Text

Proposed Tech Specs Re Nominal 24 Month Fuel Cycle Surveillance Extensions
	ML20086S127
Person / Time
Site:	Millstone
Issue date:	07/26/1995
From:	; NORTHEAST NUCLEAR ENERGY CO.
To:	;
Shared Package
ML20086S119	List: B15306, Application for Amend to License NPF-49,revising TS Re Nominal 24 Month Fuel Cycle Surveillance Extensions for Millstone Unit 3; ML20086S127;
References
	NUDOCS 9508010104
	Download: ML20086S127 (172)
	v • d • e

_.

Jcnuny 31. 1966 INDEX i

SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION pAGE 2.1 SAFETY LIMITS 2.1.1 REACTOR C0RE................................................

2-1 2.1.2 REACTOR COOLANT SYSTEM PRESSURE.............................

2-1 FIGURE 2.1-1 REACTOR CORE SAFETY LIMIT - FOUR LOOPS IN OPERATION..

2-2 FIGURE 2.1-2 REACTOR CORE SAFETY LIMIT - THREE LOOPS IN OPERATION.

2-3 i

2. 2 LIMITING SAFETY SYSTEM SETTINGS i

2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETP0INTS...............

2-p TABLE 2.2-1 REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS....

-g6 i

BASES SECTION PAGE 2.1 SAFETY LIMITS 2.1.1 REACTOR C0RE................................................

B 2-1 2.1.2 REACTOR COOLANT SYSTEM PRESSURE.............................

B 2-2 2.2~ LIMITING SAFETY SYSTEM SETTINGS i

2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETP0INTS...............

B 2-3 i

i l

1 MILLSTONE - UNIT 3 iii dI;IW 9508010104 950726 PDR ADOCK 05000423 P

PDR

t h

JAN 31 1986 SAFETY-LIMITS AND LIMITING SAFETY SYSTEM SETTINGS i

2. 2 LIMITING SAFETY SYSTEM SETTINGS

}

REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 The Reactor Trip System Instrumentation and Interlock Setpoints shall i

{

be set consistent with the Trip Setpoint values shown in Table 2.2-1.

i j

6 APPLICABILITY: As shown for each channel in Table 3.3-1.

ACTION:

c.kr nnJ With a Reactor Trip System Instrumentation e6 Sa'tpoint-f" a.

s less conservative than the value shown in the Trip Setpoint column e

I but more conservative than the value shown in the Allowable Value v

E

'e column of Table 2.2-1, adjust the Setpoint consistent with the Trip J

2 Setpoint value.

[

u y

.3 b.

c.%u,,m sL I

With the Reactor Trip System Instrumentation e-IPA M::t Ot;mt g

g f column of Table 2.2-1, either:less conservative than the value shown in the A 3

r f

{

y1 1.

Adjust the Setpoint consistent with the Trip Setpoint value of jg-)

Table 2.2-1 and determine within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months that Equation 2.2-1 n

7 I.)

was satisfied for the affected channel, or i

a-t yjr 2.

Declare the channel inoperable and apply the applicable ACTION d'

L { '. 3 statement requirement of Specification 3.3.1 until the channel L

o l

,,6 is restored to OPERABLE status with its Setpoint adjustyi i

)

consistent with the Trip Setpoint value.

/

{

i Equation 2.2-1 2 + R + 5 5,TA go

3r J,

Where:

{A a

i 2 = The value from Column 2 of Table 2.2-1 for the affected channel, k

R = The "as measured" value (in percent span) of rack error for the qt affected channel, y

5 = Either the "as measured" value (in percent span) of the sensor 1

error, or the value from Column S (Sensor Error) of Table 2.2-1 for the affected channel, and i

TA = The value from Column TA (Total Allowance) of Table 2.2-1 for the affected channel.

L c. W 9%

i a B ch "Tric E9W~"'~C*5 W " hb1 CI*"'d "1" M e

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- Z -

. e n. u,_

& * *T' '* k # ' '* ' ' Sh'"

]

g m,,, 4% N.4w.d -TM r Saky *M Cat j A64 *

"'p

,., g y u g Lw h i.i e O =d "T A t*

S e N 9 =

s v w a W <- -

MILLSTONE -

e#

v:a

d V o b c' F =4'~ Twp s, w w w. w u c w s

y, (twm kQ wbWw ch4wwd Ltxcp h pssew p m s % ^ c( d tow-w 1

bNAM. g h %N W4hv h

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ebww d 4 o 7%sk W

\\

tw cAe_c(o. w.Asm c y p u csstc_

Aenaw SWW@

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.6b T a bte-d 3 3 - l_

vow \\

h cL ww d

-L,

>+ M b oe E G6 % -E.

d)AA cer 6 s shb wx% AR

. Ghva c.w ck W s,

.seyo w4 s

9 cad % p SQ%+ vdwe.

i.,

-e e.

- I a

1

T a r 2 r.I c

z REETQR TRIP SYSTEM INSTm"NTATION TRIP SETFOINTS TOTAL stNs0R' M

lF ALLOWANCE ERROR

* 'M "

H I

m runcinonnt uMIT fTA)

Z

($1 TRIP SETPOINT ALLDMARLE M LUE 1.

Nanual Reacter Trip N.A.

N.A.

M.A.

i h

2.

Power Range, Neutpn Flux 4

a.

High Setpointi e

I

1) Four Loops Operating 7.5 4.56 0

5 1995 of RTP**

$ 111.15 of RTPa*

p 2)ThreeLoopsOperating 7.5 4.56 0

1 805 of RTP**

1 82.15 of RTP**

Q-b.

Lcw Setpoint 8.3 4.56 0

$ 29E of RTP**

$ 27.1% of RTP**

1 3.

Power Rango Neutmn Flux.

I.6 0.5 0

1 95 of RTP** with i 6.35 of RTP** wi th h High Positiva Rate a time constant a time constant f

N 2 2 seconds t 2 seconds o

4.

Deleted t"

5.

Intermediate Range, 17.0 8.41 0

1295 of RTP**

130.95 of RTP**

Neutron Flux 6.

Searce Range, Neutrun Flux 17.0 10.01 0

$ 10"cys J 1.4 x 19 " cps 7.

Overtemperators AT E.

l f

a.

Four Loops Operating w

1) Channels I, II 10.0 8.14 1.61 + 1.33 Note 1

% Note 2 (Temp + Pmss K

2) Channels itI, IV 10.4 7.17 1.61 + 2.60 Note 1 lee Note 2 O

i

(

(Temp +Pmss v

a

- RTP - u Tro Tntannt rowtR

=

y m

G s

-c

.e n--

<w----

w,.-

e

,,-.m-

---n--,----

i l

r 1

E 3

5 sa e

.k s-

~

s=

1

~.

3 zas c

a 5 E " s *! * 'u s 33 we~s~Q.eu}

}

i su =

w 33 3~w w~

3 g

)? $

.YJ5 L

eth l Olil/g kl*

?N

(

5 Il

=m i[

% av s

a a

a1 s

s s a s

e 12 n-a a

a yE E= Es s: 5s a

-e s

=

s s.

g g ii 33 3

~

e, we na ~En w-33 ng sj q

3}

e

_=

.. ~.

I, 8

cret

.-~

e a

a me H=g g1 g

ac ae a e e a e

a w.

g s~

P a

a ee==

a s.

32 a

a e

as as

-;s a s Cz 3;;;

w W

a E3 vt_

a s

- at..e

=.

_s s,

.z -

e, it:

A-g F

.y e

y

>z e

a h

8

'E I

r tn8Y a

a s" z

e m

E.

E 2".

e=

3 t =g Ia t

c a

a3 h

?

cn

-1I*EEn1 a =!! ! j :i ~) }83 j=

=

j3 e{

]c t

t t

==

se e

g i

is

[

al

} 33 I;

e=c g;

azisa i

e e s a

i a

is IS Y,

- n--

m

a. n n. n.~

7 ;a;

-TTContinuedT-C..

REACTOR TRIP initn lil5TNINENTATION TRIP SETPOINTS 9,y 2

ETOTAL SEN T '

AttovANet ERROR

mid^'

FUNCTIONAL WII ITA1 Z

f5)

TRIP SETPOINT.

ALLOM BLE ULUE

'}

16. Turbine Trip i

a.

Low Fluid Oil Pressure N.A.

N.A.

M.A.

1 500 psig 1 450 psig b.

Turbine Stop Valve M.A.

N.A.

2 1% open 1 1% open Closure

17. Safety Injection input N.A.

N.A.

M.A.

N.A.

M.A.

from ESF

18. Reactor Trip System Interlocks i

a.

Intermediate Range N.A.

M.A*

N'A.

1 1 x 10'to amp 2 6 x 10'" any j

Neutron Flux, P-6 i

b.

tow Power Reactor Trips 81ock, P-7 S

i

1) P-10 input (NoteA)

N.A.

N.,*.

s 11% of RTP**

s 12.1% of RTP**

3

2) P-13 input N.A.

N.A.

M.A.

s 105 RTP** Turbine 5 12.1% RTP** Turbine Impulse Pressure impulse Pressure Equiyalent Equ1 valent c.

Power Range Neutron Flux, P-8 i

1) Four loops Operating N.A.

N.A.

s 37.5% of RTP**

s 39.6% of RTP**

2) Three loops Operating N.A.

N.A.

s 37.5% of RTP**

5 39.6% of RTP**

j M

t

RTP = RATED THERNRL POWER NILLSTONE - UNIT 3 C199 2

Amendment No. 5.

i 85 m

~

="

REACTOR TRIP h sien insi._. a in?t0N intP siirvinii 10/25/93' f0TAL Enno R)

SENSO EUNCTIONAL UNIT AucunNCr

- ~ < =

ITA)

Z 151 1 RIP SETPOINT AtInWABLE VALUE y

d.

Power Range Neutron Flux, P-9 M.A.

N.A.

s 51% of RTP**

< 53.1% of RTP**

e.

Power Range Neutron M.A.

N.A.

M.A 2 97,of RTP**

2 7.9% of RTP**

Flux, P-10 (Note

19. Reactor Trip Breakers M.A.

N.A.

N.A N.A.

20. Automatic Trfp and Interlock N.A.

Logic N.A.

,N.A.

N.A.

M.A.

21. Three i.oop Operation N.A.

Bypass Circuitry N.A.

N.A.

M.A.

M.A gg g

swsen,

.rptPAETP* swr ALL* d84 ALtouspect EN (M

t 8l =

ID4sagvhey basein.W j

g y.o

g. 77 31

% M'O P84

. 10 -

P. uwvi..y P,.sm.w H q w

r..

tn 3-1, 6 * "* 5 PS A 6 4 *

P' A

\\3 Steaww G%.v W m6 i s.g a

14..c is s.5 i, 7, t8.w.F w w.w 3 17 11 'E " " '**

Le v.f Le e.,- i.. s vsw3 e. W4 wwsc. hab=wt-i 5Mw 5ew-

"RTP = RATED THERNAL PONER INILLSTONE-UNIT 3 q

mee 2,8

- Amendment No. g, g, a.m e

.: j necch 11

);

5 JAstE 2.2-1 fContinuedl IABLE NOTATIONS

={

NOTE 1: DVERTEMPERATURE AT h

ATkI+*13I I

I+45I I

(1 + r 3) gI + # 3) SAT IEl~I2 N

2 3

II + '5SI [T gI + # 3) - T'l + K3 (P - P') - f (AI))

O n

g 6

Where:

AT

= Measured AT by Reactor Coolant System Instrumentation; I+rSj

= lead-lag compensator on measured AT; I+73 2

- Time constants utilized in lead-lag compensator for AT, r r,r y

2 i

g = 8 s, 2 " 3 *I r

I I+r5

- Lag compensator on measured AT; b

3 o

D r

- Time constants utilized in the lag compensator for AT, r 3

3 - 0 s; AT Indicated AT at RATED THERMAL POWER;

=

O K

= 1.20 (Four loops Operating); 1.20 (Three loops Operating);

g K

- 0.02456; 3

2 I+#I 4

- The function generated by the lead-lag compensator'for T,g dynamic 1+r3 5

compensation; 7,7

= Tim cu stants uttilz d in W 1ead-lag c epensator for T,,,,

r 4

5 5 " 4 SI 4 - 20 s, 7

la T

$~

Average temperature, 'F; 1

- tag coupensator on measured T,q ;

1+73 6

r

- Time constant utilfred in the measured T,,, lag c e pensator, 6

m.

r6*88I

~

4 gse Ipas r f.2 1 fr- ^ l- - 't TABLE II5 FAT 1tHB (f.antlaned)

IIDTE 1: (Continued)

T' s 587.1'F (llusinal T,,, at MTG TIIElWN. POWER)

K

= 0.M1311/psis 3

p

= pressortaer pressere, pelas p'

= 2250 psis (IIsoleel RCS operettag pressere):

S Laplace transform operator, s 's

=

and

?

(AI) is a functlen of the Indicated difference between top and bottom detectors of the dering plant startup tests such thet: range neutron ten chad erst with gains to be selected based on messered 53 (1) For g g betusen -205 and + 35, f,(AI) = 0, ahore g and are percent MTS INEIWWE. PUNElt to tu top and betten halves of the core respectively,g and

+ g is total 1 MIO N. PON R in percent of MTED THEIWWW. POWER:

(2) For each percent that the engattede of g - g esteeds -205, the AT THp Setpoint shali be setematteelly redeced by 3.555 of its satse eY MTED lilEIWWE. POWER: and (3) For each that the negattede of reduced by I.985 of fts vbee h exceeds +35, tle AT 1Hp Setpelat shall be automatic MTW lilElWW. POWER.

l IIDTE 2:

^

The channel's mentaus Trip Setpelat shall not onceed its competed Tri z

AT span (Fear Loop Operetten): 2.75 AT span (Three Loop Operetten). p Setpoint by more than 1.45 l

f I

!y l=

=

l l

m

______-------___-.,_.._a m --

ms A

-w

March 11 t

' 17h TABLE 2.2-Litentinuedl IABLE HDTATIGNS fCentfneed) 4 NOTE h OVERPO KR A'T AT II + # 3I I I

I 1

(1 + r:S) (1 + r:S) s AT, (K. - K, (I I'I I

II I

T-K (T I I

I - T*] - f, (AI)}

1 + r,5)

(1 + r,5)

(1 + r S)

^

Where:

AT

= As deffned in Note I, I+#I 8

= As deffned in Note 1, 1 + r:S ri, 7:

- As defined in Note 1, I

1 + r:S As defined in Note 1,

=

rs As defined in Note 1, AT,

= As deffned in Note 1 K

1.09,

=

l K,

= 0.02/'F for increasing average temperature and 0 for decreasing average temperature.

'88 The function generated ly the rate-lag compensator for T,

=

1 + r,S dynamic compensation, r,

= Time constants utt11 red in the rate-lag compensator for T,y, r, - 10 s, I

I + r,$

= As defined in Note 1, e

a r,

= As defined in Note I, h

4 mm

_--__s,

..,,,.._...,-...~<--.---.....,-,.4-

, ~,.,. -,

v

-<w r-e.

TAERI 2.2-1 fCastlemedl TABLE E RATICES (Camitamodt E

V 4

norE @ (continued)

K

= 0.00180/*F for T > T' and K = 0 for T 1 T*,

6 g

T

= As defined in IIste 1 T*

ladicated T a

,r.

. for AT lastnamentab,t IWLTED THEIWWLL POWER (Callbretten *

=

s507.I'F),

= As defined in Ilote 1 and i

fIAII

' I 'II AI' 2

?

[NUTE4: The channel's mentasm Trip 5etpoint shall not onceed its computed Trip Setpoint by more then I.75 AT span. (Four Loop operetten)

\\h 9

l IIDTE,5!

Setpefat is for incrossley poser.

IIOTE Setpoint is for decreeslag peuer.

l t-O I-C 2

1 1

k 22 LIMITING SAFETY SYSTEM SETTINGS JAN 311986 BASES 2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETP0INTS mvh CowmN Fe EmAr ne neactor irip setpoint Limits specified in Table 2.2-1 are the nominal

-values at which the Reactor trips are set for each functional unit.

The Trip

'Setpoints have been selected to ensure that the core and Reactor Coolant System are prevented from exceeding their safety limits during normal operation and design basis anticipated operational occurrences and to assist the Engi-neered Safety Features Actuation System in mitigating the consequences of accidents.

The Setpoint for a Reactor Trip System or interlock function is considered to be adjusted consistent with the nominal value when the "as measured" Setpoint is within the band allowed for calibration accuracy and instrument drift.

To accommodate the instrument drift assumed to occur between operational tests and the accuracy to which Setpoints can be measured and calibrated.

Allowable Values for the Reactor Trip Setpoints have been specified in Table 2.2-1.

Operation with Setpoints less conservative than the Trip Set-point but within the Allowable Value is acceptable since an allowance has been made in the safety analysis to accommodate this error.

An optional provision has been included for determining the OPERABILITY of a channel when its Trip Setpoint is found to exceed the Allowable Value.

The methodology of this option utilizes the "as measured" deviation from the specified calibration point for rack and sensor components in conjunction with a statistical combin-ation of the other uncertainties of the instrumentation to measure the process variable and the uncertainties in calibrating the instrumentation.

In Equa-tion 2.2-1, Z + R + 5 < TA, the interactive effects of the errors in the rack and the sensor, and t G "as measured" values of the errors are considered.

Z, as specified in Table 2.2-1, in percent span, is the statistical summation of errors assumed in the analysis excluding those associated with the sensor and rack drift and the accuracy of their measurement. TA or Total Allowance is the difference, in percent span, between the Trip Setpoint and the value used in the analysis for Reacter trip.

R or Rack Error is the "as measured" devia-tion, in percent span, for the affected channel from the specified Trip Set-point.

S or Sensor Error is either the "as measured" deviation of the sensor from its calibration point or the value specified in Table 2.2-1, in percent span, from the analysis assumptions.

Use of Equation 2.2-1 allows for a sensor drift factor, an increased rack drift factor, and provides a threshold value for REPORTABLE EVENTS.

The methodology to derive the Trip Setpoints is based upon combining all of the uncertainties in the channels.

Inherent to the detemination of the Trip Setpoints are the magnitudes of these channel uncertainties. Sensors and other instrumentation utilized in these channels are expected to be capable of operating withir the allowances of these uncertainty magnitudes.

Rack drift in excess of the Allowable Value exhibits the behavior that the rack has not met its allowance.

Being that there is a small statistical chance that this will happen, an infrequent excessive drift is expected.

Rack or sensor drift, in excess of the allowance that is more than occasional, may be indicative of more serious problems and should warrant further investigation.

