Text

Proposed Tech Specs 3/4.3.1 & 3/4.3.2,increasing Surveillance Test Intervals & Allowed Outage Times for RTS & ESFAS Instrumentation
	ML20080J559
Person / Time
Site:	Mcguire, McGuire
Issue date:	01/13/1995
From:	; DUKE POWER CO.
To:	;
Shared Package
ML20080J550	List: ML20080J546; ML20080J559;
References
	NUDOCS 9502270418
	Download: ML20080J559 (44)
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, , ,

,; 3.

4 a .f e

s ATTACHMENT 1 PROPOSED TECHNICAL SPECIFICATION AMENDMENTS FOR MCGUIRE ' (

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= 1 I

I 9502270418 950113 '

l PDR ADOCK 05000369 P PDR l

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3/4.3 INSTRUMENTATION i OR INFORNA N ON y 3/4.3.1 REACTOR TRIP SYSTEM INSTRUMENTATION i

LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the Reactor Trip System Instrumentation channels and interlocks of Table 3.3-1 shall be OPERABLE with RESPONSE TIMES as shown in Table 3.3-2.

APPLICABILITY: As shown in Table 3.3-1. l ACTION:

As shown in Table 3.3-1.

l SURVEILLANCE REQUIREMENTS 4.3.1.I Each Reactor Trip System Instrumentation channel and interlock shall be demonstrated OPERABLE by the performance of the Reactor Trip System ,

Instrumentation Surveillance Requirements specified in Table 4.3-1. l 4.3.1.2 The REACTOR TRIP SYSTEM RESPONSE TIME of each Reactor trip function T shall be demonstrated to be within its limit at least once per 18 months.

/ Each test shall include at least one train such that both trains are tested at '

least once per 36 months and one channel per function such that all channels are tested at least once every N times 18 months where N is the total number of redundant channels in a specific Reactor trip function as shown in the

" Total No. of Channels" column of Table 3.3-1. , l

4. 3.1. 3 The response time of RTDs associated with the Reactor Trip System shall be demonstrated to be within their limits (see note 2 to Table 3.3-2) l at least once per 18 months.

7

)

McGUIRE - UNITS 1 and 2 V4 3-1 Amendment No.130 (Unit 1)

Amendment No.112 (Unit 2)

y TABLE 3.3-1 o

5 REACTOR TRIP SYSTEM INSTRUMENTATION A

. MINIMUM c- TOTAL NO. CHANNELS CHANNELS APPLICABLE 5 FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION d

g 1. Manual Reactor Trip 2 1 2 - 1, 2 1

, 2 1 2 3* , 4* , 5* ' 10 m 2. Power Range, Neutron Flux - High 4 2 3 1, 2 2 Setpoint Low 4 2 3 1,,,, 2 2 Setpoint

3. Power Range, Neutron Flux 4 2 3 1, 2 2 High Positive Rate

4. Intermediate Range, Neutron Flux 2 1 2 1 ,2 3 y 5. Source Range, Neutron Flux gg N a. Startup 2 1 2 2 4

b. Shutdown 2 1 2 3*, 4*, 5* 10

c. Shutdown 2 0 1 3, 4, and 5 5

6. Overtemperature AT NE Four Loop Operation 4 2 3 1, 2 6 (k

sa Three Loop Operation- (**) (**) (**) (**) (**) i,=i go

N y9 35

&5 g2

>~

G$ EN

==

22 .

32 AA 3C fN 1

-____u __k__--_____t__-__- _ _m a u _-- 2 m a T

TABLE 3.3-1 (Continued) '

S '

REACTOR TRIP SYSTEM INSTRUMENTATION -

M t

' MINIMUM TOTAL NO. CHANNELS CHANNELS APPLICABLE E FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

$ 7. Overpower AT i y .

$ Four Loop Operation 4 2 3 -1, 2 6

[ Three Loop Operalfon (**) (**) (**) (**) (**)

8. Pressurizer Pressure-Low 4 2 3 1 6

(***) l

9. Pressurizer Pressure--High 4 2 3 1, 2 6

( ) l q 10. Pressurizer Water Level--High. 3 2 2 1 6

a w 11. Low Reactor Coolant flow 0 a. Single Loop (Above P-8) 3/ loop 2/ loop in 2/ loop in 1 6 any oper- each oper-ating loop ating loop

. b. Two Loops (Above P-7 and 3/ loop 2/ loop in 2/ loop 1 6 l below P-8) two oper- each oper- '

({ ating loops ating loop aa ,

EE 12. Steam Generator Water 4/sta. gen. 2/sta. gen.' 3/sta. gen. 1, 2 6 3$

Level -Low-Low in any oper- each oper- -(^^^)

ating sta. ating sta. l pp gen. .

gen.

CC

3. 3.

c. ~

2 TABLE 3.3-1 (Continued) l !

REACTOR TRIP SYSTEM INSTRUMENTATION

. IR .

. MINIMUM e TOTAL NO. CHANNELS CHANNELS APPLICABLE 2;. FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

, d i g 13. Undervoltage-Reactor Coolant

. Pumps (above P-7) 4-1/ bus 2 3 1 6

~ 5. *1 m 14. Underfrequency-Reactor Coolant Pumps (above P-7) 4-1/ bus 2 3 1 6

15. Turbine Trip r

a. Low Fluid Oil Pressure 3 2 2 1 6

b. Turbine Stop Valve Closure 4 4 1 1 11

16. Safety Injection Input R

from ESF 2 1 2 1, 2 7 ' !

T 17. Reactor Trip System Interlocks

a. Intermediate Range Neutron Flux, P-6 2 1 2 2,, 8

b. Low Power Reactor Trips Block, P-7 P-10 Input 4 2 3 1 8 4.

g ,, or 3g P-13 Input. 2 1 2 1 8 4

k2

. gg c. Power Range Neutron -

22 Flux, P-8 4 2 3 1 8

.P

d. Low Setpoint Power Range Neutron Flux, P-10 4 2 3 ). 2 8 CC s =,, e. Turbine Impulse Chamber

" Pressure, P-13 2 1 2 1 8 00

y. -

W -

TABLE 3.3-1 (ConLinued) l' O

t REACTOR TRIP SYSTEM INSTRUMENTATION M

MININUM c TOTAL NO. CHANNELS CHANNELS- APPLICABLE

$ FUNCTIONAL UNIT OF CHANNELS TO TRIP OPERA 8LE MODES ACTION 1

v

- 18. Reactor Trip Breakers 2 1 2 1, 2 9, 12-

, 2 1 2 3* , 4* , S* 10 o

[ 19. Automatic Trip an'd' Interlock 2 1 2 1, 2 Logic 2 1 2 3*, 4*,

+7 l S* 10 w

w M* '

ER 3a en O

22 aa M

Oc .

TABLE 3.3-1 (Continued) 3 s

TABLE NOTATION A

With the Reactor Trip System breakers in the closed position, the Control Rod Drive System capable of rod withdrawal.

Values left blank pending NRC approval of three loop operation.

-**'7_ _ _ 4 . .,.m .<_ ___..,_1 _,e___, ,__i,__ e , ,

,__ __. ___.,__ ,, ,s,

......n.. . . . . . , . , . . . . . . . . . . _

, w J. ;i. ,. 2!. . . i. . '. 2 ";~'d!'Aen~ois""'elI,T_.~i: ' . .,s, ' . . . ' . " ' ' ' ' ' ' ~ ~~ ~

1. B elow the P-6 (Intermediate Range Neutron Flux Interlock) Setpoint.

Below the P-10 (Low Setpoint Power Range Neutron Flux Interlock) Setpoint.

