Text

Proposed Changes to Tech Specs Re Plant Design & Operation
	ML20076G854
Person / Time
Site:	Grand Gulf
Issue date:	06/14/1983
From:	; MISSISSIPPI POWER & LIGHT CO.
To:	;
Shared Package
ML20076G851	List: AECM-83-0338, Application to Amend License NPF-13,clarifying & Providing Consistency W/Plant Design & Operation; ML20076G854;
References
	NUDOCS 8306160274
	Download: ML20076G854 (46)
	v • d • e

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TRANSMITTAL OF PROPOSED CHANGES TO GRAND GULF TECHNICAL SPECIFICATIONS

1. (GGNS - 159)

SUBJECT:

Technical Specification'3.2.2 and Table 4.3.1.1-1, pages 3/4 2-5 and 3/4 3-8.

DISCUSSION: Technical Specification 3.2.2 specifies an'APRM flow biased simulated thermal power high scram trip setpoint (S) and a flow-biased neutron flux-upscale control red block trip setpoint (SRB) as follows:

S less than or equal to (0.66W + 48%) T S ess than or equal to (0. W + 420 T RB Where: S and.S 8r in percent of RATED THERMAL POWER.

RB W = Loop recirculation flow as a percentage of the loop recirculation flow which produces a rated core flow of 112.5 million Ibs/hr.

T = Lowest value of the ratio of FRACTION OF RATED THERMAL POWER (FRTP) divided by the MAXIMUM FRACTION OF LIMITING POWER DENSITY (MFLPD). T is always less than or equal to 1.0.

These setpoints are applicable in OPERATIONAL CONDITION 1 when thermal power is greater than or equal to 25% of rated. With a setpoint less conservative than those specified in 3.2.2, the corresponding ACTION statement requires initiation of corrective action within 15 minutes and to restore S and/or

., S t w n required Hmits witMn 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be at RB less than 25% power within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Allowable values for these trip setpoints are not specified in 3.2.2 but are specified in Table 2.2.2-1 for the scram trip (0.66W + 51%) and in Table 3.3.6-2 for the rod block trip (0.66W + 45%). It is possible to be outside the setpoint specified in 3.2.2 and still be within allowable values for these setpoints as specified in Table 2.2.2-1 and Table 3.3.6-2. An Instrumentation and Controls Technician could find an APRM scram setpoint of (.66W + 50%) which is within the allowable value of (.66W + 51%) on Table 2.2.2-1 and not realize that he has only 15 minutes to initiate corrective action per Specification 3.2.2 (assuming S and/or S RB ss conservative than setpoint). The proposed solution adds the allowable values of Tables 2.2.2-1 and Table 3.3.6-2 to the associated setpoints in Specification 3.2.2. (See attached proposed revisions to Specification 3.2.2.)

8306160274 830614 PDR ADDCK 05000416 P PDR 1F(TS Dump)

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-The last sentence of note (d) on Table 4.3.1.1-1 states:

"Any APRM channel gain adjustment made'in compliance with

-. Specification 3.2.2 shall not be included in determining

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the absolute difference."-

This part of: note-(d) can be confusing and should be changed to further separate.the requirements of Specification 3.2.2 and~

'C the above note. Specification 3.2.2 states limits for APRM gain adjustments, but does'not.specify tolerances on the gain adjustment'within the . limits (i.e. ,L APRM readings ~can be set up to 10%f higher than actual power, but there is no-tolerance on

'the : setting as long as the 10% boundary -(and 100% power) .is not violated). .The confusion between Specification 3.2.2 and note

(d) on Table 4.3.1.1-1: exists because the tolerance for adjusting the APRM setpoint from Table 4.3.1.1-1 is not the same as the APRM gain adjustment boundaries in 3.2.2., Note (d) on Table 4.3.1.1-1 should be' changed to exclude adjusting the APRM channel if an APRM channel-gain adjustment has been made to comply with 3.2.2.

JUSTIFICATION: This change will make Specification 3.2.2 consistent with the

. Allowable Values specified in Tables 2.2.2-1 and 3.3.6-2 for

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the APRM flow biased simulated thermal power-high scram trip setpoint and flow biased neutron flux-upscale control rod block

-trip setpoint. The change to Table 4.3.1.1-1 note (d) will separate the APRM channel adjustment criteria from the APRM gain adjustments specified in 3.2.2.

SIGNIFICANT HAZARDS CONSIDERATION:

'The change is a purely administrative change proposed to achieve consistency throughout the Technical Specifications

, with regard to the allowable values specified for the APRM flow biased simulated thermal power-high scram trip setpoint and flow' biased neutron flux-upscale control rod' block trip setpoint. -In addition a clarification of the -Technical Specification has been added in regard to the adjustment of the gain of the APRM channel. Therefore, based upon NRC example, 3'(1) (10CFR50, Interim Final Rule, Federal Register, April 6,

_ 1983) the proposed change-involves no significant hazards.

considerations.

NOTE: Technical Specification page changes marked with a PCOL number-and circled are changes that were previously submitted to the NRC.

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' 1.p1.(GGNS -157)

POWER DISTRIBUTION LIMITS

3/4.2.2 APRM SETPOINTS LIMITING CONDITION FOR OPERATION .

3.2.2 The APRM flow biased simulated thermal power-high scram trip setpoint (S) and flow biased neutron flux-upscale control rod block trip setpoint (Sgg) shall be established according to the following gagsggggy relationships:yggyg TREP SET 96EC S 1 (0.66W + 48%)T .51 (0.M W + 51 f.) T S

RB i (0.66W + 42%)T Sun (8 MW + VfA}T where: S and S RB are in percent of RATED THERMAL POWER.

W = Loop recirculation flow as a percentage of the loop recirculation flow which produces a rated core flow of 112.5 million Ibs/hr.

T = Lowest value of the ratio of FRACTION OF RATED THERMAL POWER (FRTP) divided by the MAXIMUM FRACTION OF LIMITING POWER DENSITY (MFLPD). T is always less than or equal to 1.0.

APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or l

equal to 25% of RATED THERMAL POWER.

, ACTION:

Ag AllowAN8 YdI#d ulated thermal power-high scram trip setpoint and/

With the APRM flow biase ortheflowbiasedfneutronflux-upscalecontrolrodblocktripsetpointless as above determined, initiate corrective action l conservative thanFS or S within15minutesandreNo,reSand/ ors.,towithintherequired_ limits *within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less Han 25% of RATED THERMA the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.2 The FRTP AND MFLPD for each class of fuel shall be determined, the value of T calculated, and the most recent actual APRM flow biased simulated thermal j

' power-high scram and flow biased neutron flux-upscale control rod block trip setpoints verified to be within the above limits or adjusted, as required:

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

b. Within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after completion of a THERMAL POWER increase of at l

least 15% of RATED THERMAL POWER, and

c. Initially and at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the reactor is operating with MFLPD greater than or equal to FRTP.

' "With MFLPD greater than the FRTP during power ascension up to 90% of RATED THERMAL POWER, rather than adjusting the APRM setpoints, the APRM gain may be adjusted such that APRM readings are greater than or equal to 100% times MFLP provided that the adjusted APRM reading does not exceed 100% of RATED THE P0WER, the required gain adjustment increment does not exceed 10% of RATED THERMAL POWER and a notice of adjustment is posted on the reactor control pane GRAND GULF-UNIT 1 3/4 2-5

TA8LE 4.3.1.1-1 (Continued)

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REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL i E CONDITIONS FOR WHICH 1 9 CHANNEL FUNCTIONAL CHANNEL CALIBRATION SURVEILLANCE REQUIRED e FUNCTIONAL UNIT CHECK TEST

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5 9. Scram Discharge Volume Water R I9) l 1, 2, 5 Level - High S M

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10. Turbine Stop Valve - Closure S M R IE) 1

! 11. Turbine Control Valve Fast Closure Valve Trip System 011 gg) l Pressure - Low S M R 1

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

13. Manual Scram NA' M NA 1,2,3,4,5 4re T

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! (a) Neutron detectors may be excluded from CHANNEL CALIBRATION. p (b) The IRM and SRM channels shall be determined.to overlap for at least 1/2 decade during each l

startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be deter- x mined to overlap for at least 1/2 decade during each controlled shutdown, if not performed u

! 8

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

(d) This calibration shall consist of the adjustment of the APRM channel to conform to the power values v

calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER > 25% of RATED THERMAL POWER. Adjust the APRM channel if the absolute difference is greater than 2% of RATED THERMAL POWERg ".ny ^^^" ch::::1 g:f dj::t.::t r:d: in :1-;11 ::: with 4 :!fiesti:: 2.2.2

h:11 ::t b: 1 ct ics in det: :::! ! g tk :t;:::t: sific:::::.

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

(f) The LPRMS shall be calibrated at least once per 1000 effective full power hours (EFPH) using the TIP system. V< ca y <we. w<.d c ore W o A, w Ic e, N a or (g) Calibrate trip unit at least once per 31 days. */'d b '"AW sM c <'re (1 d N ev. ,1:..tg e (h) " ri#y =:::::d ::r: '?r te h gre:ter 15 - or --"-! te re*d ce-- *!-".JL...Co.'I< l v.he e< A. .i. O e (i) This calibration shall consist of verifying the 6 i 1 second simulated thermal power time constant.

Hess an Arnh ch ,,,,al Gs 1,ea n ~ Ja ra, ca,m ly w.71. Spa,'J,'c2len 3. 2.2. . y;, ,3;s,7~a T ,

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=2. (GGNSI-'488a)

SUBJECT:

Technical Specification Table 3.3.2-2, page 3/4 3-16, 3/4 3-17.

DISCUSSION: Technical Specification . Table 3.3.2-2 specifies setpoints and allowable values for isolation actuation instrumentation. The following setpoints and/or allowable values should be changed as indicated.

Item Instrument- Trip Setpoint Allowable Value

$ '4.a RWCU Sys. -Isolation Flow-High .

as is gg89 gpm$Iik~

5.a RCIC Steam Line Flow - High 2[363" H 2O sG371" H O 5.k RHR/RCIC Steam-Line Flow - High

as is gE160" H 2O

- 2

as is - Present Technical Specification value is correct.