MILLSTONE - UNIT 3 8 2-3

f7

USNRC DRPE TEL:301-415-2102 Jul 11'95 17:11 No.018 P.07 LIMITIls SAFETY SYSTEN SETTINQ5 sasEs I

i REACTOR TRIP SYSTEM INETRUNDIT4 TION SETPOINTS (Continued)

The various Reactor trip circuits automatically open the Reactor trip breakers whenever a condition monitored by the Reactor Trip system reaches a preset or calculated level. In addition to redundant channels and trains, the design approach provides a Reactor Trip System which monitors numerous system variables, therefore providing Trip System functional diversity. The functional capability at the specified trip setting is required for those anticipatory or diverse Reactor trips for which no direct credit was assumed in the safety analysis to enhance the overall reliability of the Reactor Trip system. The Reactor Trip System initiates a Turbine trip signal whenever Reactor trip is initiated. This prevents the reactivity insertion that would otherwise result from excessive Reactor Coolant System cooldown and thus avoids unnecessary I

actuation of the Engineered Safety Features Actuation System.

W lN4Ef7 hl Manual Reactor Trio The Reactor Trip system includes manual Reactor trip capability.

power Ranoe. Neutron Flur i

In each of the Power Range Neutron Flux channels there are two independent b1 stables, each with its own trip setting used for a High and Low Range trip setting. The Low Setpoint trip provides protection during suberitical and low power operations to mitigate the consequences of a power excursion beginning from low power,.and the High Setpoint trip providas protection during power operations to mitigate the consequences of a reactivity excursion from all power levels. The High Satpoint trip is reduced during three loop operation to a value consistent with the safety analysis.

The Low Setpoint trip may be manually blocked above P-10 (a power hvel of approximately 10lf, of RATED THERMAL POWER) and is automatically reinstated below the P-10 Setpoint.

Power Rance. Neutron Flux. Hiah Positive Rate l

The Power Range Positive Rate trip provides protection against rapid flux increases whi'ch tTe characteristic of a rupture of a control rod drive housing.

Specifically, this trip complements the Power Range Neutron Flux High and Low trips to ensure that the criteria are met for all rod ejection accidents.

s NgLSTONE-LNt!T3 5 2-4 Amendment No.116 i

iMEtt M k 1 Q 2.

v. P y B 2- 't

' ' ' ~:':" ::T:77 ::: :M ::7;hf Bf""

i eWL c.s L uMN Fa it.m Ar-1 p e-+ me m no Toto evevru prem-. gu --ng u,3 The Reactor Trip Setpoint Limits specified in Table 2.2-1 are the nominal values at which the reactor trips are set for each functional unit.

The Nominal Trip Setpoints are considered the Limiting Safety System Settings as identified in 10CFR50.36 and have been selected to ensure that the core and Reactor Coolant System are prevented from exceeding their safety limits during nomal operation and design basis anticipated operational occurrences and to assist the Engineered Safety Features Actuation System in mitigating the consequences of accidents.

The Setpoint for a Reactor Trip System or interlock function is considered to be consistent with the nominal ~value when the measured "as left" Setpoint is within the administrative 1y controlled (1) band identified as the calibration tolerance.

1 Maintenance and Test Equipment accuracy is administrative 1y controlled by plant procedures and is included in the plant uncertainty calculations as defined in WCAP-10991. Operability determinations are based on the use of Maintenance and Test Equipment that confoms with the accuracy used in the plant uncertainty calculation. Maintenance and Test Equipment should be consistent with the requirements of ANSI / ISA S1.1-1979 or the most accurate practicable.

The administratively controlled limit for operability of a device is detemined by device drift being less than the value required for the i

surveillance interval.

In the event the device exceeds the administratively controlled limit, operability of the device may be evaluated by other device performance characteristics, e.g., comparison to historical device drift data, j

calibration characteristics, response characteristics and short term drift characteristics.

A device (RTD, relay, transmitter, process rack module, etc.), whose "as found" value is in excess of the calibration tolerance, but within the operability criteria (administratively controlled limit), is considered operable but must be recalibrated such that the "as left" value is within the two sided (*) calibration tolerance.

Plant procedures set administrative limits ("as left" and "as found" criteria) to control the detemination of operability by setting minimum standards based on the methodology in WCAP-10991 and the uncertainty values included in the detemination of the Nominal Trip Setpoint, and allow the use of other device characteristics to evaluate operability. REPORTABLE EVENTS are identified when the minimum number of channels required to be operable are not met.

The methodology, as defined in WCAP-10991 to derive the Nominal Trip i

Setpoints, is based upon combining all of the uncertainties in the channels.

Inherent in the detemination of the Nominal Trip Setpoints are the magnitudes of these channel uncertainties. Sensors and other instrumentation utilized in these channels should be capable of operating within the allowances of these uncertainty magnitudes. Occasional drift in excess of the allowance may be detemined to be acceptable based on the other device perfomance characteristics.

"ZH2 E LT k '

qb 4u Peg S.-t u LTMTTfNf: tArriv tverru erw n g m arr-- m nne n::

....emm, m

m,,,,...u)

Device drift in excess of the allowance that is more than occasional, may be indicative of more serious problems and would warrant further investigation.

The various reactor trip circuits automatically open the reactor trip breakers whenever a condition monitored by the Reactor Trip System reaches a preset or calculated level.

In addition to redundant channels and trains, the design 1

approach provides a Reactor Trip System functional diversity. The functional capability at the specified trip setting is required for those anticipatory or diverse reactor trips for which no direct credit was assumed in the safety analysis to enhance the overall reliability of the Reactor Trip System.

The Reactor Trip System initiates a turbine trip signal whenever reactor trip is initiated.

This prevents the reactivity insertion that would otherwise result from excessive Reactor Coolant System cooldown and thus avoids unnecessary actuation of the Engineered Safety Features Actuation System.

l l

e

1 POWER DISTRIBUTION LIMITS LIMITING COM ITION FOR OPERATION ACTION (Continued) b.

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of initially.being outside the above limits, verify through incore flux mapping and RCS total flow rate that Fa" and RCS total flow rate are restored to within the above limits, or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

c.

Identify and correct the cause of the out-of-liniit condition prior j

to increasing THERMAL POWER above the reduced THERMAL POWER limit required by ACTION a.2. and/or b., above; subsequent POWER OPERATION may proceed provided that F," and indicated RCS total flow rate are demonstrated, through incore flux mapping and RCS total flow rate comparison, to be within the region of acceptable operation prior to i

exceeding the following THERMAL POWER levels:

1.

A nominal 50% of RATED THERMAL POWER, 2.

A nominal 75% of RATED THERMAL POWER, and 3.

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of attaining greater than or equal to 95% of RATED THERMAL POWER.

SURVEILLANCE REQUIREMENTS i

4.2.3.1.1 The provisions of Specificatio 4.0.4 are not applicable.

4.2.3.1.2 RCS total flow rate and F," shall be determined to be within the acceptable range:

a.

Prior to operation above 75% of RATED THERMAL POWER after each fuel loading, and b.

At least once per 31 Effective Full Power Days.

4.2.3.1.3 The indicated RCS total flow rate shall be verified to be within the acceptable range at least once ser 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the most recently obtained value of F,", obtained per Specificat< on 4.2.3.1.2, is assumed to exist.

4.2.3.1.4 The RCS total flow rate indicators shall be subjected to a CHANNEL

[

CALIBRATION at least oncedieFT8iii55At: The measurement instrumentation shall be calibrated within 7 days prio to the performance of the calorimetric flow measurement.

gA Rc r un t-t N cr @ TW A

[t NILLSTONE - UNIT 3 3/4 2-20 Amendment No. pp. 77,100

$l0f'

March 11, 1991 POWER DISTRIBUTION LIMITS SURVEILLANCE REOUIREMENTS (Continued) y t%ch tREFuG urJ G lure (WA L -

4.2.3.1.5 The RCS total flow ratVshall be determined by precision heat balance I

measurement at least once fer 18 mannt.

Within 7 days prior to performing the precision heat balance, the instrumentation used for determination of steam pressure, feedwater pressure, feedwater temperature, and feedwater venturi AP in the calorimetric calculations shall be calibrated.

g

.2.3.1.6 If the feedwater venturis are not inspected at least once QD. '** d "

an additional 0.1% will be added to the total RCS flow measurement uncertainty.

i i

MILLSTONE - UNIT 3 3/4 2-21 Amendment No. 77,60

?' b,,,i:(

k l

POWER DISTRIBUTION LIMITS LIMITING C05 ITION FOR OPERATION ACTION (Continued) b.

Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of initially being outside the above lim [ts, d RCS verify through incore flux mapping and RCS total flow rate that F an total flow rate are restored to within the above limits,,or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Identify and correct the cause of the out-of-limit condition prior c.

to increasing THERMAL POWER above the reduced THERMAL POWER limit required by ACTION a.2. angor b.

above; subsequent POWER OPERATION l

may proceed provided that F, and, indicated RCS total flow rate are i

demonstrated, through incore flux mapping and RCS total flow rate comparison,he following THERMAL WWER levels:to be within the retion of acceptable operation prior to exceeding t 1.

A nominal 32% of RATED THERMAL POWER, and 2.

A nominal 50% of RATED THERMr.L POWER.

SURVEILLANCE. REQUIREMENTS 4.2.3.2.1 The provisions of Specification 4.0.4 are not applicable.

4.2.3.2.2 RCS total flow rate and F" shall be determined to be within the acceptable range at least once per 3IEffective Full Power Days.

]

4.2.3.2.3 The indicated RCS total flow rate shall be verified to be within the acceptable rangg at least once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months when the most recently i

obtained value of Fm, obtained per Specification 4.2.3.2.2, is assumed to exist.

4.2.3.2.4 The RCS total flow rate indicators shall be subjected to a CHANNEL CALIBRATION at least once er 1BimodtYs' The measurement instrumentation l

~

shall be calibrated within ays prior o the performance of the calorimetric flow measurement.

p geFus uch i wts genL..

4.2.3.2.5 The RCS total flow rate shal be determined by precision heat balancemeasurementatleastoncedel performing the precision heat balance _18]nonttin Within 7 days prior to the instrumentation used for detemination of steam hressure, feedw,ater pressure, feedwater temperature and feedwater venturi A in the calorimetric calculations shall be calibrafed.

g e gerum"G 4.2.3.2.6 If the feedwater venturis are not inspected at least once-per, wrmA" I:: s;ths uncertainly.an additional 0.1% will be added to the total RCS flow measurement jNlSTONE - IMIT 3 3/4 2-23 Amendment No. 77, pp. 77,100 o pry

January 3,1995 3/4.3 INSTRUNENATION 3/4.3.1 REACTOR TRIP SYSTEN INSTRLa8ENTATION LIMITING COM ITION FOR OPERATION 3.3.1 As a minimum, the Reactor Trip System instrumentation channels and interlocks of Table 3.3-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3-1.

AfJ10H:

)

As shown in Table 3.3-1.

SURVEILLANCE REQUIREMENTS 4.3.1.1 Each Reactor Trip System instrumentation channel and interlock and the automatic trip logic shall be demonstrated OPERABLE by the performance of-the Reactor Trip System Instrumentation Surveillance Requirements specified in Table 4.3-1.

pew n eruet.ioc. imTepA'

,,w hm 4.3.1.2 The REACTOR TRIP SYSTEN RESPONSE TIME of e actor trip Functio shall be demonstrated to be within its limit at least once per is montns.

l Neutron detectors and speed sensors are exempt from response time testing.

_q

~

Each test shall include at least one train such that both trains are tested at 9

least ofire 7 rt30 months and one hannel to include input relays to both trains) <nar functTAD#uch that all d'ha are tested at-least once every b

)

rtimes 18 months where N is the tofa' n

r of recundarli channels in a specifi Reactor trip function as shown 1/l the " Total No. of Channel 1" coluNn of Jable3.3-1.L iAc Hm p yu k c4'" S*U'O

-F"yfpygn a c,-

scV I A T E A u A L.

h + an d cold asu%ce tu Reseau.s a 7~tm e of n e vv.c.a r a ng e.

-l:emper.,% de Fec ks uaM 1efs pex day npd ac % o ce Arntershm:.or '

i Mc4 n Wp$ Jhe,li b s.

o{ernosSlYte U & k VIifistA Qn8 ouerf M eq A T t

ex.4 pe f v e uac. ia niku A L Enc

+% < LA M-Iess I--

em e e.

c 4

-te & s k it in c kde. c, f- (ew

-% pyh. sets.rm e k 4%.

4II S Y R T b.re.fs c<. r e, be.s te al, enf-JeesI-cmcc fen

42 vn e n.s.

NILLSTONE - UNIT 3 3/4 3-1 Amendment No. JJ. 77. JJ1 %

esse 0 4so

i TABLE 3.3-1 (Cent 1JggA),

. March 11, 1991 ACT*0N STATEMENTS (Continued)

ACTICN 3 - With the number af thannels* DPERA8LE one less than the Minimum Channels OPERABLE requirement and with the THERMAL POWER 1evel:

k.s..-

..1

~r%

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

Setpoint, restore the inoperable channelSto OPERABLE T

status prior to Increasing THERMAL POWER,above the P 6

. !?

.:. v fe: c Setpoint, and e': ::

1..

3,

.f.

b.

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

Setpoint but below 30% of RATED THERMAL POWER, restore the inoperable channel to CPERABLE status prior to. increasing i

THERMAL POWER above los of RATED THERMAL POWER.

.. t.:

-s ACTION 4 - With the number of OPERABLE channels one less then the Minimum Channels OPERABLE requiremen't, suspend all operations involving positive reactivity changes.,

ACTION 5 - (a)

With the number of OPERABLE channels one less than the I p._

Minimum Channels OPERABLE requirement, restore the f

inoperable channel to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or suspend all operations involving positive reactivity changes and verify valves as per Specification (4.4.1.4.2w are closed and secured in. position within the nex,.t__f.ce-I hours.

p j,f..g t (b)

With no chann'els

DPERABLE, spend all operations

- Q i

involving positive.<rea:tivity. anges and verify valves L

1 per Soecification 14.'.4.2.3]are closed and secured in position within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

Verify compliance with g

the SHUTDOWN MARGIN requirements of Specification 3.1.1.1. 2 or 3.3.2.2 as applicable within the next hour.

Continue to verify valves closed and secured every 14 days and verify SHUTDOWN MARGIN every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Entry into an OPERATIONAL MODE. pursuant to Specification 3.0.4 is not u

permitted.

ACTION 6 - With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERAT*0N may proceed provided the following conditions are sati:fied:

' w.

The inoperable' channel is placed in the trippeo conoitton s.

within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and -. * :<.. ;o.

1.:

.. h.'

The Minimum Chan'nels OPERABLI requirement is met: however, i

M8a.- ; : :. i[.. '.

the inoperable 1:hannel may be bypassed for un to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months La +

%l?.*.as :f 6i..for.. surveillance utesting' n

of.other channels per

.W;:,0W* Spectfication 4.3;Th.:dia :5':; 5 :

ne 1: ::

. :. t.

Q.-.

v-

.. :., ::...: '. - e,-" D " i.

ACT10N 7'n' e

-- (Not used)'# "

s

,.','.'f".f $U'"*P:lh.e 4::'

~.

C-We l

0

.t ACTION 8 - With less than'the Minimum Number of Channels OPERABLE, within I hour determine by observation of the associated persissive O

annunciator window (s) that the inter'ocx is 'n its recuirec Le

4. 3.n : :, :.., state for the ex a

/

. Specification 3.3.3.*' jsting plant conci ton.

or acoly

. ? g V

W D9%

S// E - L-

. ' p'; '

...E.

ty-

i l

m l

C 5

LB5 t3

(

$E TABLE 4.3-1 5I l

ap k ium tarp aisir,iai

--mileE SIEtWEtt B aarx =s=;i---

=33 m

TRIP AMLOG ACTUATIM MODES FOR E

I CHA'tNEL CMNNEL OPERAil0NAL OPERATIONAL TUI SURVEftl>NCE CHANNE.

LEVICE WIca 4

FUNCTIONAL UNIT CHECK CALIslATIGt TEST TEST IC 'EST IS REGUIRED 1.

Nanval Reacter Trip N.A.

N.A.

R(14)

N.A.

g 2, 3*, 4*,g 2.

Power Range $tpoint Neutron Flex C

a.

High S

DC n,, cj,,

q N.A.

N.A.

1, 2 3

h *d e

1 b.

Low setpoint S

Rd

ll S/U(I)

N.A.

1***, 2 y

3.

Power R g

HighPoNyeRateNeutron Flux, ll.A.

R(4,5)

(

N.A.

M.A.

1, 2 O

8 h

4.

Deleted

{

~

5.

Intermediate Range 3

R(4,5)

$/U(1)

N.A.

1 ***, 2 4.

Source Range, Neutron Flux S

R(4,5) gt).

N.A.

g**,3,4, 7.

Overtemperature AT S

R Q

N.A.

1, 2 E

u 8.

Overpower AT S

R Q

N.A.

I, 2 M9 q(18)

N.A.

I f'

9.

Presserizer Pressure--Low 3

N

10. Pressurizer Pressure--High S

g fS#

Q(18)

N.A.

M.A.

1, 2 3

11. Pressurizer Water Level--High S R

Q R.A.

N.A.

1

]

g

12. Reactor Coolant Flow--Low S

A q

R.A.

N.A.

I G

w4 I

4 g

a <

=

m v

tD 1

r-

I IABLE 4.3-1 (Continued)

REACTOR. TRIP _STSTDI INSTRUNotTATION SURTEILEANCE_REOUIREMENTS d

TRIP ANALOG ACTUATING MODES FOR CHAMMEL DEVICE WICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE E

FUNCTIONAL UNIT CHECK CAllBRATION IEST IEST LOGIC TEST IS REOUIRED=

![

h6 MN Q(18)

M.A.

N.A.

1, 2

{

13. Steam Generator Water level-- S Low-Low

14. Low Shaft 5

- Reactor N.A.

R(13)

Q N.A.

N.A.

I Coolant s

15. Turbine Trip a.

Low Fluid 011 Pressure M.A.

R M.A.

5/U(1,10)****N.A.

1 l

b.

Turbine stop Yalve M.A.

R N.A.

5/U(1,IO)****N.A.

I Closure i

16. Safety Injection Input from N.A.

N.A.

R N.A.

1, 2 ESF y

t

17. Reactor Trip System Interlocks a.

Intermediate Range Neutron Flux P-6 N.A.

R(4)

R N.A.

N.A.

2**

b.

Low Power Reactor Trips Block P-7 N.A.

R(4)

R N.A.

N.A.

I c.

Power Range, Neutron Flux P-8 N.A.

R(4)

R M.A.

M.A.

I d.

Power, Range Neutron

/

Flux P-9 N.A.

R(4)

R N.A.

N.A.

I gf e.

Power, Range 5

Neutron Flux P 10 N.A.

R(4)

R N.A.

M.A.

1, 2 a

Pressure,pulseChamber

$u f.

Turbine im c

3 P-13 N.A.

R R

N.A.