ACTION STATEMENTS ACTION 1 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 2 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ,

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels per Specification 4.3.1.1, and -

c. Either, THERMAL POWER is restricted to less than or equal to 75% of RATED THERMAL POWER and the Power Range ~ Neutron Flux Trip Setpoint is reduced to less than or equal to 85% of RATED THERMAL POWER within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ; or, the QUADRANT POWER TILT RATIO is monitored at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months per Specification 4.2.4.2.

i i

McGUIRE - UNITS 1 & 2 3/4 3-6 Amendment No. (Unit 1) T Amendment No.1 (Unit 2) 1

j y

l TABLE 3.3-1 (Continued)

ACTION STATEMENTS (Continued) 1 ACTION 3 - With the number of channels OPERABLE one.less than the Minimum I Channels OPERABLE requirement and with the THERMAL POWER level:

a. Below the P-6 (Intermediate Range Neutron Flux Interlock)

Setpoint, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above the P-6 Satpoint, and

b. Above the P-6 (Intermediate Range Neutron Flux Interlock)

Setpoint but below 10% of RATED THERMAL POWER, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above 10% of RATED THERMAL POWER.

ACTION 4 - With the number of 0PERA8LE channels one less than the Minimus Channels OPERABLE requirement suspend all operations involving ;

positive reactivity changes. l ACTION 5-WiththenumberofOPERABLEfchannelsonelessthantheMinimum Channels OPERABLE requirement, verify compliance with the l SHUTDOWN MARGIN requirements of Specification 3.1.1.1 or i 3.1.1.2, as applicable, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and at least once per l 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. '

)

ACTION 6 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied: ,

a. The inoperable channel is placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and

b. The Minimus Channels OPERA 8LE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing of other channels per Specification 4.3.1.1 and Specification.4.3.2.1.

ACTION 7- L';L4 IvfEKr~ A l>

ACTION 8 - With-less than the Minimum Number of Channels OPERA 8LE, within 1 hocr determine by observation of the associated permissive annunciator window (s) that the interlock is in its required state for the existing plant condition, or apply Specification 3.0.3.

)

McGUIRE - UNITS 1 & 2 3/4 3-7 Amendment No. Unit 1)

Amendment No. p ((Unit 2)

= . . - _ _ _ _ _ _

p.' ,:;.

i INSERT A for Page 3/4 3-7:

With the number of OPERABLE Channels one less that the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing per Specification 4.3.1.1, i provided the other channel is OPERABLE. :

i 4

l i

l

l

.. l TABLE 3.3-1 (Continued)

ACTION STATEMENTS (Continued)

ACTION 9 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, be in at least HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; however, one channel may be bypassed for up to 4 -t-hours for surveillance testing per Specification 4.3.1.1, provided the other channel is OPERABLE. [

ACTION 10 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or open the Reactor trip breakers within the next hour.

ACTION 11 - With the number of OPERABLE channels less than the Total Number of Channels, operation may continue provided the inoperable channels are placed in the tripped condition within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 12 - With one of the diverse trip features (Undervoltage or shunt trip attachment) inoperable, restore it to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or declare the breaker inoperable and apply ACTION 9. The breaker shall not be bypassed while one of the diverse trip features is inoperable except for the time required for performing maintenance to restore the breaker to OPERABLE status.

7 1

McGUIRE - UNITS I and 2 3/4 3-8 Amendment No. (Unit 1)

Amendment Nn 1Av (lini t - 7 )

, ._- 'a l '.

2 TABLE 3.'3-2 .

E>

S REACTOR TRIP SYSTEM INSTRUMENTATION RESPONSE TIMES A

[ FUNCTIONAL UNIT RESPONSE TIME 5

d 1. Manual Reactor Trip N.A.

2. Power Range, Neutron Flux 50.5 second (1) a Power Range, NeutredFlux, m 3.

High Positive Rate N.A.

4. Intermediate Range, Neutron Flux N.A.

5. Source Range, Neutron Flux N.A.

6. Overtemperature AT $10.0 seconds (1)(2)

7. Overpower AT 510.0 seconds (1)(2)

E 8. Pressurizer Pressure--Low 12.0 seconds

9. Pressurizer Pressure--High 12.0 seconds

10. Pressurizer Water Level--High N.A.

.N .N hh (1) Neutron detectors are exempt from response time testing. Response time of the neutron flux signal portion ga of the channel shall be measured from detector output or input of first electronic component in channel.

en (2) The 5 10.0 second response time includes a 6.5 second delay for the RTDs mounted in thermowells.

E5 mm

, -. go -

M iiE G2 EE S. S. EG sn

=a ro e

-- EE o =;g

=

,; )

I

[

.y TABLE 3.3-2 (Continued)

C -

% REACTOR TRIP SYSTEM INSTRUMENTATION RESPONSE TIMES 8

E FUNCTIONAL UNIT RESPONSE TIME d

, 11. Low Reactor Coolant Flow

$ a. Single Loop (Above P-8) 5 1.0 second m b. Two Loops (Ab,ove P-7 and belcw P-8) s 1.0 second

12. Steam Generator Water Level--Low-Low -s 3.5 seconds l

13. Undervoltage-Reactor Coolant Pumps < l.5 seconds

14. Underfrequency-Reactor Coolant Pumps < 0.6 second

15. Turbine Trip w a. Low Fluid Oil Pressure N.A.

2 b. Turbine Stop Valve Closure N.A.

16. Safety. Injection input from ESF N.A.

17. Reactor Trip System Interlocks . N.A.

18. Reactor Trip Breakers N.A.

kk 19. Automatic Trip and Interlock Logic N.A.

R5 o5 gg EE

=a

.a =

NN

~ Eiil m

CC 0h 2

q,4 E. S.

nn Ad

~

_ v _

2 TABLE 4.3-1

, REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS

$ TRIP c ANALOG ACTUATING . MODES FOR 2 CHANNEL DEVICE- WHICH g CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE g FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST IS REQUIRED ;

~

[ 1. Manual Reactor Trip,3 N.A. N.A. N.A. R (11) N.A. 1, 2, 3^ , 4* , 5*

2. Power Range, Neutron Flux High Setpoint S D(2,4), -ft-Q N.A. N.A. 1, ' 2 M(3,4), !

Q(4,6)..

R(4,5)

Low Setpoint S R(4) -ft-f[U [l) N.A. N.A. 1 ,2 D 3. Power Range, Neutron Flux, _

N.A. R(4) 4t- R '

N.A. N.A. 1, 2 High Positive Rate

4. Intermediate Range, S R(4, 5) S/U(1)h H.A. N.A. l ,2 l Neutron Flux 8['d yy

5. Source Range, Neutron Flux S R(4,5) S/U(1),4t(9t- N.A. N.A. 2 , 3, 4, 5

6. Overtemperature AT S R(15) -ft- Q - N. A. N.A. 1, 2

7. Overpower AT S R(15) 1t-R N.A. N.A. 1, 2

. 5E 8. Pressurizer Pressure--Low S R 4t- R N.A. N. A. 1 2z

?? 9. Pressurizer Pressure--High S R 46- A N.A. N.A. 1, 2

10. Pressurizer Water Level--High S R 4t-R N.A. N.A. 1 S h 11. Low Reactor Coolant Flow S R 46- Q N.A. N.A. 1 e=

1

s. _ _ _.______.____.._.____s.__ _ ._s_ _ _ _ _ _ . . _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ . . _______-______m__ = _ - _ - __ _ _ _ - - - - - <

,a R

g IABLE 4.3-1 (Continued) 4 S

5 REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS El

, TRIP c_ ANALOG ACTUATING MODES FOR

$ CHANNEL DEVICE WHICH g CilANNEL CHANNEL OPERATIONAL OPERATIONAL ~ ACTUATION SURVEltLANCE g FUNCTIONAL UNIT CilECK CALIBRATION TEST TEST LOGIC IEST IS REQUIRE 0 c.