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' JUSTIFICATION: The changes-to the above Trip Setpoints reflect current General

' Electric design specification values and do not affect established transient analyses. General Electric has reviewed the proposed changes and concurs with the new values.

LSIGNIFICANT HAZARDS CONSIDERATION:

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The proposed amendment to this Technical Specification changes

- trip setpoints and allowable values for identified Isolation Actuation Instrumentation to reflect actual General Electric

[ , design' specification ~ values. As these changes do not affect the established transient analysis, the amendment is a purely 4

' administrative change to correct the Technical Specification.

!This changes does not cause a significant increase in the

i. ,

probability or consequences of an accident previously evaluated

nor does-it create the. possibility of a new or different kind of accident from any accident previously evaluated. This changes does not represent a significant reduction in the

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margin of safety. Therefore, based upon NRC example, 3 (i) (10

. CFR 50. Interim Final Rule, Federal' Register, April 6, 1983),

amendments considered not likely to involve significant hazards considerations, the proposed amendment involves no significant hazards considerations.

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a4 TABLE 3.3.2-2 (Continued)

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ISOLATION ACTUATION INSTRUMENTATION SETPOINTS j

l o ALLOWA8LE E VALUE -

TRIP SETPOINT l

7 c

TRIP FUllCTION W-K g 1

4. REACTOR WATER CLEANUP SYSTEM ISOLATION 5 49 gpa l

% 1 79 gpa w a. A Flow - High 1 45 seconds 1 57 seconds

b. A Flow Timer

c. Equipment Area Temperature - High < 124*F < 130*F

1. RWCU Hx Room 5180*F

2. RWCU Pump Rooms 5174*F < 145'F

< 139'F

3. RWCU Valve Nest Rooms 7 139'F 7 145'F '

4. RWCU Demin. Rooms 5145'F

5. RWCU Rec. Tank Roon 5139"F w d. Equipment Area a Temp. - High < 65'F < 66*F 5 1. RWCU Hx Room 7 110*F 7 113*F w 2. RWCU Pump Rooms 7 70*F 7 73*F 0 3. RWCU Valve Nest Rooms 7 70*F 7 73*F

4. RWCU Demin Rooms 570*F 573*F

5. RWCU Rec. Tank Room 2,-43.8 inches

e. Reactor Vessel Water Level - Low Low, Level 2 1 -41.6 inches

Main Steam Line Tunnel Ambient Temperature - High 5 179'F** 1 185'F**

T.

5 75'F** 1 78'F**

g. Main Steam Line Tunnel a Temp. - High MA NA

h. SLCS Initiation NA f NA

1. Manual Initiation u ,

a 37f

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION 3p3

a. RCIC Steam Line Flow - High 5 WH 20 $ $ 24"' H2O g 1 60 psig 1 53 psig e RCIC Steam Supply Pressure - Low b.

RCIC Turbine Exhaust Diaphragm Pressure - High 1 10 psig 3,20psig hi c.

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' TABLE 3.3.2-2 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SETPOINTS l '

ALLOWABLE VALUE TRIP SETPOINT ,

@ TRIP FUNCTION y REACTOR CORE ISOLATION COOLING SYSTEM (Continued) i 189'F** $ 195'F**

d. RCIC Equipment Room Ambient Temperature - High 7 RCIC Equipment Room a Temp. - High 1 125'F** 5 128'F**

g e.

Main Steam Line Tunnel Ambient Temperature - High 5 179'F** 5 185'F**

f.

Main Steam Line Tunnel a Temp. - High 5 75'F** $ 78'F**

l g.

Main Steam Line Tunnel Temperature Timer i 30 minutes 5 30 minutes h.

j 5 169'Fa* $ 175'Fa*

1. RHR Equipment Room Ambient Temperature - High 1 105'F** $ 108'F**

l

j. RHR Equipment Room a Temperature - High 16 0 "

! w RHR/RCIC Steam Line Flow - High 5 145" H 2O $ WH O 2 l

! 1 k.

NA NA g 1. Manual Initiation

6. RHR SYSTEM ISOLATION 1 169'F** $ 175'F**

a. RHR Equipment Room Ambient Temperature - High 5 105'F** 5 108'F** N

b. RHR Equipment Room a Temperature - High .

> 11.4 inches * ) ,10.8 inches 'y

c. Reactor Vessel Water Level - Low, Level 3 e

d. Reactor Vessel (RHR Cut-in Permissive) 5 135 psig $ 150 psig Q p Pressure - High ,

Drywell Pressure - High i 1.73 psig 5 1.93 psig h

e. I NA NA 4

f. Manual Initiation OD O'

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=

See Bases Figure B 3/4 3-1. Any required change to Initial setpoint. Final setpoint to be determined during startup test program.

this setpoint shall be submitted to the Commission within 90 days of test completion.

3. -(GGNS - 495)

SUBJECT:

' Technical Specification Table 3.3.3-3; page 3/4 3-28.

DISCUSSION: Technical Specification Table 3.3.2-2 specifies trip setpoints and allowable values for ECCS actuation instrumentation. The following setpoints and/or allowable values should be changed.

Item- Instrument Trip Setpoint Allowable Value sA.2.c, B.2.c ADS Timer. 31105 seconds

as is A.2.e LPCS Pump Discharge Pressure-High

as is 125 - 165 psig.

A.2.f B.2.e LPCI Pump Discharge Pressure-High

as is 115 - 135 psig.

as la - Present Technical Specification value is correct.

- JUSTIFICATION: The changes to ADS Timer Trip Setpoint and LPCS and LPCI Allowable Values for pump discharge pressure-high reflect current General Electric design specification values and do not affect established transient analyses.

General Electric has reviewed the proposed changes and concurs with the new values.

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change to this Technical Specification constitutes a more stringent control of the ECCS actuation instrumentation by lowering the ADS Timer Setpoint. In addition, the LPCS and LPCI Pump Discharge Pressure High Allowable Values have been changed to reflect current General Electric design specifications, which are consistent with the established setpoints and safety analysis assumptions, and therefore, do not represent a significant reduction in the margin of safety provided by the ECCS actuation instrumentation. This change does not cause a significant increase in the probability or consequences of an accident previously evaluated nor does it create the possibility of a new or different kind of accident from any accident previously evaluated. Therefore, this change does not constitute a significant hazards consideration.

NOTE: Technical Specification page changes marked with a PCOL number and circled are changes that were previously submitted to the NRC.

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TABLE 3.3.3-2, .

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SETPOINTS

h ALLOWRELE l 5 TRIP SETPOINT VALUE I

cn TRIP FUNCTION

(& A. DIVISION 1 TRIP SYSTEM

1. RHR-A (it'CI MDDE) AND LPCS SYSTEM Reactor Vessel Water Level - Low Low Low, Level 1 1 -150.3 inches

1 -152.5 inches h a. $ 1.89 psig $ 1.94 psig

b. Drywell Pressure - High < 5 seconds $ 5 seconds LPCI Pump A Start Time Delay Relay l

c. NA NA

d. Manual Initiation

2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "A" 1 -152.5 inches

a. Reactor Vessel Water Level - Low Low Low, tevel 1 1 -150.3 inches * < 1.94 psig i < 1.89 psig.

b. Drywell Pressure - High szs-/6 Spi 11117 seconds l

c. ADS Timer f h seconds IDI > 11.4 inches *

d. Reactor Vessel Water Level-Low, level 3 f{[>10.8 inches - 1 0 p;ig , fr.;7;::f g 145 psig, increasing

e. LPCS Pump Discharge Pressure-High > )125 psig, increasing ,,1 122 p;ig, i. re;;i.;

f. LPCI Pump A Discharge Pressure-High MA I g. Manual Initiation IIK-DFr5yl l

B. DIVISION 2 TRIP SYSTEM g 1. RHR 8 AND C (LPCI MDDE) l

-Low Low Low, Level 1 1 -150.3 inches

2 -152.5 inches

a. Reactor Vessel Water Level $ 1.94 psig N

[ Drywell Pressure - High 5 1.89 psi 4 b.

5 5 second 5 5 seconds 4 cn c. LPCI Pump B Start Time Delay Relay NA g MA

d. Manual Initiation l 2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "B"> -150.3 inches * > -152.5 inches l

a. Reactor Vessel Water Level - Low Low Low, Level 1 i 1.89 psig' i 1.94 psig

b. Drywell Pressure - High i 117 seconds l

c. ADS Timer gag @ 446 seconds i 10.8 inches

> 11.4 inches *

d. Reactor Vessel Water Level-Low, level 3 l

125 psig, increasing [ 122 p;ig, f r. ::::t ;; l

e. LPCI Pump B and C Discharge Pressure-High Il5-13Sysr5[, . MA

f. Manual Initiation Q E

C. DIVISION 3 TRIP SYSTEM b

- 1. HPCS SYSTEM 1-41.6 inches

2,f-43.8 inches

! a. Reactor Vessel Water Level - Low Low, Level 2 < 1.89 psig < 1.94 psig A

b. Drywell Pressure - High 2 o 7 53.5 inches

i 55'.7 inches i

c. Reactor Vessel Water Level - High, Level 8

[0 inches [-3 inches y

d. Condensate Storage Tank Level - Low

e. Suppression Pool Water Level - High 5 5.9 inches NA 5 6.5 inches NA 4

4

f. Manual Initiation 4 V

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4. DELETED

5. (GGNS - 568)

SUBJECT:

Technical Specification Table 3.3.7.1-1, page 3/4 3-57.

DISCUSSION: Technical Specification Table 3.3.7.1-1, note "d" states that the Fuel Handling Area Ventilation Monitoring and Pool Sweep Monitoring Instrumentation causes a secondary containment isolation. This change would result in note "d" reading "also isolates the Auxiliary Building and Fuel Handling Area Ventilation Systems", Review of the logic diagrams for the affected systems indicates that only the ventilation penetrations for the Auxiliary Building and Fuel Handling Area Ventilation Systems are isolated upon receipt of a trip signal from the Fuel Handling Area Ventilation Exhaust Radiation Monitor or the Fuel Handling Area Pool Sweep Exhaust Radiation Monitor.