1 S

F e

W

=

r e

TABLE 4.3-I (Continued)

REACTOR. TRIP.3T5 TEN INSTRUNDITATION SURTEILLANCE RE0WREMENTS l

TRIP ANALOG ACTUATING MODES FOR CHANNEL DEVICE WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTURTION SURVEILLANCE 3

FUNCTIONALUNIT CHECK CALIBRATION IEST IEST LOGIC TEST IS REQUIRED

18. Reactor Trip Breaker N.A.

N.A.

N(7,11)

N.A.

I 2 4,$*3*,

I 19.

Automatic Tri and N.A.

N.A.

1.A.

N.A.

N(7)

Interlock Log $c 1(I,2$*3*,

20. Three Loop Operation N.A.

N.A.

M.A.

R N.A.

1, 2 Bypass Circultry

21. Reactor Trip Bypass N.A.

N.A.

M.A.

MI 7 N.A.

RI,15)15) 4g

$,3*,

I 2 Breaker

22. Shutdown Margin Monitor N.A.

N.A Q(19)

N.A.

N.i.

3,4,5

)D

)'

s n 3-I B

B h

r k

t; E

E Y

/

=

l

~

USHRC DRPE TEL*301-415-2102 Apr 26'95 16:03 No.013 P.07 No Cka u y_

Tantr ts-1 teanti-M YABLE E TAT 10R$

When the Reactor Trip System bmakers em closed and the Control Rod Drive System is capable of rod withdrawal.

Selow P-5 (Intemediate Range Neutna Flux Interlock) Setpoint.

Selow P-10 (Low 5etpoint Power Range Neutron Flux Interlock) 5etpoint.

Above the P-9 (Reactor Trip / Turbine Interlock) setpoint.

(1)

If not perfomed in previous 31 days.

(t)

Comparison of calorimetric to excore power indication above IRE of RATD THERMAL POWER. Adjust excore channel gains consistent with calorimetric power if absolute difference is gnater than 25.

The provisions of Specification 4.0.4 are not applicable to entry into EDE 2 er 1.

(5)

Single point comparison of incon to excore AXIAL FLUX DIFFERENCE above 15% of RATED THERMAL POWER. Recalibrate if the absolute difference is greater than or equal to 35. The provisions of Specification 4.0.4 are not applicable for entry into MODE E or 1.

(4)

Neutron detectors may be excluded from CHAl0lEL CALIBRATION.

i (5)

Detector plateau curves shall be obtained, and evaluated and compared to j

manufacturer's data. For the source Range Intemediate Range and Power 1

Ran e Neutron Flux channels the provisions of Specification 4.0.4 are not app icable for entry into N0DE 2 or 1.

(6)

Incore - Excore Calibration, above 75% of RATE THERMAL POWER.

The provisions of Specification 4.0.4 are act applicable for entry into J

MODE 2 or 1.

I (7)

Each train shall be tested at least every 62 days on a STAGGERED TEST BAS!$.

(8)

(Notused)

(9)

Quarterly surveillanca la NODES 3*,

4*, and I* shall else include i

verification that permissives F-5 and P-10 are in their required state for existing lant conditions by observation of the pemissive annunciator wi i

i l

l m,tL5 Tour - astri s s/4 s.1s amendment me. pp. 7p.109 0

l

January 3,1995 TABLE 4.3-1 (continued)

No CW w A TABLE NOTATIONS fcontinued)

I" (10) Setpoint vertfication is not applicable.

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

Trip Breakers.

(12)

(not used)

(13) Reactor Coolant Pump Shaft Speed Sensor may be excluded from CHANNEL CALIBRATION.

(14) The TRIP ACTUATING DEVICE OPERATIONAL TEST shall independently verify the OPERABILITY of the undervoltage and shunt trip circuits for the Manual Reactor Trip Function. The test shall also verify the OPERABILITY of the Bypass Breaker trip circuit (s).

(15) Local manual shunt trip prior to placing breaker in service.

(16) Automatic undervoltage trip.

(17)

(not used).

(18) The surveillance frequency and/or MODES specified for these channels in I

Table 4.3-2 should be reviewed for applicability.

(19) Quarterly surveillance shall include verification that the Shutdown Margin Monitor is set per the CORE OPERATING LIMITS REPORT (COLR).

I I

NILL 5 TONE - LD(IT 3 3/4 3-14 Amendment No. 11. ff.100 i

ene 79 79.

72b

'$b pt 6/28/ 94 INSTRtMENTATION [,, 2/4.2.2 ENCfNrfRED IATfTY FEATURES ACTUAT10N 1Y1 TEN INSTRLMrWTATION ifMITINC CONDIT104 FOR OPERATIDN atn t 3.3.2 The Engineered Safety Features Actuation System (ESFAS) instrumentation 3 ,^ l channels and interlocks shown in Table 3.3-3 shall be OPERABLE with their Trip j$ Setpoints set consistent with the values shown in the Trip setpoint column of Table 3.3-4. n* v d. l 4# APPlftABillTY: As shown in Table 3.3-3. ~* 1 13 EIl0!f: e w.' 6% ' ~d WithanESFASInstrumentationhrInterlockfTripSetpointtripless& a. jj conservative than the value shown in'the Trip Setpoint column but L T jI sore conservative than the value shown in the Allowable Value column Bi of Table 3.3-4, adjust the Setpoint consistent with the Trip y{ 4{ 5etpoint value. v th id ] 1, Ih ku conservative than the value s[or Interlock \\ Trip 5etpoint 4ees b. With an ESFAS Instrumentation f[{ I jg hown in the Ailowable Yalue column of e Table 3.3-4, either: a. 7 [to 1. Adjust the Setpoint censistent with the Trip Setpoint value of I I I Table 3:1-4, and deterzine within 12 hours that Equation 2.2-1 I.k f was satisfied for the affected channel, or E) jj Declare the channel inoperable and apply the applicable ACTION [k 2. c statement requirements of Table 3.3-3 until the channel is f restored to OPERABLE status with its Set n# consistent with the Trip setpoint value. point adjusted F[ g Equation 2.2-3 2 + R + 5 5 TA Y Where: I = The value from Column 2 of' Table 3.3 4 for the affected n "f

channel, h,

R = The *as measured

value (in percent span) of rack error for the affected channel, 3

3 a Either the 'as sensured' value (in percent span) of the sensor f error, or the value from Column 5 (Sensor Error) of Table 3.3-4 j for the affected channel, and 7 TA = The value from Co'lumn TA (Total Allowance) of Table 3.3-4 for b the affected channel.

L A

<W e} b[y With an ESFAS instrumentation channel or interlock 1noperable, take c. the ACTION shown in Table 3.3 3. 3 [ D,, > W A*M Y r _wmra n_ nmn-

4 e, 4 w lMAE LT'W b Peg e. 3 /*( 3 - 15 b wel-y l w~ 4,,c ad. WM % ESFA5 ~Ew th wh hw C k a w d n 1 6 La.k(.b w l e _... C< wee.ph 4w > s sw4 e w pskn,4%ews!u~\\-L..Ihe.J 3% ~ -s u.m,% s -4.. o m.~ v. St.y.Q 4 c.= w6 ab&....WWw %=. v=6 e..tbum A N M -.., ',

u. A t rer s a c> ",

4-6 m s<- h s c w s u u ww w,_ N w-o we s<w vst_

c. w A u

u. au s wwasu cwwwa c~ w w w C. h s.w w f)

( tvt q0- %3&we$-Eev p asw% [ *acNewA$ MLt.sl O shm 3e% ( m 4 w ca= 6 te. M f b ckaw J v 4 b c.c.) l - E w aA %-. b < m o g < r k\\ <. .L e. d aw cb w w e.A 6o p bk c4.T.ht4.3.'3-3 uwM\\ 4%<. ck%ww aA (s v4.sh w A b i h w v4-d 7 Ap.Sc.h obv. vakt. j i i _.. ~ ~ - i. 4.= +

- a.

w.. ....w ao I "Wh* 4h.IIeih enesbe =

gas an-
- e

--e. .e. em _mee

mo

_,u.

== am =em. 4 e gem m.e ei

s. mi.

ee.no e.wm.m.. m= O e .= 'W W $$. .Oeh. 19 m h h &N w /* a.. .. =.. ..*-e e S*-p...., ..,,e wsp m.n.. .. e - - ~ - - - e w ~r< - - - - - - +

January 3,1995 INSTRUNENTATION SURVEILLANCE REQUIREMENTS 4.3.2.1 Each ESFAS instrumentation channel and interlock and the automatic actuation logic and relays shall be demonstrated OPERABLE by performance of the ESFAS Instrumentation Surveillance Requiremen s syc,1f, igd in, Table 4.3-g g 4.3.2.2 The ENGINEERED SAFETY FEATURES RESPONSE TIME

ofiach ESFAS jfuncus shall be demonstrated to be within the limit at least oncetper Is months) l q%

Each test shall include at least one train such that both trains are tested at least once perfl@ months and one ann (to include input relays to both trains)(fer-functlpftuch that all a66epare tested at least once @ / times 18 m66ths whe W Nl s the t Ispecific ESFAS function as showp'9tal number of7edundant,han~ne7s in ty ~ in the yTotal No. of Channels" column.g Qab1_e 3.3-3) f PM'b " \\ Pv"k'k'" beksCH) guer few tf h p.6 F UG L'Nb g r3 TE fo' A L. i

The provisions of Specification 4.0.4 are not applicable for response time testing of steam line isolation for entry into MODE 4 and MODE 3 and turbine driven auxiliary feedwater pump for entry into MODE 3.

3 J NILLSTONE - UNIT 3 3/4 3-16 Amendment No. Q, 77, #, 100 arm i

tenech 11. 1991 1A8tE 3.3-4 hw ENGINEERED SAFETY FEATURES ACTURTION 5Viitn in3inntniATION TRIP SETPOINTS s e-s TOTAL ) ALLONA9tE3ALUE g FUNCTIONALUNIT ALLOWANCE fTA) Z _ f51 TRIP.SETPOINT 1 U 1. Saf'ety injection (Reactor Trip, Feedwater Isolation, Control Sullding Isolation (Nanual Initiation Only), Start Diesel f Generators, and Service Mater) f a. Manual Initiation M.A. N.A. N.A. N.A. N.A. l b. Automatic Actuation Logic M.A. M.A. N.A. N.A. N.A. g c. Containment Pressure--High 1 3.3 1.01 1.75 $ 3.0 psig s 3.8 psig ,{ d. Pressurtzer Pressure--Low g<j.h,

1) Channels I and II

.22.16 20.1 1.5 ' 2 1877.3 psig 1 1868.5 psig

2) Channel III and IV 22.16 15.6 3.3

. 2 1877.3 psto 2 1863.3 psig e. Steam Line Pressure--Low 17.7 15.6 2.2 2 658.6 psig* 2 648.3 psig* 2. ContainmentSpray(CDA) a. Manual Initiation M.A. N.A. M.L. N.A. N.A. b. Automatic Actuation Logic N.A. N.A. N.H. N.A. N.A. and Actuation Relays [ c. Containment Pressure--High-3 3.3 1.01 1.75 s 8.0 psig s 8.8 psfg h 3. Containment Isolation n [ a. Phase 'A" Isolation ? b g

1) Nanual Initiation M.A.

N.A. N. N.A. f N.A. ^ ]' a L r*

TABlt 3.3-4 (Continued 1 ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRUNENTATION TRIP SETPolNTS '5 x u I\\ 8 TOTAL bd N# ' FUNCT10NAL UNIT All0WANCE fTAl I (S1_ TRIP SETPotNT ALLONA8trVALUE ,] 3. Containment isolation (Continued)

2) Automatic Actuation logic

.N.A. N.A. M.A. M.A. N.A. w and Actuation Relays ( 4 e preau

3) Safety injection See item 1. above for all Safety injecti rip Setpoints @.

(Allowable Yalue W h. Phase "B" Isolation y 1 Y

1) Nanual Initiation N.A.

N.A. N.A. N.A. N.A.

2) Automatic Actuation N.A.

M.A. M.A. M.A. N.A. logic and Actuation w 3 Relays

3) Containment Pressure--

3.3 1.01 1.75 5 8.0 psig i 8.8 psig High-3 4 Steam line Isolation a. Manual Initiation N.A. M.A. N.A. N.A. N.A. ,7 h. Automatic Actuation Logic N.A. N.A. N.A. M.A. N.A. [ g and Actuation Relays b c. Containment Pressure--High-2 3.3 1.01 1.75 $ 3.0 psig l 1 3.8 pstg 5 d. Steam line Pressure--Low 17.7 15.6 2.2 1 658.6 psig* 2 648.3 psig* l I8 Steam line Pressure - S.0 0.5 0 $ 100 psl/s** s122.7psl/sy c. Negative Rate--High %j t

x

~ .---n-

July 9, 1990 F _TABtt 3.3-4 (Continuedl ENGINEERED _ SAFETY FEATURES ACTUATION SYSTEN INSTRUNENTATION TRIP SETP0ffffS F c di SENSOR b TOTAL ERROR pomIN p [ [UNCTIONAL_ UNIT Al.l.0WANCE (TA1 Z (S) 1 RIP SETPolNT ALLOWABLE VALUE 9 q l 5. Turbine Trip and Feedwater lsolation [ q

4. O a.

Automatic Actuation logic N.A. N.A. N.A. N. A. M]4 N.A. Actuation Relays / @'pf.9 b. Steam Generator Water 5.25 3.76 1.50 's 80.45% of $. 81.47% of narrow c' y level--liigh-High (P-14) narrow range range Instrument 1 J instrument i span. i - 9 ermann. c. Safety injection Actuation y See Item 1. above for all Safety Injectio(Trip Setpoints and logic Allowable Value.. cl. T,,, low Coincident with Reactor Trip (P-4) g ~ ~ I) Four Loops Operating N.A. N.A. N.A. 2 564*F 1 560.6*F hj

2) Three loops Operating N.A.

N.A. N.A. 1 564*F A 560.6*F 4 6. Auxiliary Feedwater { q a. Manual Initiation N.A. N.A. N.A. N.A. M.A. h. Automatic Actuation logic N.A. N.A. N.A. N.A. IN.A.. . E and Actuation Relays c. Steam Generator Water M Level--Low-Low { S$ % A

1) Start Motor-Driven 18.10 16.64 1.50 Il 18.10% off j 217.11% of narrow Pumps narrow rame J range instrument

__ J instrument I' span. J span._ d

~ 03/74/94 1ABLE 3.3-4 fContinuedl SE ENGINtrRED SAFETY FEATURES ACTUAfl0N ii5ian INSTRUMDITAfl0N TRIP SETPotNTS SEMSOR N TOTAL ERROR N'" / FUNCTIONAL _IINIT ALLOWANCE ITA1 Z f5) TRIP SETPOINT ALLOWABLE YALUE W E 6. AuxiliaryFeedvater(continued) fyg 'f18.10 [

2) Start Turbine-16.64 1.50 1 18.101 of 117.11% of narr Driven Pumps narrow range.

range instrument V j instrumentJ span. y p t d. Safety injection See Item 1. above for all Safety injecti [r tpoints }nd M h e. loss-of-Offslte power M.A. N.A. 1 2800V [12720V Start Motor-Driven Pumps w> gotwidat-w f. Containment Depressurization See Item 2. above for all CDA tTrip Setpoints lnTAllowable Valuet. g 4 Actuation (CDA) Start Motor-Driven Pumps 7. Control Building Isolation I_ p I a. Manual Actuation M.A. M.A. M.A. N.A N.A. b. Manual Safety Injection N.A. N.A. N.A. N.A N.A. g Actuation 2 E 2 c. Automatic Actuation N.A. N.A. N.A. M.A. N.A. A Logic and Actuat,lon Relays d. Containment 3.3 1.01 1.75 < 3.0 psig -< 3.8 psig ? Pressure--High I ~ e. Control Building N.A. N.A. M.A $1.5 x 10-5pcl/cc{<l.5x10-5,c,7,el Inlet Ventilation I J Radiation (

11/30/94 , g3 IA8tE 3.3-4 (Contfneedl h ENGINEERED $AFETY FEATURES _ ACTUATION SYSTEN INSTNUNENTATION TRIP SETPOINTS i a m TOTAL R N /# g FUNETIONALUNIT 1 \\ $QOWANCEfTAl Z _f51 IRIP SETPOINI AIDPitE M UE '[ 8. toss of Power

a. 4 kV Bus Undervoltage

{ N.A. M.A. M.A. 2 2800 2 2720 volts (Loss of Voltage) volts with with a s 2 a 5 2 second second time J time delay. delay.

b. 4 kV Bus Undervoltage N.A.

N.A. N.A. A 3730 volts 2 3706 volts l (Grid Degraded Voltage) with a 5 8 with a s 8 second time second time delay w1th ESF dely wtth ESF Y actuation or actuation or 5 < 300 second 1300 second time delay time delay without ESF without ESF actuation. actuation. 9. Engineered safety Features f Actuation System Interlocks a. Pressertzer Pressure, P-11 M.A. M.A. N.A. s 1985 psfg 5 1995 psig F

b. tow-tow T,,,, P-12 N.A.

M.A. M.A. 2 553*F 2 549.6*F g c. Reactor Trip, P-4 ' N.A. N.A. N.A. N.A. N.A. .e

10. Eme,,em,.ene,ato, toad M.A.

N.A. N.A. M.A. W Sequencer y1* i

'l, c i Lt g n r e.k A 7 l5 4 *(,3 g il Yjj s v 9 A 8I1 3) 3 3 is 4 ^l Jg r5 g ~ j f d k, Et. <.f k d $w' _E 5 Nf qu'.ei.k

A

,su g k s.L 4 g g y g 5 ......n <JL # { }.- A L k. L 7 $ sf . P. g_. ,. g f. g 5

ij g

m a-2 1, 3 C A igt ? i3 s 23 f bb gb 3hef vi g j ~ m E g g s<.;- & J.s n 5, 3 g s e f 3 e p o m M o N 44 H 6

P 4

1 ~ p t 9 e.4 $ vi 7 9 u M s y l 4 7 a 4 6 T 7 w 68l [ 1 .i. g u. e ts 4 0 y V J w T T d Ch 7 h 3 3 if e ~ e y',s 6 c. ._. 4 [... - i.. . g., I ......_ ; p _3, x 2, <.,p 2. g. 3 g 3 a ... ].._..y< 4 e a . ei . p .. -g h... j[=q.m _. f _.j. E y.

g. {

i j i d.. .g J c, e)i o j s *{ 3, c i 2 s '1 J.<3 o 3 i~e1* 2 _c t [ c "e v J ~ !t d 73 o L....f j a 2 1 ^n S, 5 . U =.... g 1,1% s't u. ~} f 1~

j A)o Chh& Janury 31, 1986 SA fN f~C C)tu L-Y TApt.f 3.3*4 (Continued) TABLE NOTATIONS

Time constants utilized in the lead-lag controller for Steam Line Pressure-tow are tg 1 50 seconds and 12,5 seconds. CMANNEL CALIBRATION shall f

ensure that these time constants are adjusted to these values.