R 12. Steam Generator Water Level--' S R -M- Q N.A. N.A. 1, 2 [

0 m Low-low

13. Undervoltage - Reactor Coolant N.A. R N.A. -M-- Q N.A. 1

[

Pumps

14. Underfrequency - Reactor N.A. R N.A. -M-Q N.A. 1 l

Coolant Pumps w

} 15. Turbine Trip y a. Low fluid Oil Pressure N.A. R N.A. S/U(1, 10) N.A. 1 C b. Turbine Stop Valve Closure H.A. R N.A. S/U(1, IU) N.A. I

16. Safety Injection Input from H.A. N.A. N.A. . R N.A. 1, 2 ESF

,, 17. Reactor Trip System Interlocks

!O a. Intermediate Range ##

Neutron Flux, P-6 N.A. R(4) -M-A/4 N.A. N.A. 2

'h.

t,

' p, b. Ls ."; ;. L . J.u.

2 Trip Sh d , F7 M .". R(':) ." (S) M.A. ii. A. i

c. Power Range Neutron b, Flux, P-8 N.A. R(4) F. (0) /V 4 N.A. N.A. I 12

. E.

, c.

w

w TABLE 4.3-1 (Continued) :.~k 8 REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS ,

3 TRIP

' MODES FOR ANALOG ACTUATING E CHANNEL DEVICE WHICH Q CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST 15 REQUIRED

[

a - Low Setpoint Podek Range C. Neutron Flux, P-10 N.A. R(4) " (0) Mj$, N. A. N.A. 1, 2 Turbine Impulse Chamber d Pressure, P-13 N.A. R " (0) N. A, N.A. N.A. I N.A. N.A. N.A. M (7, 12) N.A. 1, 2 , 3 * , 4 * , 5 *

18. Reactor Trip Breaker

19. Automatic Trip and 1, 2, 3* , 4 * , 5*

Interlock Logic N.A. N.A. N.A. N.A. H (7)

{

T 20. Reactor Trip Bypass M (13), R (14) N.A. 1, 2, 3 * , 4 * , 5

O Breakers N.A. N.A. N.A.

EE a

RR 8

ee OO S. 3.

ee i

w.

TABLE 4.3-1 (Continued) i TABLE NOTATION With the Reactor Trip System breakers closed and the Control Rod Drive System capable of rod withdrawal.

Below P-6 (Intermediate Range Neutron Flux Interlock) Setpoint.

Below P-10 (Low Setpoint Power Range Neutron Flux Interlock) Setpoint.

31 (1) -

If not performed in previous t days. g.

(2) -

Comparison of calorimetric to excore power indication above 15% of ;

Adjust excore channel gains consistent with RATED THERMAL POWER.

calorimetric power if absolute difference is greater than 2%. The provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(3) -

Single point comparison of incore to excore axial flux difference l above 15% of RATED THERMAL POWER. Recalibrate if the absolute difference is greater than or equal to 3%. The provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(4) -

Neutron detectors may be excluded from CHANNEL CALIBRATION.

l (5) -

Detector plateau curves-shall be obtained, evaluated, and compared to manufacturer's data. For the Intermediate Range and Power Range Neutron Flux channels the provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(6) - Incore - Excore Calibration, above 75% of RATED THERMAL POWER. The provisions of Specification 4.0.4 are not applicable for entry into I

MODE 2 or 1.

(7) - Each train shall be tested at leest every 62 days on a STAGGERED ,

TEST BASIS. l (8) -

h er than or equal to the interlo e i required operationai w t hall c er fying that the in k 5 . ate W he permissive f 8.va e4wAv (9) -

. sthi,7 surveillance in MODES 3*, 4* and 5* shall also include verification that permissives P-6 and P-10 are in their required state for existing plant conditions by observation of the permis-sive annunciator window. ." =thi- surveillance shall include l verificationoftheHighFluxathhutdownAlarmSetpointofless than or equal to five times background.T Qua r+cdf (10) - Setpoint verification is not required.

McGUIRE - UNITS 1 and 2 3/4 3-14 Amendment No.1 (Unit 1) j Amendment No. (Unit 2) )

'"1 F

NO CNANGES THl3 PAGE L_ ON0Nty TABLE 4.3-1 (Continued)

TABLE NOTATION (11) - The TRIP: ACTUATING OEVICE OPERATIONAL TEST shall independently verify the OPERABILITY of the undervoltage and shunt trip circuits for the Manual Reactor Trip Function.

(12) - The TRIP ACTUATING DEVICE OPERATIONAL TEST shall independently verify the OPERABILITY of the undervoltage and shunt trip attachments of the Reactor Trip Breakers.

(13) - Prior to placing breaker in service, a local manual shunt trip shall be performed.

(14) - The automative undervoltage trip capability shall be verified operable.

(15) -

Overtemperature setpoint, overpower setpoint, and T,yg channels re- .

2 quire an 18 month channel calibration.

Calibration of the AT channels is required at the beginning of each cycle upon completion of the precision heat balance of Surveillance 4.2.3.5. RCS loop AT values shall be determined by precision heat balance measurements.at the.

beginning of each cycle in connection with Surveillance 4.2.3.5.

1

' O.

l l

l

) 1 McGUIRE - UNITS 1 and 2 3/4 3-14a Amendment No. 131 (Unit 1) ,

Amendment No.113 (Unit 2)

l NO CHANGES THIS par" FOR INFORMATION Oh INSTRUMENTATION '

{

3/4.3.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION LIMITINC CONDITION FOR OPERATION '

3.3.2 The Engineered Safety Features Actuation System (ESFAS) Instrumentation channels and interlocks shown in Table 3.3-3 shall be OPERABLE with their Trip Setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3-4 and with RESPONSE TIMES as shown in Table 3.3-5. l APPLICABILITY: As shown in Table 3.3-3.

l ACTION:

a. With an ESFAS Instrumentation channel or interlock Trip Setpoint less conservative than the value shown in the Allowable Values column of Table 3.3-4, declare the channel inoperable and apply the i applicable ACTION requirement of Table 3.3-3 until the channel is I restored to OPERABLE status with the Trip Setpoint adjusted consistent with the Trip Setpoint value. ,

b. With an ESFAS Instrumentation channel or interlock inoperable, take the ACTION shown in Table 3.3-3.

) SURVEILLANCE REQUIREMENTS I i

4.3.2.1 Each ESFAS Instrumentation channel and interlock and the automatic actuation logic and relays shall be demonstrated OPERABLE by the performance of the ESFAS Instrumentation Surveillance Requirements specified in Table 4.3-2. l 4.3.2.2 The ENGINEERED SAFETY FEATURES RESPONSE TIME of each ESFAS function shall be demonstrated to be within the limit at least once per 18 months.

Each test shall include at least one train such that both trains are tested at least once per 36 months and one channel per function such that all channels are tested at least once per N times 18 months where N is the total number of redundant channels in,a specific ESFAS function as shown in the " Total No. of Channels" column of Table 3.3-3.

.]