JUSTIFICATION: The current logic diagrams for the Auxiliary Building and Fuel Handling Area Ventilation systems indicate that only these systems penetrations are isolated upon receipt of a trip signal from the Fuel Handling Area Ventilation exhaust radiation monitor or the Fuel Handling Area Pool Sweep exhaust radiation monitor. This instrumentation does not initiate isolation of secondary containment, but does isolate the secondary containment ventilation penetrations of the systems described above. Also FSAR Section 9.4.2.5 states that the Auxiliary Building and Fuel Handling Area Ventilation Systems are isolated and not secondary containment.

-SIGNIFICANT HAZARDS CONSIDERATION:

As this proposed change is being requested to reflect the actual plant conditions shown in the appropriate system logic diagrams and the FSAR which have been reviewed and approved by the NRC, this change is considered to be purely administrative.

Further, the concern in a fuel handling accident is to prevent the release of airborne radiation to the environment. As the affected instrumentation does isolate the ventilation penetrations for the Auxiliary Building and Fuel Handling Area, thereby preventing such a release, the intent of the system design is met. Based on this, the proposed change does not involve a significant increase in the probability or consequences of a previously evaluated accident nor create the possibility of a new or different kind of accident. No significant reduction in the margin of safety is created.

Therefore, this proposed change to the Technical Specifications does not involve any significant hazards considerations.

NOTE: Technical Specification page changes marked with a PCOL number and circled are changes that were previously submitted to the NRC.

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4 TABLE 3.3.7.1-1 (Continued)

RADIATION MONITORING INSTRUMENTATION h .

6 MINIMUM CNANNELS APPLICA8LE ALARM / TRIP MEASUREMENT RANGE ACTION o, CONDITIONS SETPOINT_ _

OPERA 8LE F INSTR M NTATION

?

E 10. Area Monitors Z a. Fuel Handling Area

- Monitors -2 to 103mR/hr 10 72

1) New Fuel 1 (e) 12.5 mR/hr/NA Storage Vault

-2 to 103mR/hr 72 10 Spent Fuel 1 (f) 52.5 mR/hr/NA 5 72.

2) , cil -t . 10 mR/kr t (8) 62.5 mit/k,/gA

3) ry 64. c.Aru. 1 <0.5 mR/hr/NA 10 2 3 to 10 mR/hr 72

b. Control Room 1 At all times -

Radiation Monitor M

Y " With RHR heat exchangers in operation.

- When irradiated fuel is being handled in the secondary containment. Any required change to

!G Initial setpoint. Final Setpoint to be determined during startup test program.

this setpoint shall be submitted to Commission within 90 days after test completion.

(a) Trips system with 2 channels upscale-high high, or one channel upscale and one chann 2 channels inoperative.

(b) Isolates containment /drywell purge penetrations.

(c) With irradiated fuel in spent fuel storage pool. A u x e,l'.ary Sullch,ap an) Fue / AJI.,=p l 1

(d) Also isolates the t ;;;d:rj.;;;t: R at p;;;tatien;. Aren W.J.%t.'on SySTe - s , 4 l

(e) With fuel in the new fuel storage vault.

(f) With fuel in the spent fuel storage pool. *

(3') W4K b\ W ne. I>cjer 5%rge Are. . 1R 2

cl- 91 u IC I k 8

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e i6; (GGNS - 210)-

SUBJECT:

Technical Specification 3/4.1.1,'page 3/4 4-1.

~ DISCUSSION: Technical Specification 3.4.1.1 specifies recirculation loop

operability-requirements:for.0PERATIONAL CONDITIONS 1 and 2

The' corresponding surveillance requirement, 4.4.1.1,_does not Lverify. operation of the reactor coolant system recirculation

= loops, but instead specifies ' surveillance requirements for the

-reactor. coolant system recirculation loop flow control valves.

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Recirculation' loop operability should be verified at least once

- per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months when demonstrating jet pump operability per Specification 4.4.1.2.a. Surveillance Requirement 4.4.1.1 for recirculation' loop flow control valves along with associated new limiting conditions for operation should be placed in Specification 3/4.1, REACTIVITY CONTROL SYSTEMS, and a new bases section,-3/4.1.6, should be written to describe the recirculation loop flow control valves.

Tha. new Limiting Condition for Operation'(LCO), Applicability, and Action statements for the flow control valves are written to comply with.the existing Specification 3.4.1.1, for the reactor coolant system recirculation. loops. The flow control ,

-valves are specified to be operable'in OPERATIONAL CONDITIONS 1 and 2-when their-associated recirculation loops are required to be in operation. The surveillance requirements for the flow contro1' valves have been changed to require a demonstration of L operability prior to returning the valve (s) to service after maintenance, repair,~or replacement work.is performed on the valve or its associated actuator, hydraulic power unit or control circuit. The surveillance requirements for the flow control valves have also been changed to reflect that the rate of control valve movement is a " maximum" rate rather than the presently stated " average". The " maximum" rather than

" average" control valve movement rate of 11% of stroke per second is specified in FSAR Section 15.3.

JUSTIFICATION: The present Surveillance Requirement 4.4.1.1 for recirculation loop flow control valves does not support the corresponding LCO 3.4.1.1, for recirculation loops in operation. The-

-recirculation loops.should be verified in operation during

, performance of jet pump _ operability surveillance performed at least once'per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months per Surveillance Requirement 4.4.1.2.a.

The recirculation loop flow control valve position affects b reactivity addition to the reactor core since recirculation j pump _speedLis kept constant and loop' flow is changed by

position of the flow control valve. The increased surveillance

[ . requirements on the flow control valves help to' ensure their operability.

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. .SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change is administrative in that it establishes better consistency between LCO's and surveillance requirements.

Additionally it establishes more stringent requirements for

-operability of the recirculation flow control valves.

Therefore, based on comparison with NRC example 3 (ii) (10 CFR 50, Interim Final Rule, Federal Register, April 6, 1983),

amendments that are considered not likely to involve significant hazards considerations, the proposed change to the

. Technical Specifications does not involve any significant hazards considerations.

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6 g.1 (GGNS-210) 3/4.4 REACTOR COOLANT SYSTEM 3/4.4.1 RECIRCULATION SYSTEM ;

RECIRCULATION LOOPS LIMITING CONDITION FOR OPERATION 3.4.1".1 Two reactor coolant system recirculation loops shall be in operation.

APPLICABILITY: OPERATIONAL CONDITIONS 1* and 2*.

ACTION:

a. With one reactor coolant system recirculation loop not in operation, 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 no reactor coolant system recirculation loops in operation, immediately initiate measures to place the unit in at least STARTUP within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS E'ac.h e4 treee c. toy. coolaut system recirculdi o,V bYS..I**pt I.. c@ eve..re7::tM..

n. . F.IT. .. ... b. .y: . 5NdN..h::.

e 4.4.1.1 e.. .

ch:115; d;nn:tr:t:d 0"E"'."LE :t 1:nt n;; ;;r IS nath: 53

. V:rifying th:t th: natr:1 nin 1;il: "n i:" ;; 1;;; ef hydreulic pr:n ur: :t th: hyd n:li: : it, ad

b. Y:rifying th:t th; n:n;; r;t: ;f natal nin s.;nat i::

1. L::: then :r :; :1 t: I'l :f :t nt: ;:r ::n nd :;;r'ag, : d l

2. Ln: th= :: ;ni t; l'd Of :tr:h: ;:r :::=d :10:ing.

l l

l "See Special Test Exception 3.10.4.

l l

l I

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3/4 4-1 i

GRAND GULF-UNIT 1 i

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- , - - - , . . , . , . , - - - , . - ,,,c -, ,-y w g,, , , , ~-=----..~--_,mm.

E 6.canas-no) 3/4.1 REACTIVITY CONTROL SYSTEMS 3/4.1.6 RECIRCULATION FLOW CONTROL VALVES LIMITING CONDITION FOR OPERATION -

3.1.6 Two reactor coolant system recirculation flow control valves shall be operable.

APPLICABILITY: Operational conditions 1 and 2 ACTION:

a. With one reactor coolant system recirculation flow control valve not OPERABLE, 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 no reactor coolant system recirculation flow control valves OPERABLE, immediately initiate measures to place the unit in at least startup within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in hot shutdown within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.6 Each reactor coolant system recirculation loop flow control valve shall be demonstrated OPERABLE at least once per 18 months and prior to returning the valve to service after maintenance, repair, or replacement work is performed on the valve or its associated actuator, hydraulic power unit, or control circuit by:

a. Verifying that the control valve fails "as is" on loss of hydraulic pressure at the hydraulic unit, and

b. Verifying that the maximum rate of control valve covement is:

1. Less than or equal to 11% of stroke per second opening, and

2. Less than or equal to 11% of stroke per second closing.

}

23F(TS Dump) 3/4 1-21 l

\ *

~

(o[GGMS-210) p CTIVITY CONTROL SYSTEMS

,pAsES :

t 3/4.1.6 RECIRCULATION FLOW CONTROL VALVES The recirculation flow control valves provide regulation of individual

~

~2 tecirculation loop drive flow; which, in turn, will vary the flow rate o coolant through the reactor core over a range consistent with the rod pattern and recirculation pump speed. The recirculation flow control system consists of the electronic and hydraulic components necessary for the positioning of the two hydraulically actuated flow control valves. Solid state control logic will generate a flow control valve " motion inhibit" signal in response to any s

one of several hydraulic power unit or analog control circuit failure signals.

The " motion inhibit" signal causes hydraulic power unit shutdown and hydraulic isolation such that the flow control valve fails "as is". This design feature insures that the flow control valves do not respond to potentially erroneous control signals, s

Electronic limiters exist in the position control loop of each flow control 1 valve to limit the flow control valve stroking rate to 1011% per second in the

, opening and closing directions on a control signal failure. The analysis of the recirculation flow control failures on increasing and decreasing flow are

. presented in Sections 15.3 and 15.4 of the FSAR respectively.

