-ZS-N102C (1)MSIV Closure Both i IB21-ZS-N101B (1)MSIV Closure 1 lB21-ZS-N102B (1)MSIV Closure Either i 017-RITS-K610C MSL Radiation High I C71-PIS-N650C Drywell Pressure High l

,C11-LIS-N601C SDV Water Level High l I  !

C11-LS-N013C SDV Water Level High I I

C71-PIS-N606C (2)Turb Stop Valve Closure Both I lC71-PIS-N606G (2)Turb Stop Valve Closure d l gC71-PIS-N605C (2)Turb Control Valve Fast Closure i

,C71-HSS-M602 **Rx Mode Switch Shutdown I l :C71-HS-M600C Manual Scram _ i i l I .... _.- - -_.- ..-- - J (1) This CHANNEL is automatically bypassed when the Reactor Mode Switch is not in the RUN position.

(2) This CHANNEL is automatically bypassed when turbine first stage pressure is less than 30% of the value of turbine first stage pressure at valves wide open steam flow, equivalent to less than 40% rated thermal power.

(3) This CHANNEL is automatically bypassed when the Reactor Mode Switch is in the RUN position.

  • One Channel (Typical of 28 shown on this page) l
    • There is only one Reactor Mode Switch which operates relays in both Trip Systems A and B. The Reactor Mode Switch and its associated contacts constitute one Channel.

l Revised as of January 29, 1986 Lisdl8

Attachment 1 AECM-84/0093 Page 4 DEFINITIONS FOR

" CHANNELS", " TRIP SYSTEMS", AND " TRIP FUNCTIONS" FOR REACTOR PROTECTION SYSTEM INSTR 1' MENTATION TABLE 3.3.1-1 (Continued)

Trip Unit Parameter Logic r 1 C51-K601B (3)IRM-Neutron Flux High  ;

IC51-K601F (3)IRM-Neutron Flux High g IC51-K601B (3)IRM-Inoperative g 51-K601F (3)IRM-Inoperative 51-Z405B (3)APRM-Neutron Flux High, Setdown I 51-Z405F (3)APRM-Neutron Flux High, Setdown l IC51-Z409B APRM-Flow Biased Thermal Pcwer-Hi l lC51-Z409F APRM-Flow Biased Thermal Power-Hi l lC51-Z401B APRM-Neutron Flux High l

,C51-Z401F APRM-Neutron Flux High g t51-Z401B APRM-Inoperative I

IC51-2401F APRM-Inoperative l_ - - l y

lB21-PIS-N678B *Rx Steam dome pressure highl Any "B" Trip Logic p J %e B21-LIS-N680B RPV Level 3 I

h21-LS-N683B (1)RPV Level 8 IB21-ZS-N101A (1)MSIV Closure Either  !

IB21-ZS-N102A (1)MSIV Closure Both l IB21-ZS-N101B (1)MSIV Closure  ; ,

lB21-ZS-N102B (1)MSIV Closure Either  ;

lD17-RITS-K610B MSL Radiation High ,

lC71-PIS-N650B Drywell Pressure High SDV Water Level High I lC11-LIS-N601B lC11-LS-N013B SDV Water Level High l lC71-PIS-N606B (2)Turb Stop Valve Closure  ;

Both I gC71-PIS-N606F (2)Turb Stop Valve Closure l lC71-PIS-N605B (2)Turb Control Valve Fcst Closure g C71-HSS-M602 ** Rx Mode Switch Shutdown IC71-HS-M600B Manual Scram '

s I L____ _____ _- _____--- --- J (1) This CHANNEL is automatically bypassed when the Reactor Mode Switch is not in the RUN position.

(2) This CHANNEL is automatically bypassed when turbine first stage pressure is less than 30% of the value of turbine first stage pressure at valves wide open steam flow, equivalent to less than 40% rated thermal power.

(3) This CHANNEL is automatically bypassed when the Reactor Mode Switch is in the RUN position.

  • One Channel (Typical of 28 shown on this page) l
    • There is only one Reactor Mode Switch which operates relays in both trip systems A and B. The Reactor Mode Switch and its associated contacts constitute one Channel.