MCGUIRE - UNITS 1 AND 2 3/4 3-15 Amendment No.130 (Unit 1) l Amendment No.112 (Unit 1)

. x 2 TABLE 3.3-3 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION El c MINIMUM z .

TOTAL NO. CHANNELS CHANNELS APPLICABLE g FUNCTICNAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

, 1. Safety Injection, Rqactor g Trip, Feedwater Isotalion, y Component Cooling Water, Start Diesel Generators, and Nuclear Service Water

a. Manual Initiation 2 1 2 1,2,3,4 18 m b. Automatic Actuation 2 1 2 1,2,3,4 14

} Logic and Actuation y Relays

c. Containment 3 2 2 1,2,3 15 l Pressure-High

d. Pressurizer 4 2 3 1,2,3 19 l Pressure - Low-Low g3 e. Steam Line Pressure-Low j$

Four Loops 3/ steam line 2/ steam line 2/ steam line 1,2,3 15 l gy Operating in any steam gg ne line > **

zz :!E FF Three Loops (**) (**) '(**) (**) (**)

gm Operating ar e,

i. G E" i 22 El r+ r NH vv

. - _ - - - _ _ _ . - __ - _ _ . _ - _ - - - ------____..----_--__------_---.--.__-----__._-----_--n- - - , , - , - - ,

? ,

^

TABLE 3.3-3 (Continued) n

@ ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION E

m MINIMUM E TOTAL NO. CHANNELS CHANNELS APPLICABLE FUNCIl0NAL UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION

}

7. Auxiliary feedwater (continued) y *6

f. Station Blackout (Note 1)

Start Motor-Driven Pumps

[

and Turbine-Driven Pump 6-3/ Bus 2/ Bus 2/ Bus 1, 2, 3 19 Either Bus

g. Trip of All Main Feedwater Pumps Start Motor-

{ Driven Pumps 2-1/MFWP 2-1/MfWP 2-1/MFWP 1, 2 27 M T 8. Automatic Switchover to O Recirculation RWST Level 3 2 2 1,2,3 15 k l

9. Loss of Power 4 kV Emergency Bus Undervoltage-Grid 3/ Bus 2/ Bus 2/ Bus' 1, 2, 3, 4 15a [

,E ,s Degraded Voltage oo R-Pi 10. Engineered Safety Features na Actuation System Interlocks Pressurizer Pressure, 3 2 2 1, 2, 3 20 22 a.

PP P-11

b. 4 2 3 1,2,3 20 Low-Low T,,g, P-12 Reactor Trip, P-4 1,2,3 22

?E

. ~ .

c. 2 2 2

"" d. Steam Generator 3/sta gen. 2/sta gen. 2/sta gen. 1, 2, 3 20

$C L evel , P- 14 in any in each operating operating sta gen. stm gen.

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

wy . .~ .-

q .. .,

ieJ

.}

TABLE 3.3-3 (Continued) ;

, TABLE NOTATION-i I

'# Trip function'may be blocked in this MODE below the P-11 (Pressurizer Pressure Interlock) Setpoint.

r ##T rip function automatically. blocked above P-11 and may be blocked below 4

P-11 when Safety Injection on low steam pressure is not blocked. ;

- These values left blank pending'NRC approval of three loop operation.

[

Note 1: Turbine driven auxiliary feedwater pump will not start on a blackout . ;

signal coincident with a safety injection signal.

ACTION STATEMENTS l 3

ACTION 14 With the number of OPERABLE channels one less than the' Minimum .

Channels OPERABLE requirement, be in at least HOT STANDBY .

w

_ithin g hours and in COLD SHUTDOWN within the following s.p . -!

/F 30 nours; however, one channel may be bypassed for up to-E-h,ours '

for surveillance testing per Specification 4.3.2.1, provided !

the other channel is OPERABLE. -

ACTION 15 . With the number of OPERA 8LE channels one less than the Total l Number of Channels, operation may proceed until performance of ^

) the next required.0PERATIONAL TEST provided the inoperable i channel is placed in the tripped condition within 1 M _r. g.

Gkoves 1 ACTION 15a With.the number of OPERABLE channels less than the total Number i of Channels, operation may proceed until performance of the qu next required OPERATIONAL TEST provided the inoperable channel is With mo in the tripped inoperable, entercondition Specificationwithin 1.%.. k g,.re 3.8.1.1 ,. than one channe INSERT b l, With the number of OPERABLE channels one less than the Total ACTION 16

. Number of Channels, operation may proceed provided the inoperable channel is placed in the bypassed condition and the Minimum j Channels OPERABLE requirement is met. One additional channel I may be bypassed for up to 4-hours for surveillance testing per l

-Sper,ification 4.3.2.1. 4 ACTION 17 With less than the Minimum Channels OPERABLE requirement, operation may continue provided the containment purge supply and exhaust valves are maintained closed.

)

McGUIRE - UNITS 1 and 2 3/4 3-23 Amendment No. (Unit l) ,

^

Amendment No. '(Unit 2) l

_ - _ , ,m . , . . -

4 INSERT B for Page 3/4 3-23:

ACTION 15b With the number of OPERABLE channels one less than -

the total number of channels, operation may proceed until performance of the next required OPERATIONAL TEST provided the inoperable channel is placed in the tripped condition within I hour.

t t

9 l

l i

I l

l I

TABLE 3.3-3 (Continued)

ACTION STATEMENTS (Continued)

ACTION 18 - With the number of OPERA 8LE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANOBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUT 00WN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

ACTION 19 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are satisfied:

a. The inoperable channel is placed in the tripped condition within I h u , and

4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .r !

b. TheMinimumChannelsOPERABLErequirementismet[Y however, the inoperable channel may be bypassed for up to-2-nours g for surveillance testing of other channels per Specific.a- c tion 4. 3. L1 and Spec i fication 4. 3.2.1. 5 i

ACTION 20 - With less than the Mini um Number of Channels OPERABLE, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months determine by observation of the associated permissive annunciator window (s) nat the interlock is in its required state for the existing plant condition, or apply Specification 3.O.3.

ACTION 21 - With the number of OPECHLE Channels one less than the Minimum A hannels OPERABLE requirement hbe in at least HOT STANDBY (etitrr4c, Lofans6b withiqv6 hours and in at least HOT SHUT 00WN within the following Chaee.l to 07F/A A s- F6 houTs; however, one crannel may be bypassed for up to M ours i for surveillance testing per Specification 4.3.2.1 providedithe s+s.4 9 J W rt b k. (3 hwer er other channel is OPERABLE. Y ACTION 22 - With the number of OPERABLE channels one less than the Total dencyf Number of Channels, restare the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months ar be in at least HOT STANOBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least 07 SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

ACTION 23 - With the number of OPE;t. ate channels one less than the Total Number of Channels, restare the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or declare the associated valve inoperable and take the action required by Specification 3.7.1.4.

ACTION 24 - With the number of OPERABLE channels less than the Total Number of Channels, restorc the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or declare the associated auxiliary feedwater pump inoperable and take the action required by Specifica-tion 3.7.1.2. With'the channels associated with more than one auxiliarv feedwater pump inoperable, immediately declare the associated auxiliary feedwater pumps inoperable and take the action required by Specification 3.7.1.2.