- The tis'Mr constant utilized in the rate-lag contes 11er for Steam Line Pressure-hepative Rate-High is less than er egual to 50 seconds. CNANNEL CALIBRAT 0N sr.all ensure that this 1, tee constant is adjusted to this value.

4 O ee O 4 6 e G t 9 8 e MIN - 1907 3 3/4 > 31

TANLL4.3-2 o l @% EMEINEERED SAFETY FEATWE5 ACTWTIM SYSTUI.INSTIMENIRIIS SURVEILLANCE REOUIREMUITS i l g TRIP ANAlos ACTUATING NooES CHAMEL DEVICE MSTER SLATE FOR WICil E CHAMEL CNAMEL OPERATIONAL OPERATIOML ACTWTION RELAY ~RELAT SURVEILUIEE 4 F E TIO M L W il .Cl!LCX_ CALIBRATION IEST IEST LOGIC TEST If.3I IEST_ 15.REOUIRED w

1. Safety injection (Reactor Trip.

Feedwater Isolation Control Building Isolation Manual Initiation Only Generators,and)$e$artDiesel rviceMater)

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. N(1) N(1) q 1, t, 3, 4 w logic and Actuation i Relays Y

c. Containment Pressure-S R

q N.A. N.A. N.A. N.A. 1, 2, 3 M High-1 16 r"'*

5 h

4 N.A. N.A. N.A. N.A. I, 2, 3

d. Pressurtzer Pressere-S Low

e. Steam Line N

q N.A. N.A. N.A. N.A. I, 2, 3 l Pressure-Low k, l2.ContainmentSpray i

a. Manual Initiation N.A.

N.A. N.A. R N.A. N.A. N.A. I, 2, 3, 4 l

b. Automatic Actuation N.A.

N.A. N.A. N.A. N(1) N(1) Q 1, 2, 3, 4 .I L tc and Actuation Re ays

c. Contelnment Pressure-S R

q N.A. N.A. N.A. N.A. I, 2, 3, 4 ~ 4, High-3 1 = 5 g a. u i

TABLE 4.3-2 fContinuedl tmp m t=0 CN'l !E DIGINEERED SAFETY FEniunEi ACTUATION STSTEN_INSTRUNENTATION 5tmrtILIIW;E REQUIRENENTS _ g TRIP ANALOG ACTUATING MODES E CHANNEL DEVICE NRSTER SLAVE FOR Mf!CN CHAMEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEI 4 FUNCTIONAL UNIT CHECK = CALIBPATION IEST IEST LOGIC TEST IESI IESL 15 REQUIRED _

3. Containment Isolation

a. Phase "A" Isolation

1) Manual Initiation M.A.

N.A. N.A. R N.A. N.A. N.A 1, 2, 3, 4 l 2)AutomaticActuation M.A. N.A. M.A. N.A. N(1) N(1) q 1, 2, 3, 4 L ic and Actuation Re sys es> 3)SafetyIn,fection See Item 1. above for all Safety injection Surveillance Regelrements. g,

b. Phase '8' Isolation l

w

1) Manual Initiation M.A.

M.A. N.A. R N.A. N.A. N.A 1, 2, 3, 4 l 2)AutomaticActuation M.A. M.A. M.A. M.A. N(1) N(1) q 1, 2, 3, 4 L ic Actuation Re sys I

3) Containment S

R q N.A. M.A. N.A. N.A. 1, 2, 3, 4 i Pressure-High-3 [;

4. Steam Line Isolation y

a. Manual Initiation

1) Individual N.A.

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

2) System M.A.

M.A. N.A. R N.A. M.A. N.A. 1, 2, 3, 4 l 8 i 5 8 3 m

.1 er p-n TABLE.4J-LIContinued) r'-- #~ ]h"'g 5 DNIINEENED SAFETT FEATURES.ACTUNTISN Sf5TER INSTNONERATISH SURVEILLANCE REQUIREMEE5 3 & M \\ TRIP ANALOG ACTMTIM NODES CHAMEL DEVICE NRSTER SLATE FOR WICN g CHAMEL CHANNEL OPERATIOML OPERATIONAL ACTURTION RELAY RELAY SURTEILLANCE 4 FUNCTIUMAL UNIT CHECK _ CALIBRATION TEST IEST LOGIC _.TESTIISI IESL IS..REOUIRED 4.SteamLineIsolatten(Continued)

b. Automatic Actuation N.A.

N.A. R.A. N.A. M(1) M(1) 4 1, 2, 3, 4 togic and Actuation Relays

c. Containment Pressure-5 R

q N.A. R.A. N.A. N.A. 1, 2, 3, 4 High-Z r

d. Steam Line 5

R q N.A. N.A. R.A. N.A. 1, 2, 3 /' s Pressure-Low

e. Steam Line Pressure-5 R

q N.A. N.A. M.A. N.A. 3

g Negative Rate-Nigh

5. Turbine Trip and Feeduster Isolation

a. Automatic Actuation N.A.

N.A. N.A. N.A. M(1) M(1) 4 I, 2 Logic and Actuation g Relays

b. Steam Generator Water 5

ft'18 N W> q N.A. M(1) M(1) q 1, 2, 3 j 5 Level-High-Nigh

c. Saf'et Injection M.A.

N.A. N.A. R N.A. N.A. N.A. 1, 2 ,I ActuaffenLogic ~ 4 R

d. T, low Coincident N.A.

R 4 h.3. N.A. M.A. N.A. I, 2 withReactorTrip(P-4) 4 1 m 8

January 3, 1995 a a a d d a 5 ,jd 44 4 ,4 4 4

E

=sa .a s gra Lsa .d3 4 44 3 d l!.- E !-il i, .s - s< s = g E-5A SE~5 s I =I 0 E M 4 4 E 4 4 a EM55W .i i 22-a i bl 3..h it n s"g }_E 8 38 gg m 3 9 m ss

=

ss s n E B" ii+a ii a a k h* *h h s 2 W i g5g 5 l E jj2 i E 4s dd 4 QEEE ...-~ i 2== 44 44 i yyy M M E E g g 3 BE 4 ) al 5 5 55 E , 3. e*gs ss =k g =g s ss i 3 2 BwC 88 E geEC y e D M- % i "3 MM a g e $N I k,.=_ 2N E3 $1l IEjilus .e 2 I,s E 3 yhe y l aI III h . 8 I. = -- E se -s a 5ei a see ~ei a a a a 6

January 3, 1995 l 6 A A ""A y 4 4 4 44 4 ly ,e %,h wgu 4 4 4 e 44 4 Egg = = = =

=

2. 5-4 d i d <dd gg = = = =

=

t Il C h i < dd d = = = = = = or 4 h Ecwc eBu a w w aa a E EW55*m g 4 E E d en 4 _,g -a I g La E 5 4 44 = = . = = 1 ,L ( E e g ~ 44 \\ Q G u a a nai u l lEI._ =< =< < u< =

=

s I b, = =_ =. s a s 44 t , ;g .g, :,n =..E B b IA $8,! % *8st I.= 4 $ - IE-3 A k I a yaf a. = paEl 4 kI8k s, -- EER.IE== + y .E.E.E.* ".l. ". = bd bd i EEE 4 AJ A i i i s 9%- RILLSTONE - UNIT 3 3/43-40 Amendment No. M. M. 77. 77 100 m

i TABLE 4.3-2 (Continued) " ""7 A>u C La ng TABLE NOTATIM g,, .u o,u g, y (1) Each train shall be tested at least every 62 days on a STAGGERED TEST BASIS. (2) This surveillance may be performed continuously by the emergency generator load sequencer auto test system as long as the EGLS auto test system is demonstrated operable by the performance of an ACTUATION LOGIC TEST at least once per 92 days. (3) On a monthly basis, a loss of voltage condition will be initiated at each undervoltage monitoring relay to verify individual relay operation. 3etpoint verification and actuation of the associated logic and alam relays will be performed as part of the channel calibration required once per 18 months. NILLSTONE - IB(IT 3 3/4 3-41 Amen 6mnt No. FJ. 77 77, 100

m 'jF TABLE 4.3-3 m RADIATION MONITORING INSTRtMENTATION FOR PUWIT 25 'rtaarnaas 5'RVEilu Cr REevlREnEnr5

k ANALOG e

CHANNEL MODES FOR WNICH E CHANNEL CHANNEL OPERATIONAL SURVEILLANCE ~ FUNCTIONAL UNIT CHECK CALIBRATION TEST IS REQUIRED q i 1. Containment a. Containment Area Purge and Exhaust Isolation 5 R Q 5, 6 g b. RCS Leakage Detection

1) Particulate Radio-5

@ FS N b Q 1, 2, 3, 4 ft activity U[ ) 2)GaseousRadioactivity 5 QC)lSNb Q 1, 2, 3, 4 2. Fuel Storage Pool Area Monitors j a. Radiation Level 5 @ 16 %IN Q j 7h i TABLE NOTATIONS k

With fuel in the fuel storage pool area.

i c_ a l I a =. i 8 ,_ J

i January 3,1995 REMOTE SHIRDO W INSTRUMENTAT]pN LIMITING CONDITION FOR OPERATION 3.3.3.5 The Remote Shutdown Instrumentation transfer switches, power, controls and monitoring instrumentation. channels shown in Table 3.3-9 shall be OPERABLE. i APPLICABILITY: MODES 1, 2, and 3. AGI1(E: a. With the number of OPERABLE remote shutdown monitoring channels less than the Minimum Channels OPERABLE as required by Table 3.3-9 restore the inoperable channel (s) to CPERABLE status within 7 days, or be in HOT SHUTDOWN within the next 12 hours. b. With one or more Remote Shutdown Instrumentation transfer switches, power, or control circuits inoperable, restore the inoperable switch (.s)/ circuit (s) to OPERABLE status within 7 days, or be in HOT STANDBY within the next 12 hours, c. Entry into an OPERATIONAL MODE is persitted while subject to these ACTION requirements. i SURVEILLANCE REQUIRENDITS i 4.3.3.5.1 Each remote shutdown monitoring instrumentation channel shall be demonstrated DPERABLE by performance of the CHANNEL CHECK end CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3-6. 4.3.3.5.2 Each Remote Shutdown Instrumentation transfer switch, power and control circuit including the actuated components, shall be demonstrated OPERABLE at least once ( g e at ru sade w ru a u I [L N LLSTONE - IMIT 3 3/43-53 Amendment No. F7, 77, 100 e+7

jV o CbehK i september 26, 1990 TABtE3.3-9 E F KnoTL surtDO W INSTRUMUtfATION

13 total No.

NintMUN RtAnmrt oF Caumtts m INSTRUMUff toCATION DWWlELS OPERABLE k 1. Reacter Trty Breaker Indication Reactor Trip Switchgear 1/trty breaker 1/trtybreaker 2. Pressertrer Pressere Aux Shutdown Panel 2 I 3. Pressertzer Level Aux. Shutdown Panel 2 1 4 Steam Generator Pressere Aux. Shetdown Panel 2/steamgenerator 1/steamgenerator 5. Stean Generator Water tevel Aux. Sheldown Panel 2/ steam generater 1/steamgenerator 5. Auxtitary Feedwater Flow Rate Aux. Sheldown Panel 1/steamgenerator 1/steamgenerator 7. Loop Met leg Temperature Aux. Shutdown Panel 1/ loop 1/ loop 8. Loop Cold leg Temperature Aux. Shutdown Panel 1/ loop 1/ loop 9. Reacter Coolant System Pressere Aux. Shutdown Panel Z I DW5TLevel) (Wide Range Aer. 5kdown Panel 2 I 18 w II. RWST Level Aux. Shutdown Panel 2 1 1

12. Contalmeent Pressere Aux. Shutdown Panel 2

I

13. Emergency Bus Voltmeters Aux. Shutdown Panel I/ trita 1/ train wg

14. searce Range teent Rate Aux. Shutdown Panel 2

1

15. Intermediate Range Flex Aux. Shutdown Panel 2

I

15. Berle Acid Tank Level Aux. Sheldoun Panel 2/ tank 1/ tank TRANSFER _5IFITUIES SW1TtN LOCATIOlf

1.. Aust11ery Feedwater Isolatten 711R*MOV35A Transfer Switch Panel 2.

Aux 111ery Feedwater Isolation FM*MDV358 Transfer Switch Panel l 3. Auntitary Feedwater Isolation FWR*MOV35C Transfer Switch Panel 4. Aunt 11ary Feedwater Isolation FWA*MOV350 Transfer Switch Panel F 5. Aunt 11ery Feedwater.Pemy Ah. Section g FWA*AoV23A Transfer Switch Panel g 8. Aux 111ery Feedwater Pump Ah. Section FWR*ADt238 Transfer Sultch Panel g ?.

~ p g TABLE 3.3-9 (Cor:tinued) ggg h RENDTE SHUTDOWN INSTRUE NfATISH TRANSFER SWITCHES SWITCH k LOCATION 7. Tusine Driven Pump Steen Supply E MSS *A0V3IA Transfer Switch Panel Q 8. Turbine Driven Pump Stean Supply MSS *A0v318 Transfer Switch Panel w 9. Turbine Driven Pump Stean Supply MSS *ADV310 Transfer Switch Panel 10. Reactor Vessel Head Vent Isolation RCS*SV8095A Transfer Switch Panel i 11. Reactor Vessel Head Vent Isolation RCS*SV80958 Transfer Switch Panel l

12. Reactor Vessel Head Vent Isolation RCS*SV8096A Transfer Switch Panel w)

13. Reactor Vessel Head Vent Isolation RCS*SV80968 Transfer Switch Panel w

J.

14. Reactor Vessel to Excess Letdown RCS*MV8095 Transfer Switch Panel

15. Pressurizer Level Control RCS*LCV459

. Transfer Switch Panel

16. Pressurizer Level Control RCS*LCV460 Transfer Switch Panel 17.

Letdown Orifice Isolation CHS*AV81494 Transfer Switch Panel 18. Letdown Grifice Isolation CHS*AV81498 Transfer Switch Panel

19. Letdown Orffice Isolation CHS*AV8149C Transfer Switch Panel

20. Volume Control Tank Outlet Isolation CHS*LCY1128 Transfer Twitch Panel i'

21. Volume Control Tank Outlet Isolation CHS*LCV112C Transfer Switch Panel 22.

RWST to CMS Pump Section CHS*LCV1120 Transfer Switch Panel 23. RWST to CHS Pump Section CMS *LCV112E Transfer Switch Panel

24., Charging to RCS Isolation CHS*AV8146 Transfer Switch Panel

25. Charging to RCS Isolation CHS*AV8147 Transfer Switch Panel

26. Boric Acid Gravity Feed CHS*MV8507A Transfer Switch Panel

]

27. Boric Acid Gravity Feed CMS *MV85078 Transfer Switch Panel

n TABLE 3.3-9 (Continued) ' MN 31 J$ [. E _ REMOTE SHllTDOW INSTIMENTATION N o TitANSFER SWITCHES SWITCH E LOCATION

28. Charging Header Isolation Bypass E

CnS*Ws116 Transfer Swltch Panei Z

29. Pressurizer Heater Backup RCS*H1A

. i w (Group A) Transfer Switch Panel

30. Pressurizer Heater Backup RCS*H1B (Group B)

Transfer Switch Panel CONTROL CIRCUITS SWITCH LOCATION ' 1. Aux 111ary Feedwater Flow Control FWA*W31A Aux 11fary Shutdown Panel R 2. Auxiliary Feedweter Flow Control FWA*W318 Auxf11ary Shutdown Panel T 3. Auxiliary Feedwater Flow Control E FWA*W31C Auxi11ary Shutdown Panel 4. Auxiliary Feedwater Flow Control FM*W310 Aux 111ary Shutdown Panel 5. Auxiliary Feedwater Flow Control FWA*W32A AuxI11ary Shutdown Panel 6. Auxiliary Feedwater Flow Control FWA*W328 Auxfilary Shutdown Panel 7. Auxiliary Feedwater Flow Control FWA*W32C Auxfilary Shutdown Panel 8. Auxi11ery Feedwater Flow Control FM*W320 Aux 1Ifary Shutdown Panel 9. Aux 111ary Feedwater Flow Control FWA*W36A Auxi11ary Shutdown Panel

10. Adk111ary'Feedwater Flow Control FWA*W368 Auxfilary Shutdown Panel

11. Auxiliary Feedwater Flow Control FWR*W36C Aux 111ary Shutdown Panel

12. Auxiliary Feedwater Flow Control FM*W360 Auxf1Iary Shutdown Panel l

I 1 v v v ,ww r

JAN 31 1986 TABLE 3.3-9 (Continmed) AfockaA;g, f RENDTE SHUTDOW INSTRUENTATION E O E CONTR01. CIRCUITS SWITCH 8 LOCATION g

13. Reactor vessel to PRT Control g

RCS*HCV442A Auxiliary Shutdown Panel

14. Reactor Vessel to PRT Control RCS*HCV4428 Aux 111ery Shutdown Panel

15. Charging Header Flow Control CMS *HCV190A Auxiliary Shutdown Panel

16. Charging Header Flow Control CHS*HCV1908 Auxi11ery Shutdown Panel

17. Excess Letdown Flow Control CHS*HCV123 Auxiliary Shutdown Panel

18. Charging Flow Control CHS*FCV121 Auxiliary Shutdown Panel 19.

Low Pressure Letdown Control CHS*PCV131 Auxiliary Shutdown Panel R Y 5 m

A/a Chang TABLE _4.3-6 ' !p ^ RENOTE_3MUTDONN _MentTORINR _INSTRUMMIMIgg y SURVEILLANCE _REQUIREMUITS R Cn ct Connct INSTRUMENT _ CHECK-CAllBRATION 1. Reactor Trip Breaker Indication M N.A. 2. Pressurizer Pressure M .R' 3. Pressurizer Level N R t 4. Steam Generator Pressure M R 5. Steam Generator Water Level M R 6. Aux 111ery Feeduster Flow Rate M R 7. Loop Met Leg Temperatum M R 8. Loop Cold Leg Temperature M R R g. Reacter Coelant System Pressure M R i [ (WideRange) h