3 The required surveillance interval is adequate to insure that the flow control valves' remain OPERABLE and not so frequent as to cause excessive wear on the system components.

A g

3s Y

J Us A

+

,' l

, s s'~

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o

24'F(TS Dump) B3/4 1-5

7. (CCNS - 708)

SUBJECT:

Technical Specification 4.4.2.1.2.b, 4.4.2.2.1.b, Table 3.3.3-1; pages 3/4 4-5, 3/4 4-6, 3/4 3-25, and 3/4 3-26.

DISCUSSION: Technic'al Specifications 4.4.2.1.2.b and 4.4.2.2.1.b requires a LOGIC SYSTEM FUNCTIONAL TEST of the relief valve function pressure actuation instrumentation at least once per 18 months.

The procedure for performing the LOGIC SYSTEM FUNCTIONAL TEST requires opening of the relief valves at greater than or equal to 100 psig. Since this cannot be accomplished on cold startup until the desired reactor pressure is reached, the specification should be changed to allow entry into Operational Condition 2 (Startup) without the valve opening portion of the LOGIC SYSTEM FUNCTIONAL TEST being accomplished. The test with valve opening will be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of reaching the required Reactor pressure. The proposed change to Table 3.3.3-1 will also allow entry into Operational Condition 2 without performing the valve opening part of the LOGIC SYSTEM FUNCTIONAL TEST.

JUSTIFICATION: Specification 4.0.4 requires that entry into an OPERATIONAL CONDITION or other specified applicable condition shall not be made unless the Surveillance Requirement (s) associated with the Limiting Condition for Operation have been performed within the applicable surveillance interval or as otherwise specified.

Entry into Operation Condition 2 requires that the LOGIC SYSTEM FUNCTIONAL TEST required on an 18 month frequency be satisfied for the safety / relief valves. However, since this test requires at least 100 psig reactor pressure and may require entry into Operational Condition 2 to obtain this required pressure, the change is necessary to prevent conflict with Specification 4.0.4. (

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change modifies the provisions of Specification 4.0.4 so that the plant conditions necessary to satisfy the intent of the surveillance requirements 4.4.2.1.2.b and 4.4.2.2.1.b can be established. The precedent for this type of change is established in the surveillance requirements for tail-pipe pressure switches (4.4.2.1.2.b). This change to the Technical Specification is not considered to involve a significant reduction in a margin of safety since it establishes the ability to meet the intent of the surveillanec.

As such, neither a significant increase in the probability or consequences of an accident previously evaluated nor the possibility of a new or different kind of accident from any accident previously evaluated is involved. Therefore, this change to the Technical Specifications does not involve any significant hazards considerations.

8F(TS Dump) e

f'

. . REACTOR C0OLANT SYSTEM l 3/4.4.2 SAFETY VALVES SAFETY / RELIEF VALVES LIMITING CONDITION FOR OPERATION .

3.4'.2.1' Of'the following safety / relief valves, the safety v'alve function of at least'7 valves and the relief valva function of at least 6 valves other than those satisfying the safety valve function requirement shall be OPERABLE with ,

the specified lift settings:

Function Setpoint* (psia)

1%

Number of Valves

~

Safety 1165 ,

8 Safety 1180 6

Safety 1190 6

Relief 1103 1

Relief 1113 10 1123 9 Relief APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With the safety and/or relief valve function of one or more of the above l

required safety / relief valves inoperable, be in at least HDT SHUTDOWN l

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

b. With one or more safety / relief valves stuck open, provided that suppression pool average water temperature is less than 105'F, close the stuck open relief valve (s); if unable to close the open valve (s) within 2 minutes or if suppression pool average water temperature is 105'F or greater, place the reactor mode switch in the Shutdown position,

c. With one or more safety / relief tail-pipe pressure switches inoperable, restore the inoperable switch (es) to 0PERABLE status within 7 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 COLD SH within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.4.2.1.1 The tail pipe pressure switch for each safety / relief valve shall be demonstrated OPERABLE with the setpoint verified to be 30 t 5 psig by performance of a

a. CHANNEL FUNCTIONAL TEST at least once per 31 days, and a

b. CHANNEL CALIBRATION at least once per 18 months.**

4.4.2.1.2 The relief valve function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:

CHANNEL FUNCTIONAL TEST, including calibration of the trip unit, at a.

least once per 31 days.

ea,ar l

b. CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system at least once per 18 months.

"The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures.

- The provisions of Specification 4.0.4 are not applicable p adequate to perform the test.

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,3/4 4-5 #g surn%. . ;s'g,3glL'nb7C,, QR ),"'g*Q'_g'*h t" GRAle GULF-UNIT 1 rLa pusura is ahp, ate. t. yar.M , rs,a raay;

2

7. f .(GG N S-70 6)

REACTOR COOLANT SYSTEM SAFETY / RELIEF VALVES LOW-LOW SET FUNCTION

~

LIMITING CONDITION FOR OPERATION

. 3.4.2.2 The relief valve function and the low-low set function of the

' following reactor coolant system safety / relief valves shall be OPERABLE with the following low-low set function lift settings:

Set >oint* (psia)

1%

Valve No. Jpen close F051D 1033 926 F051B 1073 936 F0470 1113 946 F047G 1113 946 F051A 1113 946 F051F 1113 946 APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With the relief valve function and/or the low-low set function of one of the above required reactor coolant system safety / relief valves inoperable, restore the inoperable relief valve function and the low-low set i

function 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 in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. With the relief valve function and/or the low-low set function of more than one of the above required reactor coolant system safety / relief valves inoperable be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWNwithinthenext24 hours.

SURVEILLANCE REQUIREMENTS 4.4.2.2.1 The relief valve function and the low-low set function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:

a. CHANNEL FUNCTIONAL TEST, including calibration of the trip unit, at least once per 31 days.

eHe' l

b. LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic CHANNEL operation ofCALIBRATION, the ent ire system at least once per 18 months. ,

"Ihe lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures, e n=% .% %

isl*ses g=~ SpoJlmti.m 4,o. se- ara not ,,.un .es1L. ,p gliesblap.,aad or so va. - ss ra v laasr ss in k med w.Tho% l 2 . k o vafrar r s,.;>vaan st. _ p,u ayan, GRAND GULF-UNIT 1 d

F aT* r,4f/4d0m &u

1 I

TABLE 3.3.3-1 . ,

EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRtMENTATION ,

MINIMUM OPERABLE APPLICA8Lt l @ CHANNELS PER OPERATIONAL l

I Q TRIP FUNCTION (*) CONDITIONS ACTION l g TRIP FUNCTION ,

A. DIVISION I TRIP SYSTEM i

1. RHR-A (LPCI MDDE) & LPCS SYSTEM

> a. Reactor Vessel Water Level - Low Low Low, Level 1 2 1, 2, 3, 4*, 5* 30

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

c. LPCI Pump A Start Time Delay Relay 1 1,2,3,4*,5* 31 Manual Initiation 1/ system 1, 2, 3, 4*, 5* 32

, d.

2. AUTOMATIC DEPRESSURIZATION SYSTEN TRIP SYSTEM "A"#'

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

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

1 1,2,3 31 w c. ADS Timer 31 Reactor Vessel Water Level - Low, level 3 (Permissive) 1 1,2,3 1 d.

1 1,2,3 31 w e. LPCS Pump Discharge Pressure-High (Permissive)

LPCI Pump A Discharge Pressure-High (Permissive) 1 1,2,3 31 i A f.

32

g. Manual Initiation 1/ valve 1, 2, 3 I 8. DIVISION 2 TRIP SYSTEM l 1. RHR 8 & C (LPCI iwvE) 4*, 5* 30

> a. Reactor Vessel Water Level - Low, low Low, Level 1 2 1, 2, 3, Drywell Pressure - High 2 1,2,3 30

b. 4*, 5* 31 i

LPCI Pump 8 Start Time Delay Relay 1 1, 2, 3,

c. 4*, 5* 32

d. Manual Initiation 1/ system 1, 2, 3,

2. AUTOMATIC DEPRESSURIZATION SYSTEM TRIP SYSTEM "8"# b) 8 1,2,3 30 4e

a. Reactor Vessel Water Level - Low Low Low, Level 1 2(Ib) 9 l 2 1, 2, 3 30 i b. Drywell Pressure - High 31

c. ADS Timer 1 1,2,3 l

Reactor Vessel Water Level - Low, Level 3 (Permissive) 1 1,2,3 31 I d. 31 2:

e. LPCI Pump 8 and C Discharge Pressure - High (Permissive) 1/ pump 1,2,3

f. Manual Initiation 1/ valve 1,2,3 32 T Y

e

%s

TABLE 3.3.3-1 (Continued) si f EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION MINIMUM OPERA 8LE CHANNELS PER APPLICABLE OPERATIONAL

@ CONDITIONS _. ACTION ,

q , TRIP FUNCTION (a)

TRIP FUNCTION g i U C. DIVISION 3 TRIP SYSTEM w . '1, 2, 3.'4*, 58 33

1. HPCS SYSTEM 4

- Reactor Vessel Water Level - Low, Low, Level 2 1, 2, 3 33

a. 4g

'31

b. Drywell Pressure - High 1, 2, 3, 4*, 58

c. Reactor Vessel Water Level-High, Level 8 2(C) ) 1, 2, 3, 4*, 5* 34

d. Condensate Storage Tank Level-Low 2(d) 2 1,2,3,4*,5* 34

e. Suppression Pool Water Level-High 1/ system 1, 2, 3, 4* , 5* 32 i

f. Manual Initiation D. LOSS OF POWER Division 1 and 2 4' 1, 2, 3, 4**, 5** 30 5' 1.

a. 4.16 kV Bus Undervoltage c. ;

(Loss of Voltage) 4 1, 2, 3, 4**, 5** 30 l Y 4.16 kV Bus Undervoltage

@ b. .-

5** 30 (90P Load Shed) 4 1, 2, 3, 4**,

i

c. 4.16 kV Bus Undervoltage l

(Degraded Voltage) l # 1, 2, 3, 4**, 5** 30 $

2. Division 3 4 g

a. 4.16 kV Bus Undervoltage (Loss of Voltage)

(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 p '

surveillance without placing the trip system in the tripped condition provided at least one z other OPERABLE channel in the same trip system is monitoring that parameter, V i 8 j (b) Also actuates the associated division diesel generator.