Amendment No. (Unit 2)

McGUIRE - UNITS 1 and 2 3/4 3-24 Amendment No.' (Unit 1)

4 -

TABLE 3.3-4 (Continued) 2 p

O ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TRIP SETPOINTS E

TRIP SETPOINT ALLOWABLE VALUES

[ FUNCTIONAL UNIT

=

g 8. Automatic Switchover to Recirculation 1 90 inches > 80 inches

[ RWST Level 5 9. Loss of Power '1 y

4 kV Emergency Bus Undervoltage- 3464 i 173 volts with a 1 3200 volts Grid Degraded Voltage 8.5 1 0.5 second time delay

10. Engineered Safety Features Actuation m

System Interlocks Pressurizer Pressure, P-ll $ 1955 psig 5 1965 psig a.

Y U$ b. T 2 1 5534 1 5514 avg, N.A. N.A.

c. Reactor. Trip, P-4 5b I

d. Steam Generator Level, P-14 SeeIteng.aboveforallTripSetpointsandAllowable Values.

FE

{ { Note 1: The turbine driven pump will not start on a blackout signal coincident with a safety injection signal.

55 aa

~o CC 1 3.

sn e

w 2 TABLE 4.3-2 E

C E ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS g TRIP ANALOG ACTUATING MODES m

CHANNEL DEVICE MASTER SLAVE FOR WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE g FUNCTIONAL UNIT i3 CHECK CALIBRATION TEST TEST LOGIC TEST TEST TEST IS REQUIRED

[ 1. Safety-Injection Reactor Trip, feedwater Isolation, Component Cooling Water, Start Diesel Generators, and Nuclear Service Water

a. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3, 4

, b. Automatic Actuation N.A. N.A N.A N.A. M(1) M(1) Q 1,2,3,4 g Logic and Actuation

, Relays h c. Containment Pressure- S R. -M- R N.A. N.A. N.A. N.A. 1, 2, 3 High .

g 1

d. Pressurizer Pressure- S R -M- A N.A. N.A. N.A. N.A. 1, 2, 3 g Low-Low

e. Steam Line S R -ft- Q N.A. N.A. N.A. N.A. 1, 2, 3 Pressure--Low l

2. Containment Spray

a. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3, 4 .,

} b. Automatic Actuation N.A. N.A. N.A. N. A.' M(1) M(1) Q 1, 2,-3, 4 f

Logic and Actuation .

% Relays

c. Containment Pressure-- S R -ft-Q N.A. N.A. N.A. N.A. 1, 2, 3 High-High l

.b

h. C y GA - - - - - ... - . . - .

v. ~

3:

TABLE 4.3-2 (Continued)

{

T ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENT SURVEILLANCE REQUIREMENf5 c TRIP 3 ANALOG ACTUATING 5 CllANNEL DEVICE MODES CHANNEL CHANNEL MASTER LLAVE FOR WHICil

- FUNCTIONAL UNIT CilECK OPERATIONAL OPERATIONAL ACTUATION RELAY o,

'% CALIBRATION TEST TEST RELAY SURVEfttANCE a _ to'~~ TEST TEST _1E S T IS REQUIRED

[3.ContainmentIsolation

a. Phase "A" Isolation i

1) Hanual Initiation N.A. N.A. N.A. R N.A. N.A. N.A.

2) Automatic Actua- N.A. N.A. N.A.

1, 2, 3, 4 tion Logic and N.A. M(1) M(1) Q 1, 2, 3, 4 Actuation Relays

3) Safety Injection

b. Phase "B" Isolation See Item 1. above for all Safety Injection Surveillance Requireuents.

{

y 1) Manual Initiation N.A. N.A. N.A. -

$ 2) Automatic Actua- N.A.

R N.A. N.A. N.A. 1, 2, 3, 4 N.A. N.A. N.A.

tion Logic and M(1) M(1) Q 1, 2, 3, 4 !

Actuation Relays

3) Containment S R Pressure-High-High -ft- Q N.A. N.A. N.A. N.A. 1, 2, 3

.b g

c. Purge and Exhaust

, Isolation ~

1) Manual Initiation N.A. N.A. N.A. R N.A. N.A. !!. A.

4 2) Automatic Actua- N.A. N.A. N.A.

1, 2, 3, 4 tion Logic and N.A M(1) M(1) Q I , 2, 3, 4 -

~f p Actuation Relays

3) Safety Injection See Item 1. above for all Safety injection Surveillance Requirements.

mS CC t.?.

4+

E/ D

TABLE 4.3-2 (Continued)

?

c)

ENGINEEREO SAFETY FEATHRES ACTUATION SYSTEM INSTRUMENTATION rn SURVEILLANCE REQUIREMENTS TRIP g ANALOG ACTUATING MODES q CHANNEL DEVICE MASTER SLAVE FOR WHICH un CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE

- FUNCTIONAL UNIT CALIBRATION lEST CHECK TEST LOGIC TEST TEST TEST IS REQUIRED

o. t6 m 4. Steam Line Isolation

a. Manual Initiation N.A. N.A. N.A. R N.A. N.A. N.A. 1, 2, 3

b. Automatic Actuation N.A. N.A. N.A. N.A. M(1) M(1) Q 1,2,3 Logic and Actuation Relays

c. Containment Pressure-- S R -M-- $ N.A. N.A. N.A. N.A. 1, 2, 3 g

, High-High A d. Negative Steam Line S R +Q N.A. N.A. N.A. N.A. 3 g y Pressure Rate-High

$ e. Steam Line S R +R N.A. N.A. N.A. N.A. 1,2,3 l

Pressure--Low

5. Turbine Trip and Feedwater Isolation

a. Automatic Actuation N.A. N.A. N.A. N.A. M(1) M(1) Q 1, 2

,, Logic and Actuation N'I'Y M[d M(d R

($

gg b. Steam Generator Water S R -tt- Q N.A. M -ft-A- -th*-- 1, 2j 3 g gg Level-High-High (P-14)

(( 6. Containment Pressure Control System Start Permissive /. S R M N.A. N.A. N.A. N.A. 1, 2, 3, 4 ,I .'

Termination ,

3. 3. <

r. <+

v

~

TABLE 4.3-2 (Continued) .=

g ENGINEEREO SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION g SURVEILLANCE REQUIREMENTS s "o

m TRIP ANALOG ACTUATING e -MODES CHANNEL DEVICE

$ CHANNEL CNANNEL OPERATIONAL OPERATIONAL ACTUATION MASTER SLAVE FOR WHICH d FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST RELAY LOGIC TEST TEST RELAY SURVEILLANCE-TEST IS REQUIRED

{E 7. Auxiliary Feedwater, ,

a. Manual Initiation N.A. N.A. N. A. R N. A. N.A. N.A. 1, 2, 3

b. Automatic Actuation N.A. N.A. N.A. N.A. M(1) M(1) 1,2,3 Logic and Actuation Q Relays

c. Steam Generator Water S R N.A.