10. DNST Level M

R

11. RWST Level M

R

12. Containment Pressure M

R

13. Emergency Bus Voltmeters M

R

14. Source Range Count Rate M*

R Ef 15. Intemediate Range Amps M R g 16. Boric Acid Tank Level M R So 5 men below P-8 (intermediate range neutron finx interteck setpoint). 8 F s* y

l 2/18/93 INSTRUMENTATION' blU GNiq (, ACCIDENT MONITORING'1NSTRtMENTAT10N LIMITING CONDIT10e FOR OPERATION l 3.3.3.6 The accident monitoring instrumentation channels shown in Table 3.3-10 shall be OPERABLE. APPL 1CABILITY: MODES 1, 2, and 3. ) AC.10ti: i With the number of OPERABLE accident monitoring instrumentation s. channels except the containment area high range radiation monitor, l the containment hydrogen monitor, and reactor vessel water level, 1ess than the Total Number of Channels shown in Table 3.3-20, restore the inoperable channel (s) to OPERABLE status within 7 days, or be in at least HOT STANDBY within the next 6 hours and in at least HOT SHUTDOWN within the following 6 hours. b. With the number of OPERABLE accident monitoring instrumentation channels except the containment area-high range radiation monitor, the containment hydrogen monitor, and reactor vessel water level less than the Minimum Channels OPEAABLE requirements of Table 3.310, restore the inoperable channel (s) to OPERABLE status within 48 hours or be in at least HOT STANDBY within the next 6 hours and in at least HOT SHUTDOWN within the following 6 hours. With the number of OPERABLE channels for the containment area high c. range radiation monitor less than required by either the tptal or the Minimum Channels OPERABLE requirements, initiate an alternate method of monitoring the appropriate parameter (s), within 72 hours, and either restore the inoperable channel (s to OPERABLE status within 7 days or prepare and submit a Special ) Report to the Comis sion, pursuant to Specification 6.g.2, within 14 days that provides actions taken, cause of the inoperability, and the plans and sched-ule for restering the channels to OPERABLE status, d. With the number of OPERABLE channels for the containment hydrogen monitors less than the total number of channels shown in Table "#.3-10, restore the inoperable channel to OPERABLE status within 30 days or be in at least HOT STANDBY within the next 6 hours and in at least HDT SHUTDOMN within the following 6 hours. With the ~ number of operable channels for the containment hydrogen monitors less than the minimum channels OPERABLE requirement of Table 3.3-10, restore the inoperable channel (s) to OPERABLE status within 72 hours or be in at least HOT STANDBY within the next 6 hours and in at least HOT SHUTDOWN within the following 6 hours. With the number of OPERABLE channels for the reactor vessel water e. 1evel mor,itor less than the Total number of Channels shown in Table 3.3-10, either restore the inoperable channel to OPERABLE status within 7 days if repairs are feasible without shutting down or prepare and submit a Special Report to the Comission pursuant to Specification 6.9.2 within 30 days following the event outlining the 4 .-s-

L e' n g N#C 2/18/Q3 LIMITING CONDITION FOR OPERATION (Continued) action taken, the cause of the inoperability, and the plans and schedule for restoring the channel to OPERABLE status. With the number of OPERABLE channels for the reactor vessel water f. level monitor less than the minimum channels OPERABLE requirements of Table 3.3-20, either restore the inoperable channel (s) to OPERA-BLE status within 48 hours if repairs are feasible without shutting down or: Initiate an alternate method of monitoring the reactor vessel 1. inventory; Prepare and submit a Special Report to the Comission pursuant 2. to Specification 6.9.2 within 30 days following the event outlining the action taken, the cause of the inoperability, and the plans and schedule for restoring the channel (s) to OPERABLE status; and Restore the channel (s) to OPERABLE status at the next schedule 3. refueling. Entry into an OPERATIONAL MODE is permitted while subject to these g. ACTION requirements. SURVElttaNCE RE00fREHERTS shall be demon-Each accident monitoring instrumentation channel strated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRA 4.3.3.6 at the frequencies shown in Table 4.3-7.

February 21, 1990 88 1A9tt_3.349 N g BCCIDUff MONITORIM_IN51110 Muff 4fl0ll 'N . No. OF CnmNutLS TOTAL RINIMUM g JW511tunOft Cle mELS EEUNLE C

1. Containment Pressere a.

Normel Range t 1-b. Extended Range 2 I l

2. Ilesctor Coelant Outlet Temperatore - Tygg(WfdeRange) 2 I~

3. Elesctor toelant Inlet Temperature - TmW(ffdeRange) 2 i

4.. Reacter Coolant Pressere - Vfde Range .2 i S. Pressertzer Weter Level 2 1 { 8. Steam Line Pressere 2/steengenerator 1/stesegenerator.

7. Steam tenerator Water Level - Narrow Range 1/steen generater ' 1/stese generator S. Steam Cenerator Water Level - Vfde Range I/stesegenerator I/stesegenerster

g. RefW1 tag Water Storage Tant Water tevel 2

1 19 Deutneralfred Watee Storage Tank Water Level 2 1 3 II. Aetf11ery Feeheter Flow Rate 2/ steam generator 1/steen generator f i

12. Ileecter Coolant System Sobeoollag Mergfa Montter t

i 3 ~

13. Centafament Water tevel (Wfde Range) 2 1

14. Core Exit TheruscouPles 4/ core goedront 2/teregoodront

15. OtttTtt

~ ~ 7 q.'sa* ? $.,.:. 1nett_3.3_-ne IContinsedi ACCIDENT MONITORINIlLINSTRUMENTATl0ll Totat Nintnen INSTRUMENT

90. OF CHANNELS CHANNELS OPERABLE

16. Containment Area - N1gh Range RadIatten MenIter 2

1

17. Reacter Vessel Water level 2*

l'

18. Containment 0,."..;.

Monitor 2 I Ig. Neutron Flex 2 1 cA channel consists of eight sensors in a probe. the opper head reglen and half er more In the opper plenom region, are operable.A channel is operable if D C D? a u e m - w w- _ - - - -, - ~ - a e-

TMLE 4.3-1 E ACCIDDir McMITURINE INSTIWMENTATISM SURVERIAMct REgWran=;3_ 5 IIISTRUMDIT Ot4WIEL OWWWIEL _ DECK CALIBRAllW 1. Centainment Pressure E a. normal Ravige 4 b. Extended Range M R M R w 2. Reactor Coolant Detlet Temperature - T,,er (Wide Range) M R 3. Reactor Coelant inlet Temperature - Tei,u, (Wide Range) ' N R 4. Reacter Coelant Pressure - Wide Range M R 5. Presseriter Water Level M R [ 6. Steam Line Pressure M R 7. Steam Generater Water Level - Marrow Range M R, -- 8. Steam Generator Water Level - Wide Range M R g. Refueling Water Storage Tank Water Level M R 10. Domineralfred Water storage Tank Water Level M R 11. Aux 11tary Feedseter Flew Rate M R g 12. Reacter Coolant System Subceoling Margin Monitor M R kR 13. Containment Water Level (Wide Range) M .R o go f 14. Core Exit Thersecesples M R f 15. DELETED ) X l ~._._.__

TABLE.4.3-Litentinsed) I l5 ACCIDDIT MONITORINE INSTRINENTATIM SURTEILUUICE ItEEWI""""5 R CM=tt C ct INSTRUMDIT g _CHCCIL CALIBRAll0ll 16. Containment Area - High Ransa Radiation Monitor M R* l 17. Reacter Tessel Water Level M R** 18. Centainment 4 ", _;;.. Monitor M R 13. flestron Flex M R l M,, e. 3

CMMet CALIBMTI0li may consist of an electronic calfbration of the channel, not including the detector, for range decades above 10 R/h and a one point calibration check of the detector below 10 R/h with an installed er portable gamme source.
- Electnnic calibration from the ICC cabinets only.

l 5 sr h a >5 a y 6 5 n = 4 T 4 n I i X

.JAN 31 1986 TABLE 4.3-8 RADI0 ACTIVE LIQUID EFFLUENT MDNITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS u NE m ANALOG e CHANNEL e CHANNEL SOURCE CHANNEL OPERATIONAL ] INSTRUNENT CHECK CHECK CALIBRATION TEST 1. Radioactivity Monitors Providing Alarm and Automatic Termination of Releases gge* a. Waste Neutralization Sump Monitor-D P g(2) Q(1) Condensate Polishing Facility b. Turbine Building Floor Drains D M gra #R(2) Q(1) { c. Liquid Waste Monitor D P gr%2) Q(1) T d. Regenerate Evaporator Monitor-D M t4F 2) Q(1) U Condensate Polishing Facility (5) @W)(2) Q(1) e. Steam Generator Blowdown Monitor D M 2. Flow Rat: 1easurement Devices N dpe a. Waste Neutralization Sump Effluents D(3) NA y Q b. Turbine Building Floor Drains D(4) NA NA NA c. Liquid Waste Effluent Line D(3) NA \\1 Jt' Q

e5 d.

Regenerate Evaporator Effluent Line (5) D(3) NA

(

Q +s i FX Q i e. Steam Generator Blowdown Effluent Line D(3) NA Yb i f. Dilution Water Flow D(4) NA NA NA -,,v.,- .., ~., -.,.~,

D0C N Wp< 4 TABLE 4.3-8 (Continued) 9 0-l^4Eu Od'M JAN 311986 TABLE NOTATIONS k (1) The ANALOG CHANNEL OPERATIONAL TEST shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occur if any of the following conditions exists: Instrument indicates measured levels above the Alann/ Trip Setpoint, or . a. b.' Circuit failure (Alarm only), or c. Instrument indicates a downscale failure (Alarm only). (2) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used. ~ (3) CHANNEL CHECK shall consist of verifying indication of flow during periods of release. CHANNEL CHECK shall be made at least once per 24 hours on days on which continuous, periodic, or batch releases are made. (4) Pump status shall be checked daily for the purpose of determining flowrate. (5) Surveillance is required only if the monitor is required to be OPERABLE by Table 3.3-12.. t e 8 k MILLSTONE - UNIT 3 3/4 3-73 4 . -.... ~.

January 31, 1986 TABLE 4.3-9 x fg RA010 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE _ REQUIREMENTS Sfs e6 m ANALOG e CHANNEL MODES FOR WHICN c CHANNEL SOURCE CHANNEL OPERATIONAL SURVEILLANCE INSTRUMENT CHECK CHECK CAllBRATION TEST IS REQUIRED 1. M111 stone Unit 3 Ventilation vent Stack (Turbine Building) e W \\6 @ l)

a. Noble Gas Activity Monitor D

M Q(2)

b. Iodine Sampler W

N.A. N.A. N. A.

c. Particulate Sampler W

N.A. N.A. N.A. {

d. Stack Flow Rate Monitor D

N.A. yN Q "4

e. Sampler Flow Rate Monitor D

N.A. ,3P Q 2. Millstone Unit 1 Main Stack \\,7"g

a. Noble Gas Activity Monitor D

M R(3) Q(2)

b. Iodine Sampler W

N.A. N.A. N.A.

c. Particulate Sampler W

N.A. N.A. N.A. ks V

d. Stack Flow Rate Monitor D

N.A. ,R e Q Y t

e. Sampler Flow Rate Monitor D

N.A. ,fP l% Q

JAN 31 1986 TABLE 4.3-9 (Continued) 2pD RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS Gf? g E ANALOG . CHANNEL MDDES FOR WHICH CHANNEL SOURCE CHANNEL OPERATIONAL SURVEILLANCE e g INSTRUMENT CHECK CHECK CALIBRATION TEST IS REQUIRED 3. Engineered Safeguards Building Monitor m \\W

a. Noble Gas Activity Monitor D

M f(1) Q(2)

b. Iodine Sampler W

N.A. N.A. N.A.

c. Particulate Sampler W

N.A. N.A. M.A. vv4 {

d. Discharge Flow Rate Monitor D

N.A. K \\ Q t Y

e. Sampler Flow Rate Monitor D

N.A. / I" Q 5 4. Warehouse No. 5 Vent b

a. Noble Gas Monitor D

N.A. /t(3) N.A.

b. Iodine Sampler D

N.A.gg #,R(3) N.A.

c. Particulate Sampler D

N.A. (3) N.A. p

N o (bh-)R TABLE 4.3-9 (Continued) dNN 01 lE TABLE NOTATIONS At all times except when the vent path is isolated. When the gross activity of the regenerated waste is greater than 1 x 10 4 microcuries/.nl. (1) The initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used. (2) The ANALOG CHANNEL OPERATIONAL TEST shall also demonstrate that control room alarm annunciation occurs if any of the following conditions exists: Instrument indicates measured levels above the Alarm Setpoint, or a. b. Circuit failure (not applicable to Unit 1 Stack Monitor), or I c. Instrument indicates a downscale failure. (3) The CHANNEL CALIBRATION shall include the use of a known source whose strength is determined by a detector which has been calibrated to an NBS i These sources shall be in a known, reproducible geometry. source. e Eb MILLSTONE - UNIT 3 3/4 3-80

I i January' 31, 1986 i [ \\ 3/2. 3 IN!**WENTATION I pasf5 i l 3/4.3.1 sad 3/4.3.2 FEATOEE5 ACTueTION 5YSTEM JN5TKuMENTATION 1 Fwt ceW mv Ammar' l Festeres Acustica Systes instrumentation and interloc succiate ACTION and/or Reactor trip will be initiated when the parameter I (1) th. monitored by each cr.annel or cambination thereof reaches its Setpo specified coincidence logic is maintained, tained to permit a channel to be out-of-serv (3) sufficient redundancy is main - ~ ice for testing or maintenance and (4) sufficient system functional capability is availabJe from diverse, parameters. The OPERASILITY of 'these systems is required to provide the eve'ral reifabf Hty, redundancy, and diversity assumed available in the facil . design far the protection and mitigation of accident and transient condit The integrated operation of each of these systems is consistent with the assumptions used in the safety analyses. maintained comparable to tne original design stand T, 1ance tests performed at the minimum frequencies are sufficient to dem The periodic surveil-this capability. The Engineered Safety' Features Actuation System Instrumentation T Setpoints specified in Table 3.3-4 ers.the nominal values at which,the hi are set for each functionef unit. consistent with the nominal value when the 'as measured",5etpo the band allowed far ca,libration accuracy. i To accommodate the instrument drift assumed to occur between operatio tests and the accuracy to which Setpoints can be measured and calibrated. Allowable Values for the Setpoints have been specified in Table 3.3-4. tion with setootnts less conservative than the Trip setpoint but within the Ocora-analysis to accommodate tAis error. Allowable Value is acceptable An optional provision.has been fac1uded for determining the OPEAABILITY of a channel when its Trip setpoint is found to exceed the Allowable Valve. The methodology of this optian utilizes the

'as measured" deviation from the specified caHbration point for rack and sensor components in conjunction with a statistical combinetten of the other uncertainties of the instrumentation to measure the process variable and the uncertainties in calibrating the instrumentation.

In Equatten.3.3-1, Z

R 5 e TA, the interactive. effects of the errors in the rock.and the senser i

specifIedinTable3.3-4and the "as measured" values of the errors are considered.' 2 in percent span, is the stat'istical sumatlan i ef errers assmed in the', analysis escluding those associated ~with the sen. and rock drift and the accuracy of their sessurement. '..TA ar.. Total"A11swance, ser is the difference, in percent span, R er Rock Error is the'"as ~aeasured" i deviation f, Trip Sespo, int. in the percent span, for the affected channel frea,the specified c yf9 / 5 or sanser Error is either the 'as asasytetf,,devjatie.n.ef i 8 3N 5-/ ?

l (O tt M %W IMS3mME*W10N +, Pa p 3 3/y 3.L r::: 3/4.3.1 andf 3/4_2.2 #FAr m _ TRIPLY!TE" I!:: wun Ailun anu iNGINEERED SAFETY FEATURES ACMOTION SYSTEM INSTRL'"I"I^?: (;;r,;ir,ued) l within the two sided (*) calibration tolerance. Plant procedures set administrative limits ("as left" and "as found" criteria) to control the detemination of operability by setting minimum standards based on the methodology in WCAP-10991 and the uncertainty values included in the determination of the Nominal Trip Setpoint, and allow the use of other device characteristics to evaluate operability. REPORTABLE EVENTS are identified when the minimum number of channels required to be operable are not met. The methodology, as defined in WCAP-10991 to derive the Nominal Trip Setpoints, is based upon combining all of the uncertainties in the channels. Inherent in the detemination of the Nominal Trip Setpoints are the magnitudes of these channel uncertainties. Sensors and other instrumentation utilized in i i these channels should be capable of operating within the allowances of these uncertainty magnitudes. Occasional drift in excess of the allowance may be detemined to be acceptable based on the other device perfomance characteristics. Device drift in excess of the allowance that is rmre than occasional, may be indicative of more serious problems and would warrant further investigation.

l 6/28/94 INSTRUMENTATION .) nASES REACTOR TRIP SYS"EM INSTRUMENTATION and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMEN"ATION (Continued) the sensor from its calibration point or the value specified in Table 3.3-4, in percent span, from the analysis assumptions. Use of Equation 3.3-1 allows for a sensor drift factor, an increased rack drift factor, and provides a I threshold value for REPORTABLE EVENTS. The methodologv ee derive the Trip Setpoints is based upon combining all of the uncertainties is the channels. Inherent to the determination of the i Trip Setpoints are the mag 6itudes of these channel uncertainties. Sensor and rack instrumentation utilized in these channels are expected to be capable of operating within the allowances of these uncertainty magnitudes. Rack drift in excess of the Allowable Value exhibits the behavior that the rack has not met its allowance. Seing that there is a small statistical chance that this will happen, an infrequent excessive drift is expected. Arck or sensor drift, in excess of the allowance thtt is more than occasional, may be indicative of more serious problems and should warrant further investigation. t m a s. a.T V The measurement of response time at the specified frequencies provides assurance that the Reactor trip and the Engineered Safety Features actuation associated with each channel is completed within the time limit assumed in the ] safety analyses. The RTS and ESF response times are included in the Operating Procedure OP-3273 ' Technical Requirements--Supplementary Technical Specifications.' Any changes to the RTS and ESF response times shall be in accordance with Section 50.59 of 10CFR50 and approved by the Plant Operations Review Committee. No credit was taken in the analyses for those channels with i 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. Sensor response time verification may 4 demonstrated by either: (1) in place, onsite, or offsite test measurem=uts, or (2) utilizing replacement sensors with certified response time. Detector response times may method described in the Westinghouse Topical Report, gonse time degradatio be measured by the in situ on line noise analysis-res The Use of Process Noise Measurements To Determine Response Characteristics of Protection Sensors in U.S. Plants," August 1983. O Cd.k/ NILLSTONE - IB(If 3 3 3/4 3-1 AmendmentNo.[.9y s