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

signal to HPCS pump suction valves only. -

Ob (d) U (e) One out-of-two taken.

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

' ** Required when ESF equipment is required to be OPERA 8LE.

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

caw for 6' y ovWo=' of M Tka ovMo,es e5 .Q.aciF;eJl*,. 't; o. 'I are h oT' is y>avfovn J way,:vas vaiva. c,pa.,, proSb. fla. sairv.;llee

1. n sowaft ca rGr w.rs. . - n u.., - ara, . . .a. , , ,, _ ,, _ . . ; , . ,,, r r , ,.,,s. w w r

e.

8. (CGNS - 14)

SUBJECT:

Technical Specification 3/4.6.1.4, page 3/4 6-7.

DISCUSSION: Present Sneveillance Requirement 4.6.1.4.c.2 requires an 18 month surveillance to verify the Main Steam Line Isolation

' Valve-Leakage Control System (MSIV-LCS) blower performance.

The purpose of this specification is to verify that each blower develops at least the required vacuum as indicated in the Technical Specification.

The rcquired vacuum is given at a corresponding blower flow rate for both the inboard and outboard leakage control. systems.

The present blower ratings in the specification of -60".H O2 at 100 standard cubic feet per minute (scfe) for the inboard system and -50" H O at 240 scfm for the outboard system were obtained from the2General Electric (GE) purchase specification for the MSIV-LCS blower and do not reflect system functional requirements. . System functional requirements determined by GE requires revision to the Technical Specification, to read as follows:

Inboard system, -15" 2" H90 at greater than 100 scfm Outboard system, -50" 2" H2O at greater than 200 scfm These new values reflect actual system pre-operational testing experience at other plants. In performing the surveillance test, a tolerance is appropriate in regard to the developed flow and vacuum.

JUSTIFICATION: The proposed change clarifies that the surveillance test is performed with air flow through the system. Tite corresponding change establishing a blower flow rate greater than 100 scfm for the inboard system and greater than 200 scfm for the outboard system is proposed to provide flexibility in performing the blower performance tests. The proposed MSIV-LCS blower performance values were provided by CE and reflect the system functional requirements.

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change provides clarification to the surveillance test conditions. It also replaces purchase specification values for the Main Steam Isolation Valve-Leakage Control System Blowers with values that reflect the actual system functional requirements. These values satisfy the Technical Specification Bases and were added to reflect the actual system functional requirements. As this change only involves clarification and corrections, it is purely administrative and therefore does not involve a significant increase in the probability or consequences of an accident which was previously evaluated or create the possibility of a new or different kind of accident from any accident previously evaluated. No significant reduction in a margin of safety is involved.

Therefore, this change does not involve any significant hazards corsiderations.

9F(TS Dump)

6,(G6N S -1+)

CONTAINMENT SYSTEMS ~ !

~MSIV LEAKAGE CONTROL SYSTEM LIMITING CONDITION FOR OPERATION '

1 3.6.1.'4' Two independent MSIV leakage control system (LCS) subsystems shall be OPERABLE; APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION-With one MSIV leakage control system subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 30 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.1.4 Each MSIV leakage control system subsystem shall be demonstrated OPERABLE:

a. At least once per 31 days by verifying:

1. Blower OPERABILITY by starting the blowers from the control room and operating the blowers for at least 15 minutes.

2. Heater OPERABILITY by demonstrating electrical continuity of the heating element circuitry.

i

b. During each COLD SHUTDOWN, if not performed within the previous 92 days, by cycling each motor operated valve through at least one complete cycle of full travel.

c. At least once per 18 months by:

1. Performance of a functional test which includes simulated actuation of the subsystem throughout its operating sequence, and verifying that each automatic valve actuates to its correct position,.the blowers start and the heater draws 7.8 to 9.5 amperes per phase.

2. Verif.ying that the blower developed at least the below required vacuuaattheratedcapac,ig., g InboardspTmv. h n ,,- 00" ZM 0 :t 1^^ : '-

a) se*g ,,n gto ,g ,,,, gay 6 , zoo u% ,

b) Outboardq.. p=;,,

"^" M 2 Ot =C = " *

d. By verifying the inboard flow, inboard and outboard pressure, and inboard temperature instrumentation to be OPERABLE by performance of a:

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

2. CHANNEL FUNCTIONAL TEST at least once per 31 days, and

3. CHANNEL CALIBRATION at least once per 18 months.

GRAND GULF-UNIT 1 3/4 6-7

9. (GGNS - 336)

SUBJECT:

Technical Specification 4.6.6.3.d.2, page 3/4 6-54

~

DI$CUSSION: Technical Specification 4.6.6.3.d.2 specifies an 18 month surveillance requirement on the Standby Cas Treatment System High Efficiency Particulate Air (HEPA) filters and charcoal adsorber banks. This surveillance presently requires verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 10.75 inches Water Gauge while operating the filter train at a flow rate of 4000 cubic feet per minute (cfm) i 10%. By design specification, the Standby Gas Treatment system fan is rated at 14" H 2O static pressure at 4000 cfm. Calculations using the system design specification (9645-M-632.0) show that after considering fixed differential pressures in the filter train (housing of .50" H2 0, heater of .20" H20, demister of .50" H20, dirty prefilter of 1.0" H g 0, external static pressure from the air cleanup unit of 2.6 H O) that only 9.2" H O (14" - 4.8" 2 2 fixed) is left for the HEPA filters and charcoal adsorber banks. The recommended change to the Technical Specifications is to lower the less than 10.75" H O 2requirement on the HEPA filters and charcoal adsorber banks to less than 9.2" H 20.

JUSTIFICATION: Calculations using system design specification values show that the pressure drop across the combined HEPA filters and charcoal adsorber banks cannot exceed 9.2" H2 O while operating the filter train at a flow rate of 4000 cfm i 10%.

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change is requested to provide consistency with actual plant design. It constitutes an additional restriction not presently included in the Technical Specification by decreasing the allowable pressure drop across the combined High Efficiency Particulate Air (HEPA) filters and charcoal absorbers banks. Therefore, based upon NRC example, the proposed change to the Technical Specification does not involve significant hazards considerations.

10F(TS Dump)

y , (GGNS -336) i CONTAlle1ENT SYSTEMS SURVEILLANCE" REQUIREMENTS (Continued)

b. At least once per 18 months or (1) after any structural mairitenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone -

communicating with the subsystem by:

1. Verifying that the subsystem satisfies the in place testing acceptance criteria and uses the test procedures of Regulatory Positions C.5.a. C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rate is 4000 cfm i 105.

2. Verifying within 31 days after removal that a laboratory analysis of a representative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.

3. Verifying a subsystem flow rate of 4000 cfm i 10% during system operation when tested in accordance with ANSI N510-1975.

c. After every 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of charcoal adsorber operation by verifying within 31 days after removal that a laboratory analysis of a repre-sentative carbon sample obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, meets the laboratory testing criteria of Regulatory Position C.6.a of Regulatory Guide 1.52, Revision 2, March 1978.

l d. At least once per 18 months by:

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

a) LOCA, and b) Fuel handling accident. 7 f--

2. Verifying that the pressure drop across the combined HEPA filters inches Water Gauge l and charcoal adsorber banks is less than .

while operating the filter train at a flow rate of 4000 cfm i 10%.

3. Verifying that the filter train starts and isolation dampers

open on each of the following test signals:

a. Drywell pressure - high,

b. Reactor vessel water level - low low, level 2,

c. Fuel handling area ventilation exhaust radiation - high, and

d. Fuel handling area pool sweep exhaust radiation - high.' -

[

4. 8 Verifying that the fan can be manually started.

5. Verifying that the heaters dissipate 50 1 5.0 kW when tasted in accordance with ANSI N510-1975.

GRAND GULF-UNIT 1 3/4 6-54

r-

10. (GGNS - 698)

SUBJECT:

Technical Specification 4.6.7.3.b.1, page 3/4 6-59.

Technical Specification 4.6.7.3.b.1 pre.sently requires each

~

DISCUSSION:

drywell purge system subsystem to be demonstrated operable at least once per 18 months by verifying a subsystem flow rate of at least 500 cubic feet per minute (cfm) during subsystem operation for at least 15 minutes. A NUREG-0588 evaluation was conducted in order to determine the flowrate required to limit drywell equipment radiation doses to equipment qualification levels. A flowrate of 1000 standard cubic feet per minute (sefm) was determined to meet NUREG-0588 requirements.

The proposed change will reflect a new surveillance flow rate of 1000 cfm instead of the present 500 cfm.

JUSTIFICATION: In order to limit drywell equipment radiation dose to equipment qualification levels and meet the intent of NUREG-0588, the drywell purge subsystem flowrate was increased to 1000 cfm.

This Technical Specification change reflects an increase in drywell purge subsystem flowrate from 500 cfm to 1000 cfm.

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change constitutes an additional limitation not presently included in the Technical Specifications by

-increasing the minimum allowable drywell purge system subsystem flow rate. Therefore, based upon NRC example 3 (ii) (10 CFR 50, Interim Final Rule, Federal Register, April 6, 1983),

amendments that are considered not likely to involve significant hazards considerations, the proposed change to the Technical Specifications does not involve any significant hazards considerations.

j . 11F(TS Dump) c b

to. cccus- ea)

CONTAIMENT SYSTEMS DRYWELL. PURGE SYSTEM LIMITING CONDITION FOR OPERATION 3.6.7.3 Two independent drywell purge system subsystems shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

With one drywell purge system subsystem inoperable, restore the inoperable subsystem to OPERABLE status within 30 days or be in at least HOT SHUTOOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS Continued 4.6.7.3 Each drywell purge system subsystem shall be demonstrated OPERABLE:

a. At least once per 92 days by:

1. Starting the subsystem from the control room, and

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

b. At least once per 18 months by:

jooo

1. Verifying a subsystem flow rate of at least MW cfm during l subsystem operation for at least 15 minutes.

2. Verifying the pressure differential required to open the vacuum breakers on the drywell purge compressor discharge lines, from the closed position, to be less than or equal to 1.0 psid.

c. Verifying the OPERABILITY of the drywell purge compressor discharge line vacuum breaker isolation valve differential pressure actuation instrumentation with an opening setpoint of 1.0 psid by performance of a:

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

2. CHANNEL FUNCTIONAL TEST at least once per 31 days, and

3. CHANNEL CALIBRATION at least once per 18 months.

GRAND GULF-UNIT 1 3/4 6-59

s.

t

11. (GGNS - 26)

SUBJECT:

-Technical Specification 3.7.6.2 and 4.7.6.2.c.2,~ page'3/4 7-31.