Revised as of January 29, 1986 Lisd19

Attachment 1 AECM-84/0093 Page 5 DEFINITIONS FOR

" CHANNELS", " TRIP SYSTEMS", AND " TRIP FUNCTIONS" FOR REACTOR PROTECTION SYSTEM INSTRUMENTATION TABLE 3.3.1-1 (Continued)

Trip Unit Parameter Logic

-__------ q

'C51-K601D (3)IRM-Neutron Flux High -

i lC51-K601H (3)IRM-Neutron Flux High e iC51-K601D (3)IRM-Inoperative l IC51-K601H (3)IRM-Inoperative 1 C51-Z405D (3)APRM-Neutron Flux High, Setdown ,

lC51-Z405H (3)APRM-Neutron Flux High, Setdown ,

,C51-Z409D i APRM-Flow Biesed Thermal Power-Hi e IC51-Z409H APRM-Flow Einsed Thermal Power-Hi i IC51-Z401D APRM-Neutron Flux High I APRM-Neutron Flux High l lC51-Z401H lC51-Z401D APRM-Inoperative g IC51-Z401H APRM-Inoperative l l__-- ----- - . _ .

-- , g lB21-PIS-N678D *Rx Steam Dome Pressure Highi Any "D" Trip Logic

,_-_. - _--___----___--_ a One IB21-LIS-N680D RPV Level 3 lB21-LS-N683D (1)RPV Level 8 l lB21-ZS-N101D (1)MSIV Closure Either ,

IB21-ZS-N102D (1)MSIV Closure d Both- I jB21-ZS-N101C (1)MSIV Closure q l B21-ZS-N102C (1)MSIV Closure Either i lD17-RITS-K610D MSL Radiation High I

lC71-PIS-N650D Drywell Pressure High ,

C11-LIS-N601D SDV Water Level High 3,C11 LS N013D SDV Water Level High I i

C71-PIS-N606D (2)Turb Stop Valve Closure Both- 1 IC71-PIS-N606H (2)Turb Stop Valve Closure J l lC71-PIS-N605D (2)Turb Control Valve Fast Closure 1 C71-HSS-M602 **Rx Mede Switch Shutdown i .

C71-HS-M600D Manual Scram -- I l--- -__ _ .. _ _ _ -__ -. --- -J The TRIP FUNCTION for Reactor Protection System logics on pages 2 through *5 is shown below.

Trip Logic Logic Trip System Logic Trip Function "A" Trip Logic Either One De-energizes scram-

"C" Trip Logic d pilot solenoids in TRIP SYSTEM A Both REACTOR SCRAM "B" Trip Logic Either One De-energizes scram-

"D" Trip Logic d pilot solenoids in TRIP SYSTEM B -

(1) This CHANNEL is automatically bypassed when the Reactor Mode Sw!tch is not in the RUN position.

(2) This CHANNEL is automatically bypassed when turbine first stage pressure is less than 30% of the value of turbine first stage pressure at valves wide open steam flow, equivalent to less than 40% rated thermal power.

(3) This CHANNEL is automatically bypassed when the Reactor Mode Switch is in the RUN position.

  • One Channel (Typical of 28 shown on this page) l
    • There is only one Reactor Mode Switch which operates relays in both trip systems A and B. The Reactor Mode Switch and ita associated contacts constitute one Channel.

Lisd20 Revised ns of January 29, 1986

6. (NLS-85/16)

SUBJECT:

Technical Specification Tables 3.3.3-1 and 4.3.3.1-1, pages 3/4 3-29 and 3/4 3-36.

DESCRIPTION The proposed change modifies the ## note of the subject tables OF CHANCE: by deleting the phrase " Prior to STARTUP following the first refueling outage." The deletion of this phrase from the ##

note to the two tables retains the requirements through the first refueling outage and extends the requirements to be applicable for subsequent plant operations. The notes modify the technical specifications on the High Pressure Core Spray (HPCS) system actuation instrumentation such that the injection function of Drywell Pressure-High and Manual Initiation are not required to be OPERABLE when the indicated water level on the wide range instrument is greater than Level 8 coincident with the reactor pressure being less than 600 psig.

DISCUSSION: The primary purpose of the HPCS is to maintain reactor vessel inventory in the event of small pipe breaks (1 inch nominal diameter or smaller) which do not depressurize the reactor vessel. HPCS also provides spray cooling heat transfer during breaks in which the core is calculated to uncover. If a loss-of-coolant accident should occur, a low reactor vessel water level signal or a high drywell pressure signal initiates the HPCS and its support equipment. The system can also be placed in operation manually.