? P345ILTh h $. Q t 3*++-W*mm8* +v P.g s h 3 n 3/4.3.beid 3/4.U REACTAR TRIP M950 INSTomrNTATION AND ENGINEERED SAFETY FEATRRES E TUAfTON lySTr# INP O T NTATICi " ~ o 4 6 LeLum*J N IL rvl A r' The DPERABILITY of the Reactor irip System and the Engineered Safety Features Actuation System instrumentation and interlocks ensures 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, i specified coincidence logic is maintained, (3) sufficient redundancy is maintained to pemit a channel to be out of service for testing or maintenance, and (4) sufficient system functional capability is available from diverse parameters. The DPERABILITY of these systems is required to pruvide the overall / 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 systems is consistent with the assumptions used in the safety 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 perfomed at the minimum frequencies are sufficient to demonstrate this capability. The Engineered Safety Features Actuation System Nominal Trip Setpoints specified in Table 3.3-4 are the nominal values at which the bistables are set , for each functional unit. The Nominal Trip Setpoints are considered the Limiting Safety System Settings as identified in 10CFR50.36 and have been selected to mitigate the consequences of accidents. A Setpoint is considered to be consistent with the nominal value when the measured "as left" Setpoint is within the administrative 1y controlled (t) band identified as the calibration tolerance. Maintenance and Test Equipment a: curacy is administrative 1y controlled by plant procedures and is included in the plant uncertainty calculations as defined in WCAP-10991. Operability deteminations are based on the use of Maintenance and Test Equipment that confoms with the accuracy used in the plant uncertainty calculation. Maintenance and Test Equipment should be consistent with the requirements of ANSI / ISA 51.1-1979 or the most accurate practicable. The administrative 1y controlled limit for operability of a device is detemined by device drift being less than the value required for the surveillance interval. In the event the device exceeds the administrative 1y controlled limit, operability of the device may be evaluated by other device performance characteristics, e.g., comparison to historical device drift data, calibration characteristics, response characteristics and short tem drift characteristics. A device (RTD, relay, transmitter, process rack module, etc.), whose "as found' value is in excess of the calibration tolerance, but within the operability criteria (administrative 1y controlled limit), is considered operable but must be recalibrated such that the 'as left" value is

i l i l Docket No. 50-423 B15306 ~ '? I l i l r I t Millstone Nuclear Power Station, Unit No. 3 l Proposed Revision to Techr.ical Specifications 24-Month Fuel Cycle Instrumentation surveillance Extensions Retyped Pages i I i I l July 1995

l J3!EX SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS SECTION EAGE i 2.1 SAFETY LIMITS 2.1.1 REACTOR CORE 2-1 2.1.2 REACTOR COOLANT SYSTEM PRESSURE................. 2-1 FIGURE 2.1-1 REACTOR CORE SAFETY LIMIT - FOUR LOOPS IN OPERATION... 2-2 FIGURE 2.1-2 REACTOR CORE SAFETY LIMIT - THREE LOOPS IN OPERATION 2-3 2.2 LIMITING SAFETY SYSTEM SETTINGS 2.2.1 REACTOR TRIP SETPOINTS INSTRUMENTATION SETPOINTS 2-4 TABLE 2.2-1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS 2-6 l RACFC SECTION EaEE 2.1 SAFETY LIMITS 2.1.1 Reactor Core B 2-1 2.1.2 Reactor Coolant System Pressure................ B 2-2 2.2 LIMITING SAFETY SYSTEM SETTINGS 2.2.1 Reactor Trip System Instrumentation Setpoints......... B 2-3 I MILLSTONE - UNIT 3 111 Amendment No. uns

t SAFETY LIMITS AW LIMITING SAFETY SYSTEM SETTINGS L2 LIMITING SAFETY SYSTEM SETTINGS i REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS 2.2.1 The Reactor Trip System Instrumentation and Interlock Setpoints shall be set consistent with the Trip Setpoint values shown in Table 2.2-1. APPLICABILITY: As shown for each channel in Table 3.3-1. l ACTION: a. With a Reactor Trip System Instrumentation Channel Setpoint for pressurizer pressure (low and high) and steam generator water level low-low less conservative than the value shown in the Trip Setpoint column but more conservative than the value shown in the Allowable i Value column of Table 2.2-1, adjust the Setpoint consistent with the Trip Setpoint value. b. With the Reactor Trip System Instrumentation Channel Setpoint for pressurizer pressure (low and high) and steam generator water level low-low less conservative than the value shown in the Allowable Values column of Table 2.2-1, either: 1. Adjust the Setpoint consistent with the Trip Setpoint value of Table 2.2-1 and determine within 12 hours that Equation 2.2-1 was satisfied for the affected channel, or 2. Declare the channel inoperable and apply the applicable ACTION statement requirement of Specification 3.3.1 until the channel is restored to OPERABLE status with its Setpoint adjusted consistent with the Trip Setpoint value. Equation 2.2-1 Z + R + S s TA Where: Z = The value from Column Z of Table 2.2-1 for the affected channel, R = The "as measured" value (in percent span) of rack error for the affected channel, S = Either the "as measured" value (in percent span) of the sensor error, or the value from Column S (Sensor Error) of Table 2.2-1 for the affected channel, and TA = The value from Column TA (Total Allowance) of Table 2.2-1 for the affected channel. c. With a Reactor Trip System Instrumentaion Channel or Interlock Channel (except for pressurizer pressure (low and high) and steam generator water level low-low) Nominal Trip Setpoint inconsistent with the value shown in the Nominal Trip Setpoint column, adjust the setpoint consistent with the Nominal Trip Setpoint value. NILLSTONE - UNIT 3 2-4 Amendment No. 04oe

SAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGS 2.2 LIMITING SAFETY SYSTEM SETTINGS REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS l ACTION cont'd.: d. With a Reactor Trip System Instrumentation Channel or Interlock Channel (Except for pressurizer pressure (low and high) and steam generator water level low-low) found to be inoperable, declare the channel inoperable and apply the applicable ACTION statement requirements of Table 3.3-1 until the channel is restored to OPERABLE status and its setpoint adjusted consistent with the Nominal Trip Setpoint value. l i 1 l i i i NILLSTONE - UNIT 3 2-5 Amendment No. 0405

-TABLE 2.2-1 REACTOR TRIP SYSTEM INSTRUMEHTATION TRIP SETPOINTS l$ NOMINAL FUNCTIONAL UNIT TRIP SETPOINT -4 4 l '1. Manual Reactor Trip M.A. 2. Power Range, Neutron Flux Q a. High Setpoint w

1) Four Loops Operating

< 109% of RTP**

2) Three Loops Operating s 80% of RTP**

b. Low Setpoint s 25% of RTP** 3. Power Range, Neutron Flux, s 5% of RTP** with High Positive Rate a time constant 1 2 seconds 4. Deleted 7 5. Intermediate Range, s 25% of RTP** Neutron Flux 6. Source Range, Neutron Flux 5 10+' cps t

s 7.

Overtemperature AT kg a. Four Loops Operating-f

1) Channels I, II See Note I w?

2) Channels III, IV-See Note I I.

y

- RTP = RATED THERMAL POWER

.=?

TABLE 2.2-1 (Continued) REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS g*FMg NOMINAL l m FUNCTIONAL UNIT TRIP SETPOINT e E b. Three Loops Operating

1) Channels I, II See Note 1

2) Channels III, IV See Note 1 8.

Overpower AT (Four Loops Operating) See Note 2 9. Pressurizer Pressure-Low See at the end of Table

10. Pressurizer Pressure-High See at the end of Table

11. Pressurizer Water Level-High i 89% of instrument span g

12. Reactor Coolant Flow-Low A 90% of loop g

design flow

o.l

13. Steam Generator Water See at the end of Table c+

Level Low-Low z

14. General Warning Alarm N.A.

15. Low Shaft Speed - Reactor 2 92.5% of rated y

Coolant Pumps speed D.

Minimum Measured Flow Per Loop = 1/4 of the RCS Flow Rate Limit as listed in Section 3.2.3.1.a (Four y

Loops Operating); 1/3 of the RCS Flow Rate Limit as listed in Section 3.2.3.2.a.(Three Loops w Operating) u. x.-- -e+ e

TABLE 2.2-1 (Continued)

5 REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS g FM3 NOMINAL l

m FUNCTIONAL UNIT TRIP SETPOINT Eq

16. Turbine Trip a.

Low Fluid Oil Pressure 2 500 psig b. Turbine Stop Valve 2 1% open Closure

17. Safety Injection Input N.A.

from ESF

18. Reactor Trip System Interlocks 7

a. Intermediate Range 2 1 x 10 " amp 4 ' Neutron Flux, P-6 b. Low Power Reactor Trips Block, P-7

1) P-10 input (Note 3)

S 11% of RTP**

2) P-13 input s 10% RTP** Turbine Impulse Pressure Equivalent a

c. Power Range Neutron g Flux, P-8 5

1) Four Loops Operating s 37.5% of RTP**

m I 2)- Three Loops Operating 1 37.5% of RTP** ~

- RTP = RATED THERMAL POWER

TABLE 2.2-1 (Continued) REACTOR TRIP SYSTEM INSTRUMENTATION TRIP SETPOINTS g5F El3 NOMINAL 'l m FUNCTIONAL UNIT TRIP SETPOINT 8 Eq d. Power Range.S utron 1 51% of RTP** Flux, P-E w e. Power dange Neutron 2 9% of RTP** Flux, P-10 (Note 4)

19. Reactor Trip Breakers N.A.

20. Automatic Trip and Interlock N.A.

Logic

21. Three Loop Operation N.A.

i. "4 Bypass Circuitry TOTAL SENSOR ALLOWANCE ERROR j FUNCTIONAL UNIT (TA) Z (S) TRIP SETPOINT ALLOWABLE VALUE 9. Pressurizer Pressure-Low 5.0 1.77 3.3 'A 1900 psia 1 1890 psia-- g

10. Pressurizer Pressure-High 5.0 1.77

-3.3 1 2385 psia s 2395 psia "g-13. Steam Generator Water 18.10 .16.64 1.50 2 18.10 of narrow A 17.11 of narrow g-Level Low-Low range instrument range instrument span span E M. g

- RTP = RATED THERMAL POWER 3

~,..

TABLE 2.2-1 (Continued) $~{ TABLE NOTATIONS w E NOTE 1: OVERTEMPERATURE AT l ( + 4 ) [T I II + I SI (I + # s) 1ATO (K1~E2 - T'] + K3 (P - P') - f (AI)) AT I g E (1 + 7 3) (1 + 7 5) 1+73 2 3 5 6 w Where: AT - Measured AT by Reactor Coolant System Instrumentation; 1+rSy - Lead-lag compensator on measured AT; 1+732 7, 7 - Time constants utilized in lead-lag compensator for AT, r3-8s, 2 - 3.s; 7 3 2 I i - Lag compensator on measured AT; 1+r33 r - Time constants utilized in the lag compensator for AT, r3 - 0 s; 3 o Indicated AT at RATED THERMAL POWER; AT O K - 1.20 (Four Loops Operating); 1.20 (Three Loops Operating); y K - 0.02456; 2 I+7S - The function. generated by the lead-lag compensator for T,yg dynamic 4 g 1+735 compensation; E I g - Time constants utilized in the lead-lag compensator for T,yg, 74 - 20 s, j 7, 7 4 5 5 - 4 s; 7 i z ? T Average temperature, 'F; = 1 ?* - Lag compensator on measured T 1+73 6 r, - Time constant utilized in the measured T,yg lag compensator, 76 - O s; j

h TABLE 2.2-1 (Continued) w k TABLE NOTATIONS (Continued) NOTE 1: (Continued) E T' s 587.1*F (Nominal T,yg at RATED THERMAL POWER); 0.001311/ psi; K 3 P Pressurizer pressure, psia; = P' 2250 psia (Nominal RCS operating pressure); Laplace transform operator, s- ; S and f (AI) is a function of the indicated difference between top and bottom detectors of the g y power-range neutron ion chambers; with gains to be selected based on measured instrument response = during plant startup tests such that: (1) - gb between -26% and + 3%, f,(AI) = 0, where q For qb top and bottom halves of the core respectively,t and qb are percent RATED THERMAL POWER is total THERMAL POWER in in th and qt + 9b percent of RATED THERMAL POWER; (2) For each percent that the magnitude of q, - qs exceeds -26%, the AT Trip Setpoint shall be automatically reduced by 3.55% of its vaTue at RATED THERMAL POWER; and { (3) For each percent that the magnitude of q -q exceeds +3%, the AT Trip Setpoint shall be g, automatically reduced by 1.98% of its vakue ak RATED THERMAL POWER. 5 i'. 5 ?

,N TABLE 2.2-1 (Continued) 1 TABLE NOTATIONS (Continued) g3 NOTE 2: OVERPOWER A*T l-AT (1 + ri ) ( 1 ) o {K, - K, ( 7 S ) ( 1 ) T - K, [T I I I - _T1 - f, (A )) S AT 7 (1 + r,S) (1 + r,5) _(1 + r S) (1 + r,S) (1 + r,5) 7 Eti Where: AT As defined in Note 1, w I + T'8 As defined in Note 1, 1 + r,S As defined in Note 1, ri, r, I + r,s As defined in Note 1, As defined in Note 1, r, N AT. As defined in Rate 1, K, 1.09, 0.02/F for increasing average temperature and 0 for decreasing average. K 3 temperature, 7S l 7 = The function. generated by the rate-lag compensator for T,yg dynamic 1+7S a 7 compensation, 5 Time constants utilized in the rate-lag compensator for T,yg, r - 10 s, l g 7 y 7 f 1 As defined in Note 1, i 1 + r,S %w l ( r. As den nd in M e 1, ?

? j!! (( TABLE 2.2-1 (Continued) w ll TABLE NOTATIONS (Continued) E El NOTE 2: (Continued) l w 0.00180/*F for T > T" and K6 - O for T s T", K 6 As defined in Note 1, T Indicated T,yg at RATED THERMAL POWER (Calibration temperature for AT. T" = instrumentation, s 587.l*F), As defined in Note 1, and S }l f (AI) 0 for all AI. = 2 u NOTE 3: Setpoint is for increasing power. l NOTE'4: Setpoint is for decreasing power. l $a Ea 5 ? w

2.2 LIMITING SAFETY SYSTEN SETTINGS ! BASES 2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS FIVE COLUMN FORMAT l The Reactor Trip Setpoint Limits specified in Table 2.2-1 are the nominal values at which the' Reactor trips are set for each functional unit. The Trip Setpoints have been selected to ensure that the core and Reactor Coolant System are prevented from exceeding their safety limits during normal operation and design basis anticipated operaticnal occurrences and to _ assist the Engi-neered Safety Features Actuation System in mitigating the consequences of accidents. The Setpoint for a Reactor Trip System or interlock function is considered to be adjusted consistent with the nominal value when the "as measured" Setpoint is within the band allowed for calibration accuracy and instrument drift. To accommodate the instrument drift assumed to occur between operational tests and the accuracy to which Setpoints can be measured and calibrated, Allowable Values for the Reactor Trip Setpoints have been specified in Table 2.2-1. Operation with Setpoints less conservative than the Trip Set-point but within the Allowable Value is acceptable sinco an allowance has been made in the safety analysis to accommodate this error. An optional provision has been included for determining the OPERABILITY of a channel when its Trip Setpoint is found to exceed the Allowable Value. The methodology of this option utilizes the "as measured" deviation from the specified calibration point for rack and sensor components in conjunction with a statistical combin-ation of the other uncertainties of the instrumentation to measure the process variable and the uncertainties in calibrating the instrumentation. In Equa-tion 2.2-1, Z + R + S 1 TA, the interactive effects of the errors in the rack and the sensor, and the "as measured" values of the errors are considered. I, as specified in Table 2.2-1, in percent span, is the statistical summation of errors assumed in the analysis excluding those associated with the sensor and rack drift and the accuracy of their measurement. TA or Total Allowance is the difference, in percent span, between the Trip Setpoint and the value used in the analysis for Reactor trip. R or Rack Error is the "as measured" devia-tion, in percent span, for the affected channel from the specified Trip Set-point. S or Sensor Error is either the "as measured" deviation of the sensor from its calibration point or the value specified in Table 2.2-1, in percent span, from the analysis assumptions. Use of Equation 2.2-1 allows for a sensor drift factor, an increased rack drift factor, and provides a threshold value for REPORTABLE EVENTS. The methodology to derive the Trip Setpoints is based upon combining all of the uncertainties in the channels. Inherent to the determination of the Trip Setpoints are the magnitudes of these channel uncertainties. Sensors and other instrumentation utilized in these channels are expected to be capable of operating within the allowances of these uncertainty magnitudes. Rack drift in excess of. the Allowable Value exhibits the behavior that the rack has not met its allowance. Being that there is a small statistical chance that this will happen, an infrequent excessive drift is expected. Rack or sensor drift, in excess of the allowance that is more than occasional, may be indicative of more serious problems and should warrant further investigation. NILLSTONE - UNIT 3 B 2-3 Amendment No. 0407

'l LIMITING SAFETY SYSTEN SETTINGS 'l RASES I e REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS (Continued) i The various Reactor trip circuits automatically open the Reactor trip breakers whenever a condition monitored by the Reactor Trip System reaches a { preset or calculated level. In addition to redundant channels and trains, the j design approach provides a Reactor Trip System which monitors numerous system i variables, therefore providing Trip System functional diversity. The functional -capability at the specified trip setting is required for those anticipatory or i diverse Reactor trips for which no direct credit was assumed in the safety j analysis to enhance the overal1 ~ reliability of the Reactor Trip System. The Reactor Trip System initiates a Turbine trip signal whenever Reactor trip is j initiated. This prevents the reactivity insertion that would otherwise result l from excessive Reactor' Coolant System cooldown and thus avoids unnecessary 1 actuation of the Engineered Safety Features Actuation System. I ONE COLUMN FORMAT j The Reactor Trip Setpoints Limits specified in Table 2.2-1 are the nominal I values at which the reactor tri)s are set for each functional unit. The Nominal- -l Trip Setpoints are considered tie Limiting Safety System Settings as identified l in 10CFR50.36 and have been selected to ensure that the core and Reactor Coolant l System are prevented from exceeding their safety limits during normal operation i and design basis anticipated operational occurrences and to assist the i Engineered Safety Features Actuation System in mitigating the consequences of ) accidents. The Setpoint for a Reactor Trip System or interlock function is j considered to be consistent with the nominal value when the measured "as left" Setpoint is within the administrative 1y controlled (t) band identified as the i calibration tolerance. l Maintenance and Test Equipment accuracy is administrative 1y. controlled by i plant procedures and is included in the plant uncertainty calculations as defined in WCAP-10991. Operability determinations are based on the use of i Maintenance and Test Equipment that conforms with the accuracy used in the plant _ uncertainty calculation. Maintenance and Test Equipment should be consistent with the requirements of ANSI /ISA 51.1-1979 or the most accurate practicable. The administrative 1y controlled limit for operability of a device is j determined by device drift being less than the value required for the surveillance interval. In the event the device exceeds the administrative 1y i controlled limit, operability of the device may be evaluated by other device performance characteristics, e.g., comparison to historical device drift data, calibration characteristics, response characteristics and short-term drift characteristics. A device (RTD, relay, transmitter, process rack module, etc.), whose "as-found" value is in excess of the calibration tolerance, but within the operability criteria (administrative 1y controlled limit), is considered operable but must be recalibrated such that the "as-left" value is within the two-sided (1) calibration tolerance. Plant procedures set administrative limits '("as-left" and "as-found" criteria) to control the determination of operability by setting minimum standards based on the methodology in WCAP 10991 and the uncertainty values included in the determination of the Nominal Trip Setpoint, MILLSTONE - UNIT 3 8 2-4 Amendment No. I WQ1 .. ~ ~ - -,