DISCUSSION: Additional spray / sprinkler systems should be added to the

~*

. requirements for system operability of limiting condition for operation 3.7.6.2. These additional systems include systems in the Auxiliary Building and the Control Building. The inclusion of.this information in the Technical Specifications is in accordance with Inspector Follow-up Item 416/82-56-03.

The surveillance requirements presently in 4.7.6.2 should be changed to specify the appropriate requirements for the fire protection systems in the-Diesel Generator Building, Auxiliary

Building and the Control Building.

Visual inspection of piping and headers.is not be required for t the air supervised, pre-action sprinklers in the Diesel <

Generator Building. The requirement for visual inspection of the Diesel Generator Building air supervised systems should,

therefore, be eliminated from the Technical Specification-Surveillance Requirement presently in 4.7.6.2.c.2.

JUSTIFICATION: Section 3/4 7.6 of the Technical Specification bases states

.that fire protection systems must. be operable to ensure that adequste fire ~ suppression capability is available to confine

, and extinguish fires occurring in that portion of Grand Gulf

- Nuclear Station-(GGNS) where safety related equipment is 4 located. Appendix 9A of the GGNS Final Safety Analysis Report

, (FSAR) describes the fire suppression systems which assure adequate fire protection.for safety related equipment.

Appendix 9A states that spray / sprinkler systems are provided to

. assure adequate fire protection capability in the Auxiliary Building, the Control Building and the Diesel Generator Building. The spray / sprinkler systems in the Auxiliary and Control Buildings should therefore be added to the Technical Specification Limiting Condition for Operation 3.7.6.2.

The appropriate surveillance requirements for the fire l protection systems in the~ Diesel Generator Building, Auxiliary l Building and the Control Building differ. As a result, this ~

l : proposed. change provides specific surveillance requirements for the fire protection systems in each building consistent with lthe system design.

The automatic pre-action sprinkler systems for the Diesel

Generator Building are furnished with an air supervisory

_ system. This system involves pressurizing the sprinkler.

, , headers with air. .If the pressure of this air drops below a pre-set value, an alarm is actuated in the Control Room to ,

inform the operator that some type of leak has developed in the

~

sprinkler header. Since the air supervisory system provides i essentially continuous monitoring of these pre-action sprinkler 12F(TS' Dump) l I - - _ _ _ , _ _ _ _ ~ _ . , , . _ _ _ _ _ _ _ _ . _ _ _ . _ _ , _ _ - _ _ _

~

+

<> , e systems, periodic visual inspection of-these systems is not warranted. The corresponding requirement for this inspection presently in 4.7.6.2.c.2 is, therefore, not included in the proposed specification for the Diesel Generator Building system. _

The proposed specifi' cation for the Auxiliary Building systems clarifies'that-the 18 month surveillance censists of verificat' ion of valve. actuation on'a " system test" rather than a " test signal". . This system test will be performed by opening a, flow test drain valve to establish flow in the system. This system is not a dry pipe system, and thus a specification regarding the 18 month dry pipe visual inspection requirement is not included.

The proposed specification for the Control Building systems clarifies'that,the 18 month. surveillance consists.of' verification of no system obstructions on a " system test" rather than a " test. signal." This system test will be performed by opening a flow test drain valve-to establish flow in the system. This system is not a dry pipe system, and thus a specification regarding the'18 month dry pipe visual inspection requirement is not included. :There are no automatic valves'in the flow path,~therefore, verification of automatic actuation is not included.

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change' deletes a surveillance requirement for the visual inspection of the dry pipe and sprinkler headers of the spray and sprinkler systems in the Diesel Generator Building at discrete time intervals. However,'as-this function is'being served by an automatic system that continuously monitors the integrity of.this piping, system surveillance is actually enhanced. In addition the proposed change adds surveillance requirements for spray and sprinkler systems in the Auxiliary and Control Buildings. The affected systems in the Auxiliary

.. Building are not dry pipe systems. Accordingly the new surveillance requirements for these systems do not include the specification regarding the 18 month visual inspection of dry

. piping. -The.affected systems in the Control Building are manual backup systems. Accordingly the new surveillance requirements for these systems do not include the specification

>- for verification of the actuation of the automatic valves. The

-addition of surveillance requirements for spray and sprinkler systems in the Auxiliary and Control Buildings constitute l additional' controls not presently included in the Technical Specifications. Therefore,_this change does not involve the reduction of safety margins. No significant increase in the probability _or consequences of an accident previously evaluated is involved nor is the possibility of a new or different kind of accident from any accident previously evaluated created.

'Thus the proposed change to the Technical Specification does i 'not involve any significant hazards considerations.

!- 13F(TS Dump)

I

II,g.i (GG Ns- 26)

PLANT SYSTEMS

SPRAY AND/0R SPRINKLER SYSTEMS LIMITING CONDITION FOR OPERATION ,

7.0."

Oteeel gene.eter ", ", end C sute;;tih pre estier,e,ete;; # .N1F040142 ^

8 nd C shall be OPERABLE.

ILITY: Whenever equipment protected by the spray / sprinkler syste is APPL require to be OPERABLE.

l ACTION: '

Wit one or more of the above required spray and/or spri ler systems a.

inope ble, within one hour establish a continuous fit watch with backup ire suppression equipment for those areas in hich redundant systems o components could be damaged; for other eas, establish an hourly

e watch patrol. Restore the system o OPERABLE status within 14 da or, in lieu of any other report quired by Specifica-tion 6.9.1, pre re and submit a Special Rep t to the Commission pursuant to Spec ication 6.9.2 within the ext 30 days outlining the action taken, e cause of the inoper ility and the plans and schedule for restori the system to OP ABLE status.

The provisions of Speci ' cation 3.0. and 3.0.4 are not applicable.

b.

SURVEILLANCE REQUIREMENTS x 4.7.6.2 The above required spray an sprin er systems shall be demonstrated OPERABLE:

a. At least once per 31 ys by verifying hat each in its valve, manual, power correct position.

operated or automat' , in the flow path

b. At least once pe 12 months by cycling each estable valve in the flow path thro h at least one complete cycle f full travel.

c. At least on per 18 months:

1. By rforming a system functional test which i ludes simulated a omatic actuation of the system, and:

a) Verifying that the automatic valves in the f1 path actuate to their correct positions on a test signal, an ble b) Cycling each valve in the flow path that is not tes during plant operation through at least one complete cle of full travel.

2. By a visual inspectio7._.of the gry pipe spray and sprinkler

....w...,.

GRAND GULF-UNIT 1 3/4 7-31

o PLANT SYSTEM _S 1L bNS-Eb)

SPRAY AND/OR SPRINKLER SYSTEMS LIMITING CONDITION FOR OPERATION 3.7.6.2 The following spray / sprinkler systems shall be operable:

a. Diesel Generator Building

1. Diesel Generator A pre-action sprinkler system N1P64D142A

2. Diesel Generator B pre-action sprinkler system N1P64D142B

3. Diesel Generator C pre-action sprinkler system N1P64D142C

b. Auxiliary Building

1. Elevation 93'/103' Northeast Corridor N1P64D150

2. Elevation 119' Northeast Corridor N1P64D151

3. Elevation 139' Northeast Corridor N1P64D152

4. Elevation 166' Northeast Corridor N1P64D153

5. Elevation 119' West Corridor N1P64D158

6. Elevation 139' West Corridor N1P64D159 C. Control Building

1. Elevation 148' Lower Cable Room N1P64D154

2. Elevation 189' Upper Cable Room N1P64D155 APPLICABILITY: Whenever equipment protected by the spray / sprinkler systems is required to be OPERABLE.

ACTION:

a. With one or more of the above required spray and/or sprinkler systems inoperable, within one hour establish a continuous fire watch with backup fire suppression equipment for those areas in which redundant systems or components could be damaged; for other areas, establish an hourly fire watch patrol. Restore the system to OPERABLE status within 14 days or, in lieu of any other report required by Specification 6.9.1, prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within the next 30 days outlining the action taken, the cause of the inoperability and the plans and schedule for restoring the system to OPERABLE status.

b. The provisions of Specification 3,0.3 and 3.0.4 are not applicable.

20F(TS Dump) 3/4 7-31

11.(GG Ns-u)

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS 4.7.6.2.a The spray and sprinkler systems of 3.7.6.2.a shall be demonstrated

OPERABLE:

1. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path is in its correct position.

2. At least once per 12 months by cycling each testable valve in the flow path through at least one complete cycle of full travel.

3. At least once per 18 months:

a. By performing a system functional test which includes simulated automatic actuation of the system, and:

1. Verifying that the automatic valves in the flow path actuate to their correct positions on a test signal, and

2. Cycling each valve in the flow path that is not testable during plant operation through at least one complete cycle of full travel.

4.7.6.2.b The spray and sprinkler systems of 3.7.6.2.b shall be demonstrated OPERABLE:

1. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path is in its correct position.

2. At least once per 12 months by cycling each testable valve in the flow path through at least one complete cycle of full travel.

3. At least once per 18 months by:

a. Verifying that the automatic valves in the flow path actuate to their correct positions on a system test by opening a test drain valve, and

b. Cycling each valve in the flow path that is not testable during plant operation through at least one complete cycle of full travel.