With a high reactor vessel water level interlock (Level 8) actuated, the HPCS is automatically stopped by a signal to the injection valve to close. This prevents undesirable spillover of water into the main steamlines. HPCS operation is thus terminated until the low water level initiation setpoint is reached or the isolation logic is manually reset once the Level 8 interlock clears.

Reactor vessel water level is monitored by level transmitters that sense the difference between the pressure due to a constant reference leg of water and the pressure due to the actual height of water in the vessel. The instrumentation is the condensate chamber reference leg type (See Figure 1.) These instruments are strictly differential pressure devices which are reactor coolant density sensitive and are calibrated to be most accurate at the specific vessel conditions appropriate for the associated system functions actuated by the instrumentation.

The shutdown water level range and fuel zone water level range instruments are calibrated to read accurately at atmospheric pressure; the upset, narrow, and wide range water level instruments are calibrated for normal operating conditions (saturated steam at 1025 psig.) Figures 2 and 3 depict the level ranges and setpoints. At low coolant temperatures and pressures, those instruments calibrated for normal operating conditions will read higher than actual level.

J16ATTC85110601 - 1

The HPCS discharge valve is interlocked closed at the vessel Level 8 setpoint (setpoint less than or equal to 53.5" above instrument zero or 220" above the active fuel.) An artificially high level indication at low pressure may result in HPCS isolation when the actual vessel level is below the Level 8 setpoint. The isolation logic may be manually reset once the indicated vessel level drops below this setpoint or it will reset automatically when the indicated vessel level reaches the Level 2 HPCS initiation setpoint (a level of -41.6" below instrument zero or 125" above the fuel.)

Technical Specification Table 3.3.3-1. requires HPCS Drywell Pressure-High and Manual Initiation Actuation Instrumentation to be OPERABLE in various Operational Conditions. Actuation of these devices will result in vessel injection unless reactor vessel level is above the Level 8 setpoint or the Level 8 isolation has not been reset. The ## notes to Technical Specification Tables 3.3.3-1 and 4.3.3.1-1 state that the.

injection function of Drywell Pressure-High and Manual Initiation are not required to be OPERABLE at times when the indicated Level 8 isolation signal is present coincident with the reactor pressure at or below 600 psig.

Deletion of the phrase " Prior to STARTUP following the first refueling outage" modifies the ## notes such that the requirements remain applicable through the first refueling outage and are extended throughout subsequent plant operations.

By imposing the requirements on subsequent plant operations, design modifications and concomitant potential problems are negated.- The notes were initially added to Technical Specifications Tables 3.3.3-1 and 4.3.3.1-1 to address a concern with respect to the reactor vessel level instrumentation. The requirements were imposed through the first refueling outage which allowed adequate time to consider the necessity for a design modification. A design modification has been determined to be unnecessary because the requirements as currently imposed are considered adequate to ensure the continued safe operation

of the plant. The following is a discussion of the reactor

. water level instrumentation and concern, which prompted the

l. imposition of the requirements, to indicate that the concern has l

been properly addressed, a redesign is not required, and the subject change to the ## notes is justified.

JUSTIFICATION: MASS OF COOLANT: The wide range level instrumentation measures the mass of coolant above the lower instrument tap and displays this as level. Since the instrument is not compensated for changes in water density, the interlocks occur with the same mass of coolant in the vessel regardless of the pressure or actual water level. That is to say, mass is the variable that is being indicated by level and for a specific indicated level the mass is the same regardless of pressure. Because the mass of coolant is the same at the time of HPCS initiation, the system response to a loss of coolant event at low pressure is essentially the same as that previously analyzed under normal J16ATTC85110601 - 2

operating pressure (1025 psig), and those analyses are applicable to the low pressure condition. Mass, not density nor indicated level, is the true measure of the amount o' coolant available for an event.

ACCIDENT ANALYSIS: Only one ECCS accident analysis previously presented in the FSAR assumed HPCS initiation by a high dryeell pressure signal - a steamline break inside the containment.