-M-- A N. A. N. A N.A. 1, 2, 3 Level--Low-Low l w d. Auxiliary Feed =ater N.A. R N.A. R N.A. N.A. N. A. 1, 2, 3 1 Suction Pressure-to=

e. Safety Injection See Item 1. above for all Safety injection Surveillance Requirements

{

f. Station Blackout N.A. N.A. N.A R N.A. N.A. N.A. 1, 2, 3

g. Trip of Main Feedwater N.A. N.A. N.A. R N.A. N.A. N.A 1, 2 Pumps

8. Automatic Switchover to gg Recirculation

$S aa RSWT Level S R M N.A. N.A. N.A. N.A. 1,2,3 jj 9. Loss of Power 4 kV Emergency Bus N.A. R N.A. M N.A. N.A. N.A 1, 2, 3, 4 IE Undervoltage-Grid Degraded Voltage ee 3:

2C w

O TA8tE 4.3-2 (Continued)

! E ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUNENTATION E

l m SCXILLANCE REQUIREMENTS TRIP

! c ANALOG ACTUATING E CHANKEL DEVICE N00ES N NASTER SLAVE FOR letICH l CHAletEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE

- FuMCTIONAL LNIT CIECK CALIBRATION TEST TEST LOGIC TEST TEST TEST 15 REQUIRED h 10. Engineered Safety *6

" Features Actuatloa system Interleclis

a. Pressurizer N.A. R +q N.A. N.A. N.A. N.A. 1, 2, 3 i Pressure. P-ll I

b. t ow-Low T,,,, P-12 N.A. R -M- Q N.A< N.A. M.A. N.A. 1, 2, 3 l

A c. Reactor Trip, P-4 N.A. N.A. N.A. H N.A. M.A. M.A. 1, 2, 3 l Y >

g d. Steam Generator Leviel, P-14 5 G :: . t.. =; =g3 n 1, 7, 3_ g Jee, ItPm Cb for etN Se edllc.nw re y d re,w e w h ,

ff f

,I an N. .N

^^

n

~~

s,v

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

,j.h . y '

l f ,

3/4.3 INSTRUMENTATION

. BASES-r }

l 3/4.3.1'and 3/4.3.2 REACTOR TRIP AND ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION ,

The OPERABILITY of the Reactor Trip and Engineered Safety Features

- Actuation System instrumentation and interlocks ensure that: (1) the.

associated ACTION and/or Reactor trip will be initiated when the parameter monitored by each channel or combination thereof reaches its Setpoint (2) the ;

-specified. coincidence logic and sufficient redundancy is maintained to permit C :

a channel to be out-of-service for testing or maintenance consistent with- ;

maintaining an appropriate level of reliability of the Reactor Protection and )J !

-Engineered Safety Features Instrumentation and (3) sufficient system functions [

capability is available from diverse parameters, g .

The OPERABILITY of these systems is required to provide the overall 4

reliability, redundancy, and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions. !'

' The integrated operation of each of these sy dens is consistent with the assumptions used in the accident analyses. The Surveillance Requirements specified for these systems ensure that the overall system functional .

capability is maintained comparable to the original design standards. -The '

periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability.

SpecifiedsurveillanceinterYalsandsurveillanceandmaintenanceoutage

,~ times have been determined in accordance with WCAP-10271, " Evaluation of Sur- yo {i veillance Frequencies and Out of Service Times for the Reactor Protection 5 i

Instrumentation System," and supplements to that report. Surveillance inter--

vals and out of service times were determined based on maintaining an appro-priate l'evel of reliability of the Reactor Protection System and Engineered

.k( i MTEKT"C p!

darety Features instrumentatio M (Ie rla......t.Me.. 7 v..t..l i teat l.y .7 US i f

i: 5:in; ;::t;:n;d ;ntP ;ft:r ;peren ef ;. ;isi'.er ;;;;ic.; int;r.;.1 f;r i.i

TA;. ) T7.. ::: 0.f.;, C.e b.G... " r.. ; f.. UCAT 1001 -.; p. .. id:d i n :. I , ~'

?:tt:r d:t:d Strnry 21,1000 fre; C. 0.- It.ese; 00") ;. J. J. Ot.espece i*

(WOO Cri.L). y The measurement of response time at the specified frequencies provides l assurance that the Reactor trip and the Engineered Safety Feature actuation 4 associated with each channel is completed within the time limit assumed in the i accident analyses. No credit was taken in the analyses for those channels '

with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping, or total channel test measurements provided that such tests demonstrate the total channel response time as defined. -Sen r response time verification may be demonstrated by either: (1) in place *onsite, or offsite test measurements, or (2) utilizing ,

replacement sensors"with certified response times.

j' The Engineered Safety Features Actuation System senses selected plant parameters and determines whether or not predetermined limits are being exceeded. If they are, the signals are combined into logic matrices sensitive to comb'inations indicative of various accidents, events, and transients. Once j

the required logic combination is completed, the system sends actuation signals t'o those Engineered Safety Features components whose aggregate l

function best serves the requirements of the condition. As an example, the !

t McGUIRE - UNITS 1 and 2 B 3/4 3-1 Amendment No (Unit 1)

Amendment No Unit 2) ,

d

-e-r,, , , ,- n , --- -

INSERT C for Page B 3/4 3-1:

The NRC Safety Evaluation Reports for the WCAP-10271 series were provided in letters dated February 21, 1985 from C. O. Thomas (NRC) to J. J.

Sheppard (WOC). Febr.uary 22, 1989 from C. E. Rossi (NRC) to R. A. Newton (WOG), and April 30, 1990 from C. E. Rossi (NRC) to G. T. Coering (WOG).

l N

as

0

e N0 CHANGES THl3 PAGE Ail 0N 0NL/

INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 REACTOR TRIP AND ENGINEEREO SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION (Continued) -

following actions may be initiated by the Engineered Safety Features Actuation System to mitigate the consequences of a steam line break or loss-of-coolant accident: (1) Safety Injection pumps start and automatic valves position, (2) Reactor trip, (3) feedwater isolation, (4) startup of the emergency diesel generators, (5) containment spray pumps start and automatic valves position, (6) containment isolation, (7) steam line isolation, (8) Turbine trip, (9) auxiliary feedwater pumps start and automatic valves position, and (10) nuclear service water pumps start and automatic valves position. ,

i Technical Specifications for the Reactor Trip Breakers and the Reactor. Trip Bypass Breakers are based upon NRC Generic l'etter 85-09 " Technical Specifica- i tions for Generic Letter 83-28, Item 4.3," d4,ted May 23, 1985. ,

i l

7 McGUIRE - UNITS I and 2 B 3/4 3-la Amendment NoJa(Untt 1).

Amendment No35(Un t t 2)

.-4

.t ATTACil\ LENT 2 BACKGROUND AND DESCRil' TION OF AMENDMENT REQUEST O

l i

I

C l

]

4 Background' I The purpose of this Technical Specification amendment request is to obtain relaxation regarding the con ~ duct of surveillance testing of the Reactor Trip System (RTS) and Engineered Safety Features ' Actuation System (ESFAS). As a result of concem of the impact of existing testing and maintenance requirements on plant operation, particularly in the area of instmmentation, the Westinghouse Owners Group (WOG) initiated a program to develop justification to be utilized in revising individual plant Technical Specifications. Operating plants have experienced many inadvertent reactor trips and safeguards actuations during performance of instrumentation surveillance, causing unnecessary transients and challenges to plant safety systems. Significant time and effort on the part of the plant staff was devoted to performing, reviewing, documenting, and tracking various surveillance activities, which in many instances appeared unwananted based on the high miiability of the equipment.

'Significant benefits for operating plants appeared to be achievable through revision of instrumentation test and maintenance requirements. A complete chronology of the' WOG ,

l efforts and interactions with the NRC is contained in a document titled " Westinghouse Owners i Group Guidelines for Preparing Submittals Requesting Revision of Reactor Protection System Technical Specifications Based on Generic Approval of WCAP-10271 and Supplements" (TOPS Guidelines - August 1990).