NEIIllM I BASES l REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS (Continued) and allow the use of other device characteristics to evaluate operability. REPORTABLE EVENTS are identified when the minimum number of channels required to be operable are not met. The methodology, as defined in WCAP-10991 to derive the Nominal Trip Setpoints, is based upon combining all of the uncertainties in the channels. Inherent in the determination of the Nominal Trip Setpoints are the magnitudes of these channel uncertainties. Sensors and other instrumentation utilized in these channels should be capable of operating within the allowances of these uncertainty magnitudes. Occasional drift in excess of the allowance may be determined to be acceptable based on the other device performance characteristics. r Device drift in excess of the allowance that is more than occasional, may be indicative of more serious problems and would warrant further investigation. The various reactor trip circuits automatically open the reactor trip breakers whenever a condition monitored by the Reactor Trip System reaches a preset or calculated level. In addition to redundant channels and trains, the design approach provides a Reactor Trip System functional diversity. The functional capability at the specified trip setting is required for those anticipatory or diverse reactor trips for which no direct credit was assumed in the safety analysis to enhance the overall reliability of the Reactor Trip System. The Reactor Trip System initiates a turbine trip signal whenever reactor trip is initiated. This prevents the reactivity insertion that would otherwise result from excessive Reactar Coolant System cooldown and thus avoids unnecessary actuation of the Engineerad Safety Features Actuation System. Manual Reactor Trio The Reactor Trip System includes manual Reactor trip capability, i Power Ranoe. Neutron Flux In each of the Power Range Neutron Flux channels there are two independent i bistables, each with its own trip setting used for a High and Low Range trip i setting. The Low Setpoint trip provides protection during subcritical and low j power operations to mitigate the consequences of a power excursion beginning from low power, and the High Setpoint trip provides protection during power operations to mitigate the consequences of a reactivity excursion from all power levels. The High Setpoint trip is reduced during three loop operation to a value consistent with the safety analysis. The Low Setpoint trip may be manually blocked above P-10 (a power level of approximately 10% of RATED THERMAL POWER) and is automatically reinstated below the P-10 Setpoint. NILLSTONE - UNIT 3 8 2-4a Amendment No. 0407

i LIMITING SAFETY SYSTEN SETTINGS BASES REACTORTRIPSYSTEMINSTRUMENTATIONSETPOINTS(Continued) Power Ranoe. Neutron Flux. Hiah Positive Rate The Power Range Positive Rate trip provides protection against rapid flux increases which are characteristic of a rupture of a control rod drive housing. Specifically, this tri) complements the Power Range Neutron Flux High and Low trips to ensure that tie criteria are met for all rod ejection accidents. I i i i I MILLSTONE - UNIT 3 8 2-4b Amendment No. JJJ. WW7 1- -

POWER DISTRIBUTION LINITS LINITING COMITION FOR OPERATION ACTION (Continued) b. Within 24 hours of initially.being outside the above limits, verify through incore flux mapping and RCS total flow rate that FL and RCS total flow rate are restored to within the above limits, or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next. 2 hours. c. Identify and correct the cause of the out-of-limit condition prior to increasing THERMAL POWER above the reduced THERMAL POWER limit requiredbyACTIONa.2.andforb.,above;subsequentPOWER OPERATION may proceed provided that Fm and indicated RCS total flow rate are demonstrated, through incore flux mapping and RCS total flow rate comparison, to be within the region of acceptable operation prior to exceeding the following THERMAL POWER levels: 1. A nominal 50% of RATED THERMAL POWER, 2. A nominal 75% of RATED THERMAL POWER, and 3. Within 24 hours of attaining greater than or equal to 95% of RATED THERMAL POWER. SURVEILLANCE REQUIRENENTS 4.2.3.1.1 The provisions of Specification 4.0.4 are not applicable. 4.2.3.1.2 RCS total flow rate and FL shall be determined to be within the acceptable range: a. Prior to operation above 75% of RATED THERMAL POWER after each fuel loading, and b. At least once per 31 Effective Full Power Days. 4.2.3.1.3 The indicated RCS total flow rate shall be verified to be within the accegtable range at least once per 12 hours when the most recently obtained value 1 of Fm, obtained per Specification 4.2.3.1.2, is assumed to exist. 4.2.3.1.4 The RCS total flow rate indicators shall be subjected to a CHANNEL CALIBRATION at least once each REFUELING INTERVAL. The measurement l instrumentation shall be calibrated within 7 days prior to the performance of the i calorimetric flow measurement. NILLSTONE - UNIT 3 3/4 2-20 Amendment No. 77, 77, Jpp, m

POWER DISTRIBUTION LINITS SURVEILLANCE REQUIRENENTS (Continued) 4.2.3.1.5 The RCS total flow rate shall be determined by precision heat balance measurement at least once each REFUELING INTERVAL. Within 7 days prior to l performing the precision heat balance, the instrumentation used for determination of_ steam pressure, feedwater pressure, feedwater temperature, and feedwater venturi AP in the calorimetric calculations shall be calibrated. 4.2.3.1.6 If the feedwater venturis are not inspected at least once each REFUELING INTERVAL, an additional 0.1% will be added to the total RCS flow measurement uncertainty. NILLSTONE - UNIT 3 3/4 2-21 Amendment No. 17, JP, ous C

POWER DISTRIBUTION LIMITS LIMITING COMITION FOR OPERATION 1 ACTION (Continued) b. Within 24 hours of initially being outside the above limits, verify through incore flux mapping and RCS total flow rate that FL and RCS total flow rate are restored to within'.the above limits, or reduce THERMAL POWER to less than 5% of RATED THERMAL POWER within the next 2 hours. l l c. Identify and correct the cause of the out-of-limit condition prior to increasing THERMAL POWER above the reduced THERMAL POWER limit required by ACTION a.2. and may proceed provided that Fu/or b., above; subsequent POWER OPERATION and indicated RCS total flow rate are demonstrated, through incore flux mapping and RCS total flow rate comparison, to be within the region of acceptable operation prior to l-exceeding the following THERMAL POWER levels: 1. A nominal 32% of RATED THERMAL. POWER, and 2. A nominal 50% of RATED THERMAL POWER. SURVEILLANCE REQUIREMENTS I 4.2.3.2.1 The provisions of Specification 4.0.4 are not applicable. 4.2.3.2.2 RCS total flow rate and FL shall be determined to be within the acceptable range at least once per 31 Effective Full Power Days. 4.2.3.2.3 The indicated RCS total flow rate shall be verified to be within the acceptable range at least once per 12 hours when the most recently obtained value of FL, obtained per Specification 4.2.3.2.2, is assumed to exist. 4.2.3.2.4 The RCS total flow rate indicators shall be subjected to a CHANNEL CALIBRATION at least once each REFUELING INTERVAL. The measurement instrumentation l shall be calibrated within 7 days prior to the performance of the calorimetric flow measurement. 4.2.3.2.5 The RCS total flow rate shall be determined by precision heat balance measurement at least once each REFUELING INTERVAL. Within 7 days prior to l performing the precision heat balance, the instrumentation used for determination of steam pressure, feedwater pressure, feedwater temperature, and feedwater venturi AP in the calorimetric calculations shall be calibrated. 4.2.3.2.6 If the feedwater venturis are not inspected at least once each REFUELING INTERVAL, an additional 0.1% will be added to the total RCS flow measurement i uncertainty. gLSTONE-UNIT 3 3/4 2-23 Amendment No. 17, pp 77 Jpp,

3/4.3 INSTRMENTATION 3/4.3.1 REACTOR TRIP SYSTEN INSTRUNENTATION LIMITING COM ITION FOR OPERATION 3.3.1 As a minimum, the Reactor Trip' System instrumentation channels and interlocks of Table 3.3-1 shall be OPERABLE. APPLICABILITY: As shown in Table 3.3-1. l-ACTION: As shown in Table 3.3-1. SURVEILLANCE REQUIREMENTS 4.3.1.1 Each Reactor Trip System instrumentation channel and interlock and 4 the automatic trip logic shall be demonstrated OPERABLE by the performance of the Reactor Trip System Instrumentation Surveillance Requirements specified in Table 4.3-1. 4.3.1.2 The REACTOR TRIP SYSTEM RESPONSE TIME of each Reactor trip protection set shall be demonstrated to be within its limit at least once each REFUELING INTERVAL. Neutron detectors and speed sensors are exempt from res>onse time testing. Each test shall include at least one train such that boti trains are tested at least once per 48 months and one protection set (to include input relays to both trains) such that all protection sets (4) are tested at least once every fourth REFUELING INTERVAL. The RESPONSE TIME of narrow range hot and cold resistance temperature detector (RTD) sets providing input to the overtemperature AT and overpower AT reactor trips shall be demonstrated to be within their limit at least once each REFUELING INTERVAL. Each test shall include at least two RTD sets such that all four RTD sets are tested at least once per 48 months. l l 1 NILLSTONE - UNIT 3 3/4 3-1 Amendment No. #, N, U, JM, 0410 L_____

(I' TABLE 3.3-1 (Continued 1 y ACTION STATENENTS (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 1 status prior to increasing THERMAL POWER above the P-6 i Setpoint, and j b. Above the P-6--(Intermediate Range Neutron Flux Interlock) l Setpoint but below 10% of RATED THERMAL. POWER, restore the i inoperable channel to OPERABLE status prior to increasing THERMAL POWE3 above 10% of RATED THERMAL POWER. j ACTION 4 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, suspend all operations involving positive reactivity changes. ~ i ACTION 5 - (a) With the number of OPERABLE channels one less than' the Minimum Channels OPERABLE-requirement,. restore the j inoperable channel to OPERABLE status within 48 hours or suspend all operations involving positive reactivity ? are closed and secured in position within the next four l. changes and verify valves as per Specification 4.1.1.2.2 y hours. ] (b) With no channels. OPERABLE, suspend all operations -involving positive reactivity changes and verify valves per Specification 4.1.1.2.2 are closed and secured' Verify coml in position within the next 4 hours. the' SHUTDOWN MARGIN requirements of Specification + 3.1.1.1.2 or 3.1.1.2 as. applicable within the next hour. l Continue to verify valves closed and secured every 14 days and verify SHUTDOWN MARGIN every 12 hours. Entry into an i OPERATIONAL MODE pursuant to Specification 3.0.4 is not permitted. 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 hours, and b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be bypassed for up to 4 hours for surveillance testing of other channels per Specification 4.3.1.1. ACTION 7 - (Notused) ACTION 8 - With less than the Minimum Number of Channels OPERABLE, within-I hour determine by observation of the associated permistive annunciator window (s) that the interlock - is in its required state for the existing plant condition, or apply Specification 3.0.3. MILLSTONE - UNIT 3 3/4 3-6 Amendment No. 77 77, one

TABLE 4.3-1 g, ~ REACTOR TRIP SYSTEN INSTRUNENTATION SURVEILLANCE REQUIRENENTS E TRIP ANALOG ACTUATING N0 DES FOR CHANNEL DEVICE WHICH g CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST IS REQUIRED -w w 1. Nanual Reactor Trip N.A. N.A. N.A. R(14) N.A. g2,3*,4*, 2. Power Range, Neutron Flux a. High Setpoint S DC ), Q N.A. N.A. 1, 2 Ng, J, g(,* J, b. Low Setpoint S R S/U(1) N.A. N.A. 1***, 2 3. Power Range, Neutron Flux, N.A. R(4,5) Q N.A. N.A. 1, 2 High Positive Rate D 4. Deleted 5. Intermediate Range S R(4,5) S/U(1) N.A. N.A. .l***, 2 6. Source Range, Neutron Flux S R(4,5) S/(U[1), N.A. N.A. 2**, 3, 4, Q 9) 5 g k 7. Overtemperature AT S R Q N.A. N.A. 1, 2 8. Overpower AT S R Q N.A. N.A. 1, 2 9. Pressurizer Pressure--Low S 18 Nonths Q(18) N.A. N.A. I

10. Pressurizer Pressure--High S

18 Nonths Q(18) N.A. N.A. 1, 2 i

11. Pressurizer Water Level--High S R

Q N.A. N.A. I ??

12. Reactor Coolant Flow--Low S

R Q N.A. N.A. 1 D. ? a w-- -ve ~. e n

$5 TABLE 4.3-1 (Continued) k REACTOR TRIP SYSTEN INSTRUNENTATION SURVEILLANCE REQUIRENENTS TRIP E ANALOG ACTUATING N00ES FOR 4 CHANNEL DEVICE WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION SURVEILLANCE w FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST IS REOUIRED

13. Steam Generator Water Level--

S 18 Nonths Q(18) N.A. N.A. 1, 2 Low-Low

14. Low Shaft Speed - Reactor N.A.

R(13) Q N.A. N.A. 1 Coolant Pumps

15. Turbine Trip a.

Low Fluid Oil Pressure N.A. R N.A. S/U(1,10)****N.A. 1. b. Turbine Stop Valve N.A. R N.A. S/U(1,10)****N.A. 1 Closure D

16. Safety Injection Input from N.A.

N.A. N.A. R N.A. 1, 2 y ESF

17. Reactor Trip System Interlocks a.

Intermediate Range Neutron Flux, P-6 N.A. R(4) R N.A. N.A. 2** b. Low Power Reactor P-7 N.A. R(4) R N.A. N.A. 1 Trips Block, Neutron Power Range c. Flux, P-8 N.A. R(4) R N.A. N.A. I d. Power' Range Neutron P-9 N.A. R(4) R N.A. N.A. 1 Flux, Range ( Power e. Neutron Flux P-10 N.A. R(4) R N.A. N.A. 1, 2

s*

f. TurbineImpulseChamber l Pressure, P-13 N.A. R R N.A. N.A. 1 .F d 4 ? .n =

INSTRUMENTATION 3/4.3.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION LIMITING 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. APPLICABILITY: As shown in Table 3.3-3. ACTION: a. With an ESFAS Instrumentation Channel or Interlock Channel Trip Setpoint trip for pressurizer pressure (Functional Unit 1.d), steam generator water level High-High (Functional Unit 5.b) and steam generator water level (Functional Unit 6.c) less conservative than the value shown in the Trip Setpoint column but more conservative than the value shown in the Allowable Value column of Table 3.3-4, adjust the Setpoint consistent with the Trip Setpoint value. 1 S. With an ESFAS Instrumentation Channel or Interlock Channel Trip Setpoint for pressurizer pressure (Functional Unit 1.d) steam generator water level High-High (Functional Unit 5.b) and steam generator water level (Functional Unit 6.c) less conservative than the value shown in the Allowable Value column of Table 3.3-4, either: 1. Adjust the Setpoint consistent with the Trip Setpoint value of Table 3.3-4, and determine within 12 hours that Equation 2.2-1 was satisfied for the affected channel, or 2. Declare the channel inoperable and apply the applicable ACTION statement requirements of Table 3.3-3 until the channel is restored to OPERABLE status with its Setpoint adjusted consistent with the Trip Setpoint value. Equation 2.2-1 Z + R + S 5 TA Where: Z - The value from Column Z of Table 3.3-4 for the affected channel, R - The "as measured" value (in percent span) of rack error for the affected channel, S - Either the "as measured" value (in percent span) of the sensor l error, or the value from Column S (Sensor Error) of Table 3.3-4 { for the affected channel, and { TA - The value from Column TA (Total Allowance) of Table 3.3-4 for the affected channel. MILLSTONE - UNIT 3 3/4 3-15 Amendment No. FJ. 0412

1 r 1 INSTRUNENTATION 3/4.3.2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRUNENTATION LINITING CONDITION FOR OPERATION (continued) 1 c. With an ESFAS instrumentation channel or interlock channel l inoperable, take the ACTION shown in Table 3.3-3. l d. With an ESFAS Instrumentation Channel or Interlock Channel (except for pressurizer )ressure, Functional Unit 1.d. steam generator water i level - High-Hig1, Functional Unit 5.b, and steam generator water level Functional Unit 6.c) Nominal Trip Setpoint inconsistent wtth the value shown in the Nominal Trip Setpoint column, adjust the j setpoint consistent with the Nominal Trip Setpoint value. e. With an ESFAS Instrumentation Channel or Interlock Channel (except for pressurizer pressure, Functional Unit 1.d, steam generator water level - High-High, Functional Unit 5.b, and steam generator water i level, Functional Unit 6.c) found to be inoperable declare the j channel inoperable and apply applicable ACTION statement ) requirements of Table 3.3-3 until the channel is restored to OPERABLE status and its setpoint adjusted consistent with the Nominal Trip Setpoint value. -l l SURVEILLANCE REQUIRENENTS 4.3.2.1 Each ESFAS instrumentation channel and interlock and the automatic i actuation logic and relays shall be demonstrated OPERABLE by performance of the ESFAS Instrumentation Surveillance Requirements specified in Table 4.3-2. 4.3.2.2 The ENGINEERED SAFETY FEATURES RESPONSE TIME

of each ESFAS protection set shall be demonstrated to be within the limit at least once each REFUELING INTERVAL.

Each test shall include at least one train such that both trains are tested at least once per 48 months and one protection set (to include input relays to both trains) such that all protection sets (4) are tested at least once every fourth REFUELING INTERVAL.

The provisions of Specification 4.0.4 are not applicable for response time testing of steam line isolation for entry into MODE 4 and MODE 3 and turbine driven auxiliary feedwater pump for entry into MODE 3.

NILLSTONE - UNIT 3 3/4 3-16 Amendment No. 99, 79, m 99,199,

A

)

TABLE 3.3 $3 F ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TRIP SETP0INTS y 8 l m NOMINAL FUNCTIONAL UNIT TRIP SETPOINT E A 1. Safety Injection (Reactor Trip, Feedwater Isolation, Control w Building Isolation (Manual Generators, and) Service Water) Initiation Only, Start Diesel a. Manual Initiation N.A. b. Automatic Actuation Logic N.A. c. Containment Pressure--High I $ 3.0 psig d. Pressurizer Pressure--Low I Channels I and II See at the end of f 2 2 Channel III and IV the Table e.. Steam Line Pressure--Low > 658.6 psig* 2. Containment Spray (CDA) a. Manual Initiation N.A. b. Automatic Actuation Logic N.A. and Actuation Relays g c. . Containment Pressure--High-3 5 8.0 psig E 3. Containment Isolation B% a. Phase "A" Isolation f I) Nanual Initiation N.A. ]

a J gm TABLE 3.3-4 (Continued) ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTNUMENTATION TRIP SETPOINTS -4 .g. i NOMINAL -l 'I FUNCTIONAL UNIT TRIP SETPOINT E q 3. Containment Isolation (Continued) t

2) Automatic Actuation Logic.

N.A. and Actuation Relays

3) Safety Injection See Item 1.

above for all. Safety Injection Nominal Trip Setpoints. i b. Phase "B" Isolation 8

1) Manual Initiation N.A.

,s

2) Automatic Actuation N.A.