This event was reanalyzed with the premise that the high drywell initiation feature is defeated and HPCS is initiated only by low water level (Level 2). For this event with the worst single failure (LPCS diesel generator failure), the peak cladding temperature (PCT) was calculated to be 1322*F, which is significantly below the criteria of 2200*F as given in 10 CFR 50.46. Thus, initiation of HPCS only by low water level, and not by a high drywell pressure signal, is not a significant safety concern. The results of the re-analysis are attached and include copies of Figures 6.3-8, and 6.3-63 through 6.3-66 from the recently updated FSAR.

LEVEL TRIP IMPACT: When the vessel is at low pressure, the Level 2 trip will occur approximately I foot below the allowable Level 2 limit. This is not a safety concern because the mass of coolant available for boil off during a loss of inventory event (either transient or LOCA) is the same as if the vessel was at normal operating conditions.

The wide range Level I trip for ECCS is unaffected because the density compensation error is negligible at this low water level.

With the vessel at low pressure, the level 8 interlock will occur with actual water level lower than with the reactor hot and at high pressure; thus, for the purpose of preventing vessel overfill, the actuation of the interlock will be in the conservative direction and there is no safety concern.

With the reactor cold and actual water level at the normal level (between Level 4 - 32.7" and Level 7 - 40.7"), the Level 8 interlock will occur due to the artificial high level indication. This is not a safety concern since no water addition is needed until the water level drops to Level 2.

Further, with the actual icvel at Level 7, reset of the Level 8 interlock will occur at approximately 600 psig (MP&L letter to NRC dated September 13, 1983 - AECM-83/0557.)

LOW PRESSURE EFFECTS: With the vessel at low pressure, the plant is normally at reduced power. Also, at low pressure and saturated conditions, the energy required to boil water is greater than at high pressure and saturated conditions. Both of these effects reduce the boil-off rate of the coolant when compared to that of the safety analyses for high pressure.

J16ATTC85110601 - 3

I 4 For LOCA events, the coolant loss out of a break is less at low pressure conditions; and, low pressure ECCS injection occurs earlier as a result of the initial low pressure. Also, a number of systems other than HPCS would be more responsive to the mitigation of accidents.

Based on consideration of the above effects, the safety analyses performed at full power conditions are bounding for low vessel pressure conditions and even though the wide range water level instrumentation is not calibrated for low pressure conditions, this does not present a safety concern.

SIGNIFICANT HAZARD CONSIDERATION:

The proposed amendment does not:

1) involve a significant increase in the probability or consequences of an accident previously evaluated because the only accident analysis affected by this change is the steam line break inside the containment which was re-analyzed to show the effect of not having high drywell pressure to initiate HPCS. This event was selected because it was the only event previously in the Grand Gulf FSAR ECCS analysis which took credit for ECCS initiation 2

on high drywell pressure. Assuming ECCS initiation on low water level and not on high drywell pressure, the LPCS D/G was found to be the most limiting failure resulting in a delay in both injection and core reflooding, and an increase of about 400*F in the calculated PCT for this event. However, since the calculated increase in the PCT is only to 1322*F there is substantial margin to the 2200*F criteria of 10 CFR 50.46,

2) create the possibility of a new or different kind of accident from any accident previously evaluated because initiation of HPCS on low reactor water level (masr of coolant equivalent to Level 2) will occur as assumed in the present accident analysis and is not affected by this change. Since initiation of HPCS on low reactor water level is not adversely affected by this change, no new or different kind of accident from those previausly analyzed are postulated to occur. The affect of not having HPCS initiate on high drywell pressure has been re-analyzed and shown to increase PCT to 1322*F which is well below the criteria of 10 CFR 50.46.
3) involve a significant reduction in a margin of safety; because, no margin of safety is affected. The only margin of safety involved is that associated with the peak cladding temperature. The criterion of 2200*F as given in 10 CFR 50.46 is met, and met with significant conservatiam since the calculated increase in the PCT is only to 1322*F.

These changes make the existing requirements permanent and do not constitute a significant hazard consideration.

J16ATTC85110601 - 4

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LOCA ANALYSIS OF MAX 1 MUM STEAMLINE BREAK INSIDE CONTAINMENT BASED UPON LOW WATER LEVEL INITIATION An ECCS performance evaluation was performed for Grand Gulf to determine the effect of not taking credit for ECCS initiation on high drywell pressure for a steamline break inside the containment. This assumption results in a substantial delay in the time of ECCS injections for large steamline breaks because the rapid depressurization rate initially causes a level swell. The results of this study show that the delay in ECCS injection for this event causes an increase in calculated peak cladding temperature (PCT) of about 400*F. However, this is not the limiting event in the Grand Gulf FSAR, and there is still sufficient margin to absorb this increase and remain within the 2200*F PCT limit.