Description of Amendment Request '

The list of Technical Specification changes included in this amendment request is as follows:

(a) Otanges as described in the marked-up copy of Technical Specification 3/4.3.1 (Attachment 4). These changes include:

(i) 'Ihe surveillance test interval in Table 4.3-1 for functional unit 17, Reactor Trip System Interlocks, Analog Channel Operational Test, is changed from monthly to "R" (at least once per 18 months) for each of the interlocks. Note that for functional unit 17, Reactor Trip System Interlocks, the testing required by the channel calibration encompasses the testing mquired by the analog channel operational test. Hence, the ACOT surveillance frequency is being changed to "N.A.", since this requirement will be covered by the channel calibration. -

(ii) Increase in surveillance intervals for Reactor Trip System (P.TS) analog channel operational tests from once per month to once per quarter.

(iii) In Table 33-1, new ACTION 7 is added to allow 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to restore an inoperable channel to operable status before requiring shutdown to HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to allow bypass of a channel for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for surveillance testing, provided the other channel is OPERABLE.

Make new ACTION 7 applicable to functional units 16 (Safety Injection Input from ESF) and 19 (Automatic Trip and Interlock Logic), rather than ACTION 9.

I

\

y~

f.& ' < . li; i

(iv) I In Table 3.3-1. ACrlON 9 is modified to change the 2-hour allowance for -}

bypassing one channel for surveillance testing to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This is necessary 1 because new ACTION 7 allows 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for the SSPS. Testing of the SSPS requires bypassing the reactor trip breakers,' and allowing 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months for the SSPS would provide no advantage unless the 4-hour stipulation were also made to ,

apply to the reactor trip breakers.

(b)

Changes as described in the marked-up copy of Technical Specification 3/4.3.2 h (Attachment 4). These changes include:

(i) Increase in surveillance intervals for Engineered Safety Features Actuation -

System (ESFAS) analog channel operational tests from once per month to once i per quarter.

(ii) Increase in the time that an inoperable ESFAS channel may be maintained in . '

an untripped condition from I hour to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . '

1 (iii) Increase in the time that an inoperable ESFAS channel may be bypassed to '

allow testing of another channel in the same function from 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . '

(iv) In Table 3.3-3, revise the following ACTIONS in accordance with the Westinghouse Owners Group guidelines as follows: l

- ACTION 14 is changed to allow 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months before placing the unit in HOT ;

STANDBY and increases from 2 to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months the time that a channel may be bypassed.

- ACTION 15 is changed to increase the time that an inoperable channel may be untripped from 1 to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . j

- ACTION 15a is changed to increase the time that an inoperable channel may be untripped from 1 to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

- ACTION 16 is changed to increase the time that an additional channel may ;

be bypassed from 2 to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . '

- ACTION 19 is changed to allow the inoperable channel to remain untripped for 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 'and to allow the inoperable channel to be bypassed for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

- ACTION 21 is changed to allow 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to restore an inoperable channel !

prior to placing the unit in HOT STANDBY and increases the time that a channel may be bypassed from 2 to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

i

- Create new ACTION 15b to be inserted in Table 3.3 3 following ACTION '

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

.m . ; *:

y -

lM '

15a. ACTION 15b is made to apply to functional unit 8 (Automatic Switchover to Recirculation), as this functional unit was not part of the program for which generic NRC relief has been granted.

]

(v) In Table 4.3-2,~ a change was made which will enhance the technical ,

specification from a human factors standpoint. Functional units 5b and 10d i both describe the steam generator high-high water level (P-14) turbine trip and feedwater isolation. The conditions delineated in 10d are the most limiting and must be followed; therefore, the current conditions in 5b are being deleted and replaced by those of 10d. The surveillance requirements of 10d will then be deleted from the table i

.(c) Revisions to the 3/4.3.1 and 3/4.3.2 REACTOR TRIP AND ENGINEERED i SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION BASES. .

I J

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I I l i

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ATTACIDIENT 3 JUSTIFICATION AND SAFETY EVALUATION l

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Justification and Safety Evaluation

-In WCAP-10271 and its supplements, the WOG evaluated the impact of the proposed surveillance test interval (STI) and allowed outage time (AOT) changes on core damage frequency and public risk. The NRC staff concluded in its evaluation of the WOG evaluation that an overall upper bound increase of the core damage frequency due to the proposed.

STI/AOT changes is less than 6 percent for Westinghouse Pressurized Water Reactor (PWR) plants. He NRC staff also concluded that actual core damage frequency increases for individual plants are expected to be substantially less than 6 percent. The NRC staff considered this core damage frequency increase to be small compared to the range of uncertainty in the core damage frequency analyses and therefore acceptable.

The NRC staff concluded in addition that a staggered test strategy need not be implemented for ESFAS analog channel testing and is no longer requimd for RTS analog channel testing.

(Since Duke Power Company has never applied for an increased surveillance test interval for the McGuire RTS, the staggered test strategy was never implemented.) His conclusion was based on the small relative contribution of the analog channels to RTS/ESFAS unavailability, process parameter signal diversity, and normal operational testing sequencing.

The NRC determined that the requirement to routinely verify permissive status is a different consideration than the availability of trip or actuation channels which are requimd to change state on the occurrence of an event and for which the function availability is more dependent on the surveillance interval. The definition of the channel check includes comparison of the channel status with other channels for the same parameter. For the RTS interlocks, the change from a monthly surveillance requirement to at least once every 18 months is therefore justified.

The proposed changes are consistent with the NRC staff's letters dated February 21,1985, February 22,1989, and April 30,1990, to the WOG regarding evaluation of WCAP-10271, WCAP-10271 Supplement 1, WCAP-10271 Supplement 2, and WCAP-10271 Supplement 2, Revision 1. The staff has stated that approval of these changes is contingent upon confirmation that certain conditions are met. It is the interpretation of Duke Power Company that conditions imposed in the SER for WCAP-10271 and WCAP-10271 Supplement 1 for' the RTS instrumentation shall also be applied to the ESFAS where appropriate. Duke Power Company's response to these conditions is provided below:

The first condition in the RTS SER required the use of a staggered test plan for the RTS channels changed to the quarterly test frequency.

Response

The NRC did not impose this requirement for ESFAS channels and it was subsequently removed for the RTS channels. Duke Power Company never applied for an amendment to change the surveillance interval for RTS channels in the past; therefore, the staggered test plan was never utilized.

The second condition in the RTS SER required that plant procedures require a common

cause evaluation for failure in RTS channels changed to the quarterly test frequency and additional testing for plausible common cause failurtsi l Resoonse (n the event of failure in an RTS channel, a Problem Investigation Process (PIP) is initiated to !

document the failure and assess the need for additional corrective action. This corrective ;

action includes evaluation for common cause failure mechanisms where appropriate. Testmg l of additional channels is conducted when there is reason to believe a common cause failure mechanism exists. Station guidelines have been developed to document the current practices 1 reflecting the Failure and Analysis Trending Program used to document nuclear steam supply system (NSSS) and balance of plant (BOP) failures. The program database is periodically reviewed by the responsible component expert to ascertain any trends or common cause failures. In addition, records of failures in RTS channels are input into the Nuclear Plant Reliability Data System (NPRDS) and trending of RTS failures is periodically performed utilizing this database. Finally, it should be noted that in addition to actual hardware failures, problems that may be introduced into the equipment as a result of calibration and other

. maintenance or testing activities also are evaluated for common cause potential.

i The third condition in the RTS SER required installed hardware capability for testing in the bypass mode. 1

Response

McGuire currently has installed bypass capability within the 7300 Pmtection and Control ]

System. i l

The fourth condition in the RTS SER involved channels that provide input to both the RTS and the ESFAS. As stated by NRC in the safety evaluation for WCAP-10271: 1 l

"In order to avoid confusion in plant Technical Specifications regarding such dual f function channels, the staff concludes that either (1) the channels should not be changed I in the RTS tables until the ESFAS review is finished or (2) cautionary notes in the RTS 1 tables should refer to the more stringent ESFAS requirements."