4.7.6.2.c The spray and sprinkler systems of 3.7.6.2.c shall be demonstrated OPERABLE:

1. At least once per 31 days by verifying that each valve, manual, power operated or automatic, in the flow path is in its correct position.

21F(TS Dump) 3/4 7-31a

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

f;. (fi;c;3ss-zc)

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS

2. At least once per 12 months by cycling ea'ch testable valve in the flow path through at least one complete cycle of full travel.

3. At least once per .18 months by:

a. Verifying no obstructions in the sprinkler system by performing a system test by opening a test drain valve, and

b. Cycling each valve in the flow path that is not testable during plant operation through at least one completa cycle of full travel.

1 22F(TS Dump) 3/4 7-31b

F I

l

12. (GGNS - 75)

SUBJECT:

Technical Specification 4.8.1.1.1.b, page 3/4 8-3.

DISCUSSION: Surveillance Requirement 4.8.1.1.1.b requires that each of the independent A.C. electrical power circuits between the offsite transmission network and the onsite Class 1E distribution system be demonstrated OPERABLE at least once per 18 months during shutdown by transferring, manually and automatically, unit power supply from the normal circuit to the alternate circuit. There is no automatic transfer from the normal to alternate circuit since this bus search and automatic transfer feature was deleted from the Load Shedding and Sequencing (LSS) panel by a pre-operating license design change. Section 8.3 of the FSAR no longer contains a description of the bus search and automatic transfer feature of the LSS panel. This proposed change deletes the Surveillance Requirement on a non-existing feature from the Technical Specifications.

JUSTIFICATION: The automatic transfer feature from the normal offsite power supply to the alternate, upon sensing low voltage, no longer exists in the LSS panel. FSAR Chapter 8 describes the sequence of events upon loss of offsite power. The Diesel Generators will start when low voltage is sensed on their respective emergency busses and the operator can manually switch to an alternate offsite power source (if available) and not use the Diesel Generators. This change reflects the current description in FSAR Section 8.3 of the LSS panel and the intended manual switching from the normal unit power supply to alternate.

SIGNIFICANT HAZARDS CONSIDERATION:

The proposed change deletes the surveillance requirement for the automatic transfer of unit power supply from the nermal circuit to the alternate circuit. This feature has previously been deleted from the Load Shedding and Sequencing (LSS) panel and from Section 8.3 of the FSAR. Therefore, this change is a purely administrative change to correct the Technical Specification so that it reflects the actual plant configuration as shown in the FSAR. By comparison with NRC example 3 (i) (10 CFR 50 Interim Final Rule Federal Registka, April 6, 1983), amendments that are considered not likely to involve significant hazards considerations the proposed change involves no significant hazards considerations.

NOTE: Technical Specification page changes marked with a FCOL number and circled are changes that were previously submitted to the NRC.

14F(TS Dump)

12. (ggt 4s-75)

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Each of the above required independent circuits between,the offsite transmission network and the onsite Class 1E distribution system shall be:

l I k. ~ Determined OPERA 8LE at least once per 7 days by verifying correct breaker alignments and indicated power availability, and I

b. Demonstrated OPERABLE at least once per 18 months during shutdown by transferring, manually n d nt z t' n W , unit power supply from the l normal circuit to the alternate circuit.

4.8.1.i.2 Each of the above required diesel generators shall be demonstrated OPERABLE:

a. In accordance with the frequency specified it Table 4.8.1.1.2-1 on a STAGGERED TEST BASIS by:

1. Verifying the fuel level in the day tank.

2. Verifying the fuel level in the fuel storage tank.

3. Verifying the fuel transfer pump starts and transfers fuel from the storage system to the day tank.

4. Verifying the diesel starts from ambient condition and accelerates to at least 441 rpm for diesel generators 11 and 12 and 882 rpm for diesel generator 13 in less than or equal to 10 seconds. The ,y oa generator voltaae a frequency shall be 4160 2 416 volts and seconds after the start signal. The diesel ;I j 00 2 1.2 Hz withi ; o0 generator shall be s rted for this test by using one of the f l

following signals: L l

a) Manual.

b) Simulatea loss of offsite power by itself.

c) Simulated loss of offsite power in conjunction with an ESF actuation test signal.

d) An ESF actuation test signal by itself.

5. Verifying the diesel generator is synchronized, loaded to greater than or equal to 3500 kW for diesel generators 11 and 12 and 1650 kW for diesel generator 13 in less than or equal to 60 seconds, and operates,with these loads for at least 60 minutes.

6. Verifying the diesel generator is aligned to provide standby power to the associated emergency busses.

7. Verifying the pressure in all diesel generator air start receivers to be greater than or equal t.o:

a) 160 psig for diesel generator 11 and 12, and b) 175 psig for diesel generator 13.

b. At least once per 31 days and after each operation of the diesel where the period of operation was greater than or equal to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months by checking for and removing accumulated water from the day fuel tanks.

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

'F - p-

) .

13. (GGNS.- 351)

SUBJECT:

Technical Specification 4.8,1.1.2.d.6, page 3/4 8-5.

DISCUSSION: ' The~ load shedding requirements of Surveillance Requirement 4.8.1.1.2.d.6 is only applicable to Diesel Generators 11 and

12. . The text of the requirement should be revised as follows:

6. "" Verifying that.on a simulated loss of the diesel generator, with offsite power not available:

a. For Divisions 1 and 2:

1. The loads are shed from emergency busses associated with Diesel Generators 11 and 12.-

2. Subsequent loading of the diesel generators is in-accordance with design requirements.

b. For Division 3:

1. The associated output breaker for Diesel Generator 13 opens automatically. .

2. Subsequent loading of the diesel generator is in accordance with design requirements."

' JUSTIFICATION: Subsection 8.3.1.1.4.2.5.3 of the Grand Gulf Nuclear Station JFinal' Safety Analysis Report describes the electrical circuit protection provided for :the Division III power supply system.

This subsection states that there is no Joad shedding or ;

. sequencing for the Division III power supply system. The Division III loads. remain on the bus _and the generator breaker opens automatically on a loss of-the' diesel generator to remove the generator from the bus.

Since the' loads on' Diesel Generator'13 are not shed, the text of Surveillance Requirement 4.8.1.1.'2.d.6.should be revised to indicate that the requirement for verifying that the loads are shed from the emergency busses is only applicable to Diesel Cenerators 11 and 12.

1SIGNIFICANT HAZARDS CONSIDERATION:

The surveillance requirement regarding load shedding associated with the diesel generators is not applicable to Diesel Generator i- 13 as there is no load shedding or sequencing from this diesel

-generator. Accordingly, this requirement has been replaced (for Diesel Generator 13 only) by the appropriate surveillance requirement that the output breaker associated with Diesel Generator 13 opens automatically on simulated loss of the 4

l 15F(TS Dump)

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

.'t diesel generator with offsite power not available. This change is therefore purely administrative designed to accurately reflect Division III power system design as described in FSAR Section 8. '; .1.1. 4. 2. 5 . 3 . Therefore, by comparison with NRC example 3 (i) (10 CFR 50, Interim Final Rule, Federal Register, April _6, 1983), amendments that are considered not likely to involve significant hazards considerations the proposed change has no significant hazards considerations.

NOTE: Technical Specification page changes marked with a PCOL number and circled are changes that were previously submitted to the NRC.

I i

l l

l f-f-

i I

l-i l 16F(TS Dump)

\

1Tg.1(GGNs-351)

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

5. Verifying that on an ECCS actuation test signal, wfthout loss of offsite power, the diesel generator starts on the auto-start signal and operates on standby for greater than or equal to 3 5 minutes. The generator voltage a d frequency shall be 4160 t uS 416 volts and 60 1 1.2 Hz withi seconds after the auto-start signal; the steady state generat r voltage and frequency shall be maintained within these limits during this test.

"- ' " ' ^ " ^ - - '

6-

==.:- ::::::- =::: ' ^ 'a' :-:'~ =. ',:^:= : : =: C"n . =::,='"'x (as 1,,sa.vT ' " ' ' '." ' .C: ~ L ' : ':': .'.':l'.'.

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7. Simulating a loss of offsite power in conjunction with an ECCS actuation test signal, and:

a) For Divisions 1 and 2:

1) Verifying deenergization of the emergency busses and load shedding from the emergency busses.

2) Verifying the diesel generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads withig seconds, energizes the auto-

, lg','

h- co'5 nim.e5 'shulifowTloads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the emergency loads.

b gk After energization, the steady state voltage and frequency of the emergency busses shall be maintained i:t 4160 1 416 volts and 60 1 1.2 Hz during this test.

b) For Division 3:

1 1) Verifying de-energization of the emergency bus.

j

2) Verifying the diesel generator starts on the auto-start gy signal, energizes the emergency bus with the permanent 1N-us p connected loads withgi seconds and the autoconnected

~

emer'gency lo'a'ds within 20 seconds and operates for f(/ M ---- greater than or equal to 5 minutes while its generator J$g g is loaded with the emergency loads. After energization as the steady state voltage and frequency of the emergency bus shall be maintained at 4160 1 416 volts and 60 i 1.2 Hz during this test.

8. Verifying that all automatic diesel generator trips are automatically bypassed upon an ECCS actuation signal except:

a) For Divisions 1 and 2, engine overspeed, generator differential current, low lube oil pressure, and generator ground overcurrent.

b) For Division 3, engine overspeed and generator differential current.

GRAND GULF-UNIT 1 3/4 8-5

13.g.2 (GGNS-351)

~ (GGNS'- 351)

6. Verifying that on a simulated loss of the diesel generator, with offsite power not available:

a. For Divisions 1 and 2:

1. The loads are sh d from emergency busses associated with Diesel Generators 11 and 12.

2. Subsequent' loading of the diesel generators is in accordance with design requirements.

b. For Division 3:

1. The associated output breaker for Diesel Generator 13 opens automatically.

2. Subsequent loading of the diesel generator is in accordance with design requirements.

i h

L=

l l

17F(TS. Dump)

14. (CGNS 'X09)

SUBJECT:

Technical Specification 6.5.2.2, page 6-9.