The design basis accident (DBA) steamline break inside the containment was analyzed to determine the effect of starting the ECC systems on low water level only. This event was selected because it was the only event previously in the Grand Gulf FSAR ECCS analysis which took credit for ECCS initiation on high drywell pressure.

For the previous case, the LPCI diesel generator (D/G) was the limiting failure with a calculated PCT of 934*F. The HPCS, LPCS and 1 LPCI systems were assumed to begin injecting at 27, 40 and 40 seconds respectively.

For the case with ECCS initiation on low water level, the LPCS D/G was found to be the most limiting failure with a calculated PCT of 1322*F. The HPCS and 2 LPCI systems begin injecting at 47 and 96 seconds respectively.

Assuming ECCS initiation on low water level results in a delay in both injection and core reflooding, and an increase of about 400*F in the calculated peak cladding temperature for this event. However, since the calculated increase in PCT is only to 1322*F, there is sufficient margin to the 2200*F limit. With these results, the Grand Gulf ECCS performance analysis conclusions are clearly not affected by the ability of the ECC systems to initiate on high dryvell pressure.

To document the effect on the LOCA analysis of this change in ECCS initiation assumptions, copies of FSAR Figures 6.3-8, and 6.3-63 through 6.3-66 are attached. These figures show the PCT versus break area, and the convective heat transfer coefficient, water level, pressure and peak cladding temperature response to this event. Appropriate FSAR updates will be made to reflect the above assumption in the discussion for the main steamline break event.

J14 MISC 85122002 - 1

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E TA8LE 3.3.3-1 (Continued)

C3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION cs

% MINIMUM OPERABLE APPLICABLE T CHANNELS PER OPERATIONAL TRIP FUNCTION TRIP FUNCTION (,)

CONDITIONS ACTION

  • C. DIVISION 3 TRIP SYSTEM -
1. HPCS SYSTEM
a. Reactor Vessel Water Level - Low, Low, Level 2 4 1, 2, 3, 4* , 5" 33
b. Drywell Pressure - High## 4 1, 2, 3 33
c. Reactor Vessel Water Level-High, Level 8 g) 2 1, 2, 3, 4*, 5* 31
d. Condensate Storage Tank Level-Low 2 )

g) 1, 2, 3, 4*, 5" 34

e. Suppression Pool Water Level-High 2 1,2,3,4*,5* 34
f. Manual Initiation ## 1 1, 2, 3, 4*, 5* 32
0. LOSS OF POWER
1. Division 1 and 2
a. 4.16 kV Bus Undervoltage 4 1, 2, 3, 4**, 5** 30 R

(Loss of Voltage)

b. 4.16 kV Bus Undervoltage '4 1, 2, 3, 4**, 5**

ca 30 (80P Load Shed)

A

c. 4.16 kV Bus Undervoltage 4 1, 2, 3, 4**, 5** 30 (Degraded Voltage)
2. Division 3
a. 4.16 kV Bus Undervoltage 4 1, 2, 3, 4**, 5** 30 (Loss of Voltage) y (a) A channel may be placed in an inoperable status for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> during periods of required surveillance 3 without placing the trip system in the tripped condition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.

% (b) Ai o actuates the associated division diesel generator.

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

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

3

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

G **

Required when applicable ESF equipment is required to be OPERABLE.

3 5

  • Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 135 psig. l
    1. Pri;r t; ST'eiUP fcils-ing the first refact ng cut ;:, The injection function of Drywell Pressure -

E High and Manual Initiation are not required to be OPERABLE with indicated reactor vessel water level l

?

on the wide range instrument greater than Level 8 setpoint coincident with the reactor pressme less than 600 psig.

e TABLE 4.3.3.1-1 (Continued)

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS NOTATION

  1. Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 135 psig.
    1. "-ice te STf9 TUP fc110 win 7 the first refueling cutage,'I'he injection func- l tion of Drywell Pressure tigh and Manual Initiation 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-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 mtnths 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 Testing of Time Delay Not Required 1

i 1

GRAND GULF-UNIT 1 3/4 3-36 /% ni e n o n, e n e No.