Resoonse ,

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Now that the ESFAS SER has been issued and all of the relaxations for the RTS analog ]

channels are applicable to the ESFAS analog channels, this condition does not apply. i Cautionary notes as described above have been deleted.

The fifth condition in theCRTS SER, and second in the ESFAS SER, addresses setpoint drift. Confirmadon is needed to show that the instrument setpoint methodology includes sufficient adjustments to offset the drift anticipated as a result of less frequent surveillance.

Resoonse McGuire engineering personnel have reviewed "as found" and "as left" data for the RTS and ESFAS setpoints for a 16-month period for Unit I and a 14-month period for Unit 2 and ,

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.. g concluded that sufficient adjustments are present to offset the drift anticipated as a result of quarterly surveillance. His information is available for NRC inspection.

1 The first condition in the ESFAS SER required that the plant-specific applications must i confirm the applicability of the generic analyses to the plant i

Response

The WCAP methodology addresses two-loop, three-loop, and four-loop plants with relay or solid state systems. He RTS and ESFAS functions for which increased surveillance intervals and allowed outage times are being requested in this amendment request are those for which NRC approval has already been granted through issuance of the SERs and supplements for the basis WCAP series. Except as already described andjustified in this submittal, no additional changes are being requested in this amendment request beyond those given approvaf by the NRC, a

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l ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION AND ENVIRONMENTALIMPACT ANALYSIS 7

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No Significant Hazards Consideration Determination -

The standards used to arrive at a proposed determination that the changes described involve no significant hazards consideration are included in 10 CFR 50.92. He regulations state that if operation of the facility in accordance with the proposed amendment would not: (1) involve a significant increase in the probability or consequences of an accident previously evaluated, or (2) create the possibility of a new or different kind of accident from any accident previously evaluated, or (3) involve a significant reduction in a margin of safety then a no significant hazards determination can be made.

Duke Power Company has reviewed the requirements of 10 CFR 50.92 as they relate to the proposed RTS and ESFAS Technical Specification changes for McGuire and determined that a significant hazanis consideration is not involved. In support of this conclusion, the following analysis is provided.

Criterion 1 - Operation of McGuire in accordance with the proposed license amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.

The determination that the results of the proposed changes are within all acceptable criteria was established in the SERs prepared for WCAP-10271, WCAP-10271 Supplement 1, WCAP-10271 Supplement 2, and WCAP-10271 Supplement 2, Revision 1 issued by letters dated February 21,1985, February 22,1989, and April 30,1990. Implementation of the proposed changes is expected to result in an accep21e increase in total RTS yearly unavailability. His incmase, which is primarily due to less frequent surveillance, results in an increase of similar magnitude in the probability of an Anticipated Transient Without Scram (ATWS) and in the probability of core melt resulting from an ATWS and also results in a small increase in core damage frequency (CDF) due to ESFAS unavailability.

Implementation of the proposed changes is expected to result in a significant reduction in the probability of core melt from inadvertent reactor trips. His is a result of a reduction in the number of inadvenent reactor trips (0.5 fewer inadvertent reactor trips per unit per year) occuring during testing of RTS instrumentation. His reduction is primarily attributable to testing in bypass and less frequent surveillance. .

The reduction in core melt frequency from inadvertent reactor trips is sufficiently large to counter the increase in ATWS core melt probability resulting in an overall reduction in total core melt probability.

The values determined b[the WOG and presented in the WCAP for the increase in CDF were verified by Brookhaven National Laboratory (BNL) as part of an audit and sensitivity analysis for the NRC staff. Based on the small value of the increase compared to the range of uncertainty in the CDF, the increase is considered acceptable.

Changes to surveillance test frequencies for the RTS interlocks do not represent a significant reduction in testing, ne currently specified test interval for interlock channels allows the

! i' j 4 surveillance requirement to be satisfied by verifying that the permissive logic is in its required state using the permissive annunciator window. The surveillance as currently required only i verifies the status of the permissive logic and does not address verification of channel serpomt '

or operability, ne serpoint verification and channel operability are verified after a refueling shutdown. The definition of the channel check includes comparison of the channel status with other channels for the same parameter. The requirement to routinely verify permissive status is a different consideration than the availability of trip or actuation channels which are required to change state on the occurrence of an event and for which the function availability is more dependent on the surveillance interval. The change in surveillance requirement to at least once every refueling does not therefore represent a significant change in channel surveillance and does not involve a significant increase in unavailability of the RTS.

The proposed changes do not result in an increase in the severity or consequences of an accident previously evaluated. Implementation of the proposed changes affects the probability of failure of the RTS but does not alter the manner in which protection is afforded nor the i manner in which limiting criteria are established.

l Criterion 2 - The proposed license amendment does not create the possibility of a new or-i different kind of accident from any accident previously evaluated.

The proposed changes do not result in a change m the manner in which the RTS provides plant protection. No change is being made which alters the functioning of the RTS (other than ,

in a test mode). Rather, the likelihood or probability of the RTS functioning properly is !

affected as described above. Therefore, the proposed changes do not create the possibility of

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a new or different kind of accident.

1 The proposed changes do not involve hardware changes except those necessary to implement testing in bypass. Some existing instrumentation is designed to be tested in bypass and current !

Technical Specifications allow testing in bypass. Testing in bypass is also recognized by IEEE standards. Therefore, testing in bypass has been previously approved and implementation of _

the proposed changes for testing in bypass does not create the possibility of a new or different J

kind of accident from any previously evaluated. Furthermore, since the other proposed j changes do not alter the functioning of the RTS. the possibility of a new or different kind of I accident from any previously evaluated has not been createi l l

Criterion 3 - The proposed license amendment does not involve a significant reduction in a -

margin of safety.

The proposed changes 80 not alter the manner m which safety limits, limiting safety system setpoints, or limiting conditions for operation are determined. He impact of reduced testing other than as addressed above is to allow a longer time interval over which instrument uncertainties (e.g., drift) may act. Experience has shown that the initial uncertainty assumptions are valid for reduced testing.

Implementation of the proposed changes is expected to result in an overall improvement in safety by:

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. 1) Less frequent testing will result in fewer inadvertent reactor trips and actuation of Engineered Safety Features Actuation System components.

2) lligher quality repairs leading to improved equipment reliability due to longer allowable repair times.

3) Improvements in the effectiveness of the operating staff in monitoring and controlling plant operation. This is due to less frequent distraction of the operator and shift .

supervisor to attend to instrumentation testing.

The foregoing analysis demonstrates that the proposed amendment to McGuire's Technical Specifications does not involve a significant increase in the probability or consequences of a -

previously evaluated accident, does not create the possibility of a new or different kind of accident, and does not involve a significant reduction in a margin of safety.

Based upon the preceding analysis, Duke Power Company concludes that the proposed amendment does not involve a significant hazards consideration.

Environmental Impact ' Analysis 4

The proposed Technical Specification amendment has been reviewed against the criteria of 10 CFR 51.22 for environmental considerations. The proposed amendment does not involve a significant hazards consideration, nor increase the types and amounts of effluents that may be released offsite, nor increase individual or cumulative occupational radiation exposures.

Herefore, the proposed amendment meets the criteria given in 10 CFR 51.22(cX9) for a categorical exclusion from the requirement for an Environmental Impact Statement.

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