DISCUSSION: Section 6.5.2.2 which describes the composition of the Safety Review Committee, should be revised to reflect recent changes in corporate structure. The Assistant Vice President for Nuclear Production is now called Vice President-Nuclear, the Advisor to the Assistant Vice President, Nuclear Operations is now called the Advisor to the Vice President-Nuclear, and the Manager of System Nuclear Operations, Middle South Services, will be replaced by a qualified representative of System Nuclear Operations.

The final change is to the wording describing the role of consultants to Mississippi Power & Light Company to allow more than two voting consultants on the SRC.

JUSTIFICATION: .13ue changes to the description of the SRC Chairman and indicated members are necessary to reflect changes to the Mississippi Power & Light Company corporate structure. The change in the number of voting consultants is consistent with the recommendations of the Advisory Committee on Reactor Safeguards and will allow greater use of the practical experience of these consultants.

..SIGNIFICANT HAZARDS CONSIDERATION:

The change is an administrative change proposed to reflect changes to the corporate structure of Mississippi Power & Light Company and as such, corresponds to NRC example 3 (i) (10 CFR 50 Interim Final Rule, Federal Register, April 6, 1983),

amendments that are not considered significant hazards considerations. Therefore, this change constitutes no significant hazards consideration.

18F(TS Dump)

i 14.

l ADMINISTRATIVE CONTROLS 6.5.2 ShFETYREVIEWComITTEE(SRC) ,

FUNCTION ,

6.5.2.1 The SRC shall function to provide independent review and audit of designated activities in the areas of:

a. nuclear power plant operations

b. nuclear engineering

c. chemistry and radiochemistry

d. metallurgy instrumentation and control

f. radiological safety

g. mechanical and electrical engineering

h. quality assurance practices COMPOSITION 6.5.2.2 The SRC shall be composed of the:leto.r- l Vics cs dewt Nuc.

Chairman: ;;;;.&.nt (.,i;; Pr;;id:nt ";r ";;1;;r Pr:d;;ti:n l Member: Manager of Nuclear Plant Engineering Member: nager of Quality Assurance Member: N"M of System Nuclear Operations, Middle South Services, l Inc.

Member: Nuclear Plant Manager Member: Manager of Nuclear Services Member: Corporate Health Physicist Member: Principal Engineer, Operations Analysis q , g c, 6 Member:#

Advisor to the ".::i:t:nt Vice-President , L.c.eer Cper; tie.-

orencre.

Two[additionalvotingmembersshallbeconsultantstoMississippiPower and Light Company consistent with the recommendations of the20, Advisory 1981. Committee on P.eactor Safeguards letter, Mark to Palladino dated October The SRC members shall hold a Bachelor's degree in an engineering or physical science field or equivalent experience and a minimum of five years of technical experience of which a minimum of three years shall be in one or more of the disciplines of 6.5.2.la through h. In the aggregate, the membership of the committee shall provide specific practical experience in the majority of the disciplines of 6.5.2.la through h.

ALTERNATES 6.5.2.3 All alternate members shall be appointed in writing by the SRC Chairman to serve on a temporary basis; however, no more than two alternates shall participate as voting members in SRC activities at any one time.

--wh. T4ss elsep. k s 6een nyae sled

= , 3,

? 7 prov: *s ly a rcot. s S to s afs h e/

T'

/ M a. tins (Arcm tvo,po},

GRAND GULF-UNIT 1 6-9

n s

e

15. - (GGNS - X08) .

SUBJECT:

Technical Specification 3.11.1.1, 3.11.1.2, 3.11.2.2, 3.11.2.3, pages 3/4 11-1, 3/4 11-5, 3/4 11-12, 3/4 11-13.

DISCUSSION: The above reference Technical Specifications refer to Figure 5.1.4-1. This reference is incorrect. The correct reference is Figure 5.1.3-1.

JUSTIFICATIGN:. Figure 5.1.4-1 does not exist. Figure 5.1.3-1 is the map of the Unrestricted Area Boundary for Liquid and Gaseous Effluents to which the above reference specifications refer.

SIGNIFICANT HAZARDS CONSIDERATION:

The change is an administrative change proposed to correct an error in the Technical Specification and corresponds to the NRC example 3 (1) (10 CFR 50, Interim Final Rule, Federal Register, April 6, 1983), amendments that are not considered significant hazards considerations. Therefore, this change constitutes no significant hazards consideration.

19F(TS Dump)

=

15. g. L 3/4.11 RADI0 ACTIVE EFFLUENTS 3/4.11.1 LIQUID EFFLUENTS CONCENTRATION

. LIMITING CONDITION FOR OPERATION

=

hl.3-3 3.11.1.1 unrestricted The concentration areas Lof (see Figurgn % ctive

.1.01) shallmaterial be limitedreleased from the site to l to the concentrations specified in 10 CFR Part 20, Appendix 8, Table II, Column 2 for radionuclides other than dissolved or entrained noble gases. For dissolved or entrained noble gases, the concentration shall be limited to 2 x 10 4 microcuries/mi total activity.

APPLICABILITY: At all times.

ACTION:

With the concentration of radioactive material released from the site exceeding the above limits, immediately restore the concentration to within the above limits.

SURVEILLANCE REQUIREMENTS 4.11.1.1.1 The radioactivity content of each batch of radioactive liquid waste shall be determined prior to release by sampling and analysis in accord-The results of pre-release analyses shall be used ance with Table 4.11.1.1.1-1.

with the calculational methods in the ODCM to assure that the concentration a the point of release is maintained within the limits of Specification 3.11.1.1.

4.11.1.1.2 Post-release analyses of samples composited from batch releases The results of the shall be performed in accordance with Table 4.11.1.1.1-1.

previous post-release analyses shall be used with the calculational methods in the ODCM to assure that the i pacestrations at the point of release were .

maintained within the limit ( af 'recification 3.11.1.1.

l GRAND GULF-UNIT 1 3/4 11-1 i

.g

. -f s

15, g. L RADI0 ACTIVE EFFLUENTS; DOSE LIMITING CONDITION FOR OPERATION 3.11.1.2 The dose or dose commitment to an individual from radioactive materials in liquid effluents released, from each reactor unit, from the site (see Figure 0.1.4 1) shall be limited:

.S. I . 3- 1 a.- During any calendar quarter to less than or equal to 1.5 arem to the

~

j, total body and to less than or equal to 5 aren to any organ, and

b. During any calendar year to less than or equal to 3 mrom to the total body and to less than or equal to 10 arem to any organ.

APPLICABILITY: At all times.

ACTION:

a. With the calculated dose from the release of radioactive materials in liquid effluents exceeding any of the above limits, in lieu of any other report required by Specification 6.9.1, prepare and submit to the Commission within 30 days, pursuant to Specifica-tion 6.9.2, a Special Report which identifies the cause(s) for exceeding the 14mit(s) and defines the corrective actions to be taken to ensur( that future releases will be in compliance with Specification 3.11.1.2.

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

SURVEILLANCE REQUIREMENTS Cumulative dose contributions from liquid 4.11.1.2 Dose Calculations.

effluents shall be determined in accordance with the DDCM at least once per 31 days.

E GRAND GULF-UNIT 1 3/4 11-5

, l

f*

RADI0 ACTIVE EFFLUENTS DOSE - NOBLE GASES LIMITING COND'I' TION FOR OPERATION 3.11.2.2 The air dose due to noble gases released in gaseous effluents, from )

each reactor unit, from the site (see Figure 5.1."-1) shall be limited to' the !

following: 5, ! , 3- 1 During any calendar quarter: Less than or equal to 5 mrad for gamma l a.

radiation and less than or equal to 10 mrad for beta radiation, and During any calendar year: Less than or equal to 10 mrad for gamma b.

radiation and less than or equal to 20 mrad for beta radiation.

APPLICABILITY: At all times.

ACTION:

a. With the calculated air dose from the radioactive noble gases in gaseous effluents exceeding any of the above limits, in lieu of any other report required by Specification 6.9.1, prepare and submit to the Commission within 30 days, pursuant to Specification 6.9.2, a Special Report which identifies the cause(s) for exceeding the limit (s) and defines the corrective actions to be taken to ensure that future releases will be in compliance with Specification 3.11.2.2.

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

SURVEILLANCE REQUIREMENTS l

Cumulative dose contributions from gaseous 4.11.2.2 Dose Calculations.

effluants for the current calendar quarter and current calendar year shall be determined in accordance with the ODCM at least once per 31 days.

GRAND GULF-UNIT 1 3/4 11-12

5 I

RADI0 ACTIVE EFFLUENTS DOSE - RADIOI0 DINES. RADICACTIVE MATERIALS IN PARTICULATE FORM, AND TRITIUM LIMITING CONDITION FOR OPERATION 3.11.2.3 The dose to an individual from tritium, radiciodines and radioactive materials in particulate form with half-lives greater than 8 days in gaseous effluents released, from each reactor unit, from the site (see Figure 1.'-1) 2 shall be limited to the following: S.1.31

a. During any calendar quarter: Less than or equal to 7.5 arem to any organ, and During any calendar year: Less than or equal to 15 arem to any b.

organ.

APPLICABILITY: At all times.

ACTION:

a. With the calculated dose from the release of tritium, radiciodines, or radioactive mater.als in paticulate form, with half-lives greater than 8 days, in gaseous effluents exceeding any of the above limits, in lieu of any other report required by Specification 6.9.1, prepare

' and submit to the Commission within 30 days, pursuant to Specifica-tion 6.9.2, a Special Report which identifies the cause(s) for exceeding the limit and defines the corrective actions to be taken to ensure that future releases will be in compliance with Specification 3.11.2.3.

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

SURVEILLANCE REQUIREMENTS i

Cumulative dose contributions from tritium, 4.11.2.3 Dose Calculations.

radiciodines, and radioactive materials in particulate form W h ha'f-lives greater than 8 days for the current calendar quarter and current calendar year shall be determined in accordance with the ODCM at least once per 31 days.

GRAND GULF-UNIT 1 3/4 11-13

ML20076G854

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