Y Logic and Actuation y Relays

3) Containment Pressure--

s 8.0 psig l High-3 4. Steam Line. Isolation a. - Manual Initiation.. N.A. b. Automatic Actuation Logic N.A. and Actuation Relays f c. Containment Pressure--High-2 s 3.0 psig-f d. Steam Line Pressure--Low 2 658.6 psig* e. Steam Line Pressure - $ 100 psi /s** ,5 Negative Rate -High 4 . m _ ___ _ m____-m_m_zmo_,.._m.-_mm m..m w+-- . m m .......Am---2-~ m ..-m 2.-.-- -.+-..--._,-+__---,--~._i_.___..d

f i f l TABLE 3.3-4 (Continued) Em ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRMENTATION TRIP SETPOINTS C r-G ~4 NOMINAL l l. FUNCTIONAL UNIT TRIP SETPOINT 5. Turbine Trip and Feedwater E Isolation Q a. Automatic Actuation Logic N.A. Actuation Relays b. Steam Generator Water See at the end Level--High-High (P-14) of the Table c. Safety Injection Actuation See Item 1. above for all Safety In lection Logic Nominal. Trip Setpoints and Al owable Values. g d. T,y, Low Coincident with. Reactor Trip (P-4) 3 1) Four Loops Operating 2 564*F i

2) Three Loops Operating 2 564*F 6.

Auxiliary Feedwater a. Manual Initiation-N.A.- I b. Automatic Actuation Logic N.A. and Actuation Relays ( c. Steam Generator Water g Level--Low-Low 5.

1) Start Motor-Driven Pumps See at the end a

of the Table W b

a,. TABLE 3.3-4 (Continuedl 25 ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRUNENTATION TRIP SETP0INTS -F l y" NOMINAL m FUNCTIONAL UNIT TRIP SETPOINT 6. Auxiliary Feedwater (Continued) 4

2) Start Turbine-See at the end Driven Pumps of the Table w

d. Safety Injection See Item 1. above for all Safety Injection Nominal Trip Setpoints. e. Loss-of-Offsite Power -> 2800V Start Motor-Driven Pumps f. Containment Depressurization See Item 2. above for all CDA Nominal Trip Setpoints. w) Actuation (CDA) Start Motor-Driven Pumps b 7. Control Building Isolation a. Manual Actuation N.A b. Manual Safety Injection N.A Actuation k c. Automatic Actuation N.A. g logic and Actuation g Relays

s"

-< 3.0 psig d. Containment ,5 Pressure--High 1 -<1.5 x 10pci/cc w e. Control Building ? Inlet Ventilation Radiation w E.

TABLE 3.3-4 (Continued) og ENGIEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUNENTATION TRIP SETPOINTS NONINAL l FUNCTIONAL UNIT TRIP SETPOINT E 8. Loss of Power q-a. 4 kV Bus Undervoltage 2 2800 (Loss of Voltage) volts with Ja s 2 second time delay, b. 4 kV Bus Undervoltage 2 3730 volts (Grid Degraded Voltage) with a s 8 second time-delay with ESF actuation or s 300 second time dela us without E F h ketuation. i 9. Engineered Safety Features Actuation System Interlocks a. Pressurizer Pressure, P-11 1 1985 psig j f b. Low-Low T,yg, P-12 2 553*F:

c.. Reactor Trip, P-4 N.A.

10. Emergency Generator Load N.A.

.F Sequencer ._._._._______.__m_

TA8LE 3.3-4 (Continued) ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRUNEllTATION TRIP SETPOIE S ox $F SENSOR C; TOTAL ERROR y FUNCTIONAL UNIT ALLOWANCE fTA) Z (S) TRIP SETPOINT ALLOWABLE VALUE m 9 E 1. Safety Injection A d. Pressurizer Pressure-Low

1) Channels I and II 22.16 20.1 1.5 1 1877.3 psig 1 1868.5 psig

2) Channels III and IV 22.16 15.6 3.3 1 1877.3 psig 1 1863.3 psig-5.

Turbine Trip and Feedwater Isolation b. Steam Generator Water 5.25 3.76 1.50 $ 80.45% of $ 81.47% of Level - High-High (P-14) narrow range narrow range g instrument span instrument span a 6. Auxiliary Feedwater w U c. Steam Generator Water Level - Low-Low

1) Start Motor-Driven 18.10 16.64 1.50 1 18.10% of 1 17.11% of Pumps narrow range.

narrow range instrument span instrument span

2) Start Turbine -

18.10 16.64 1.50 1 18.10% of 1 17.11% of Driven Pumps narrow range narrow range instrument span instrument span $a Ea .I

TABLE 4.3-2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRtMEWTATION g5 SURVEILLANCE REQUIREMENTS o r-G TRIP g ANALOG ACTUATING MODES m CHANNEL DEVICE MASTER SLAVE FOR WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE = g FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST JISI TEST IS REQUIRED ~ -8

1. Safety Injection (Reactor Trip, Feedwater Isolation Control Building Isolation Manual Initiation Only S art Diesel Generators,and)$erviceWater)

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 Logic and Actuation Relays D

c. Containment Pressure-S R

Q N.A. N.A. N.A. N.A. 1, 2, 3 High-1 w 5

d. Pressurizer Pressure-S 18 months Q

N.A. N.A. N.A. N.A. 1, 2, 3 l Low

e. Steam Line S

R Q N.A. N.A. N.A. N.A. 1, 2, 3 g Pressure-Low E

2. Containment Spray 2

i?

a. Manual Initiation N.A.

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

b. Automatic Actuation N.A.

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

c. Containment Pressure-S R

Q N.A. N.A. N.A. N.A. 1, 2, 3, 4 High-3 4 =

TABLE 4.3-2 ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRUMENTATION SURVEILLANCE REQUIREMENTS

FM TRIP E

ANALOG ACTUATING MODES m CHANNEL DEVICE MASTER SLAVE FOR WHICH CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE E FUNCTIONAL UNIT CHECK-CALIBRATION TEST TEST LOGIC TEST IISI TEST.. IS REQUIRED ti

4. Steam Line Isolation (Continued) w

b. Automatic Actuation N.A.

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

c. Containment Pressure-S R

Q N.A. N.A. N.A. N.A. 1, 2, 3, 4 High-2

d. Steam Line S

R Q N.A. N.A. N.A. N.A. 1, 2, 3 wi Pressure-Low

e. Steam Line Pressure-S R

Q N.A. N.A. N.A. N.A. 3 Negative Rate-High

5. Turbine Trip and Feedwater g

Isolation a g

a. Automatic Actuation N.A.

N.A. N.A. N.A. M(1) M(1) Q 1, 2 Logic and Actuation 3" Relays F

b. Steam Generator Water S

18 months Q N.A. M(1) M(1) Q 1, 2, 3 y Level-High-High Q

c. Safety Injection N.A.

N.A. N.A. R N.A. N.A. N.A. 1, 2 Actuation Logic D

d. T,y, Low Coincident N.A.

R Q N.A. N.A. N.A. N.A. 1, 2 y with Reactor Trip (P-4)

..+ TABLE 4.3-2 (Continued) g3 ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION 8p SURVEILLANCE REQUIREMENTS v. g TRIP m ANALOG ACTUATING MODES CHANNEL DEVICE MASTER SLAVE FOR WHICH e g CHANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE q FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST IESI TEST IS REQUIRED

6. 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) Q 1,2,3 and Actuation Relays

c. Steam Generator Water S

18 months Q N.A. N.A. N.A. N.A. 1, 2, 3 l Level-Low-Low ,s [

d. Safety Injection See Item 1. above for all Safety Injection Surveillance Requirements, b

e. Loss-of-Offsite Power See Item 8. below for all Loss of Power Surveillance,

f. Containment Depres-See Item 2. above for all CDA Surveillance Requirements.

g surization Actuation g (CDA) a. 1 7. Control Building Isolation j g:

a. Manual Actuation N.A.

N.A. N.A. R N.A. N.A. N.A. All w

b. Manual Safety N.A.

N.A. N.A. R N.A. N.A. N.A. 1, 2, 3, 4 ? Injection Actuation

c. Automatic Actuation N.A.

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

d. Containment Pressure--

S R Q N.A. N.A. N.A. N.A. 1, 2, 3 High-1

TABLE 4.3-2 (Continued) gx ENGINEERED SAFETY FEATURES ACTUATION SYSTEN INSTRUNENTATION 3 %, SURVEILLANCE REQUIREMENTS uy TRIP m ANALOG ACTUATING N00ES CHANNEL DEVICE MASTER SLAVE FOR WHICH i Cl!ANNEL CHANNEL OPERATIONAL OPERATIONAL ACTUATION RELAY RELAY SURVEILLANCE g FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST IESI TEST IS REQUIRED q

7. Control Building Isolation (Continued)

e. Control Building Inlet S

18 months Q N.A. N.A. N.A. N.A. All l-Ventilation Radiation

8. Loss of Power

a. 4 kV Bus N.A.

R N.A. N(3) N.A. N.A. N.A. 1,2,3,4 Undervoltage (Loss g of Voltage)

b. 4 kV Bus N.A.

R N.A. M(3) N.A. N.A. N.A. 1, 2, 3, 4 Y Undervoltage (Grid Degraded Voltage)

9. Engineered Safety E

Features Actuation l System Interlocks. e =

a. Pressurizer N.A.

R Q N.A. N.A. N'.A. N.A. 1, 2, 3 ? Pressure, P-11

y

b. Low-tow T,yg, P-12 N.A.

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

c. Reactor Trip, P-4 N.A.

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

10. Emergency Generator N.A.

N.A. N.A. N.A. Q(1,2) N.A. N.A. 1,2,3,4 ? Load Sequencer D. 1 F

TABLE 4.3-3 h RADIATION NONITORING INSTRUMENTATION FOR PLANT C; OPERATIONS SURVEILLANCE REQUIREMENTS 3g ANALOG CHANNEL NODES FOR WHICH CHANNEL CHANNEL OPERATIONAL SURVEILLANCE FUNCTIONAL UNIT CHECK CALIBRATION TEST IS REQUIRED -i 5d 1. Containment a. Containment Area Purge and Exhaust Isolation S R Q_ 5, 6 b. RCS Leakage Detection

1) Particulate Radio-S 18 months Q

1,2,3,4 activity {

2) Gaseous Radioactivity S

18 months Q 1, 2, 3, 4 2. Fuel Storage Pool Area Monitors a. Radiation Level S 18 months Q TABLE NOTATIONS With fuel in the fuel storage pool area. .E ?

) i L INSTRINIENTATION REMOTE SHUTD0tNI INSTRUMENTATION LIMITING C0lWITION FOR OPERATION 3.3.3.5 The Remote Shutdown Instrumentation transfer switches, power, controls and monitoring instrumentation channels shown in Table 3.3-9 shall be OPERABLE. APPLICABILITY: MODES 1, 2, and 3. ACTION: a. With the number of OPERABLE remote shutdown monitoring channels less than the Minimum Channels OPERABLE as required by Table 3.3-9, restore the inoperable channel (s) to OPERABLE status within 7 days, or be in HOT SHUTDOWN within the next 12 hours. b. With one or more. Remote Shutdown Instrumentation transfer switches,

power, or control circuits inoperable, restore -the inoperable switch (s)/ circuit (s) to OPERABLE status within 7 days, or be in HOT STANDBY within the next 12 hours.

c. Entry into an OPERATIONAL MODE is permitted while subject to these ACTION requirements. SURVEILLANCE REQUIREMENTS I 4.3.3.5.1 Each remote shutdown monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK ~and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3-6. 4 4.3.3.5.2 Each Remote Shutdown Instrumentation transfer switch, power and control circuit including the actuated components, shall be demonstrated OPERABLE at least once each REFUELING INTERVAL. l. 4 i l l NILLSTONE - UNIT 3 3/4 3-53 Amendment No. J7, 7J, Jpp, 0417

a d TABLE 4.3-8 f. .22 RADI0 ACTIVE LIQUID EFFLUENT NONITORING INSTIMENTATION SURVEILLANCE REQUIRDENTS

h ANALOG-CHANNEL k

CHANNEL SOURCE CHANNEL OPERATIONAL-INSTRUMENT CHECK CHECK CALIBRATION TEST

1..

Radioactivity Monitors Providing .j H Alarm and Automatic Termination 1 of Releases a. Waste Neutralization Sump Monitor-D P .18 months (2) Q(1) Condensate Polishing Facility b. Turoine Building Floor Drains D M 18 months (2) Q(1) c. Liquid Waste Monitor D P 18 months (2) Q(1) y d. Regenerate Evaporator Monitor-D M 18 months (2) Q(1) Condensate Polishing Facility (5) e. Steam Generator Blowdown Monitor D M 18 months (2) Q(1). 2. Flow Rate Measurement Devices a. Waste Neutralization Sump Effluents D(3) NA 18 months Q i b. Turbine Building Floor Drains D(4) NA NA NA l c. Liquid Waste Effluent Line D(3) NA 18 months Q d. Regenerate Evanorator Effluent Line (5) D(3)~ NA' 18 months Q e. Steam Generator Blowdown Effluent Line D(3) NA 18 months Q g f. Dilution Water Flow D(4) NA NA-NA E = Y

TABLE 4.3-9 Ex 8 f RADIOACTIVE GASEOUS EFFLUENT NOMITORING INSTRtMENTATION SURVEILLANCE REQUIREMENTS 's I m ANALOG CHANNEL MODES FOR WHICH g CHANNEL SOURCE CHANNEL OPERATIONAL SURVEILLANCE ~ [ INSTRUMENT CHECK CHECK CALIBRATION TEST IS REQUIRED 1. Millstone Unit 3 Ver.c.iction Vent Stack (Turbine Building) .(

a. Noble Gas Activity Manitor D

M 18 months (1) Q(2)

b. Iodine Sampler W

N.A. N.A. N.A.

c. Particulate Sampler W

N.A. N.A. N.A. ,s [

d. Stack Flow Rate Monitor D

N.A. 18 months Q b

e. Sampler Flow Rate Monitor D

N.A. 18 months Q 2. Millstone Unit 1 Main Stack

a. Noble Gas Activity Monitor D

M 18 months (3) Q(2)

b. Iodine Sampler W

N.A. N.A. N.A.

c. Particulate Sampler W

N.A. N.A. N.A.

d. Stack Flow Rate Monitor D

N.A. 18 months Q {

e. Sampler Flow Rate Monitor D

N.A. 18 months Q R Ra F i s y

TABLE 4.3-9 (Continued) RADI0 ACTIVE GASEOUS EFFLUENT MONITORING INSTR'JMENTATION SURVEILLANCE REQUIREMENTS 5 z 7 ANALOG CHANNEL MODES FOR WHICH CHANNEL SOURCE CHANNEL OPERATIONAL SURVEILLANCE -8 INSTRUMENT CHECK CHECK CALIBRATION TEST IS REOUIRED w 3. Engineered Safeguards Building Monitor

a. Noble Gas Activity Monitor D

M 18 months (1) Q(2)

b. Iodine Sampler W

N.A. N.A. N.A.

c. Particulate Sampler W

N.A. N.A. N.A. R

d. Discharge Flow Rate Monitor D

N.A. 18 months Q

e. Sampler Flow Rate Monitor D

N.A. 18 months Q 4. Warehouse No. 5 Vent

a. Noble Gas Monitor D

N.A. 18 months (3) N.A.

b. Iodine Sampler D

N.A. 18 months (3) N.A.

c. Particulate Sampler D

N.A. 18 months (3) N.A. in F .m... m m m. .w

3/4.3 INSTRINGENTATION BASES -3/4.3.1 and 3/4.3.2 REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION FIVE COLUMN FORMAT l The OPERABILITY of the Reactor Trip System and the Engineered Safety Features Actuation System instrumentation and interlocks ensures 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.is maintained, (3) sufficient redundancy is main-tained to permit a channel to be out-of-service for testing or maintenance, and (4) sufficient systas functional capatTity is available from diverse parameters. The OPERABILITY of these systems is retuired to provide the overall reliability, redundancy, and diversity assumed 1.vaila)1e in the facility design for the protection and mitigation of accilent and transient conditions. The integrated operation of each of these systents is consistent with the assumptions used in the safety analyses. The Surveillance Requirements spect-fied for these systems ensure that the overall systca functional capability is maintained comparable to the original design standards. The periodic surveil- -I lance tests performed at the minimum frequencies are sufficient to demonstrate this capability. The Engineered Safety Features Actuation System Instrumentation Trip Setpoints specified in Table 3.3-4 are the nominal values at which the bistables are set for each functional unit. A Setpoint is considered to be adjusted consistent with the nominal value when the "as measured" Setpoint is within the band allowed for calibration accuracy. To accommodate the instrument drift assumed to occur between operational tests and the accuracy to which Setpoints can be measured and calibrated, Allowable Values for the Setpoints have been specifW in Table 3.3-4. Opera-tion with Setpoints less conservative than the Trip setpoint but within the Allowable Value is acceptable since an allowance has been made in the safety j analysis to accommodate this error. An optional provision has been. included for determining the OPERABILITY of a channel when its Trip Setpoint is found to exceed the Allowable Value. The methodology of this option utilizes the "as measured" deviation from the specified calibration point for rack and sensor components in conjunction with a statistical combination of the other uncertainties of the instrumentation to measure the process variable and the uncertainties in calibrating the instrumentation. In Equation 3.3-1, Z + R S 1 TA, the interactive effects of the errors in the rack and the sensor, and the "as measured" values of the errors are considered. Z, as specified in Table 3.3-4, in percent span, is the statistical summation of errors assumed in the analysis excluding those associated with the sensor and rack drift and the accuracy of their measurement. TA or Total Allowance is the difference, in percent span, R or Rack Error is the "as measured" j deviation, in the percent span, for the affected channel from the specified Trip Setpoint. S or Sensor Error is either the "as measured" deviation of NILLSTONE - UNIT 3 8 3/4 3-1 Amendment No. 0421

-?; r INSTRUMENTATION f BASES l REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAFETY FEATURES AQUATION j SYSTEM INSTRUMENTATION (Continued) i ' for a sensor drift factor, an increased rack drift factor, and providas~a j threshold value for REPORTABLE EVENTS. The methodology to derive the Trip setpoints is based upon combining all of the uncertainties in the channels. Inherent to the determination of the Trip Setpoints are the magnitudes of these channel uncertainties. Sensor and rack instrumentation utilized in these channels are expected to be capable of t operating within the allowances of these uncertainty magnitudes. Rack drift in excess of the Allowable Value exhibits-the behavior that the rack has not met its allowance. Being that there is a small statistical chance that this will happen, an infrequent excessive drift is expected. Rack or sensor drift; in excess of the allowance that is more than occasional, may be indicative of more serious problems and should warrant further investigation. l ONE COLUMN FORMAT The OPERABILITY of the Reactor Trip System and the Engineered Safety 1 Features Actuation System instrumentation and interlocks ensures that: i (1) the associated action and/or Reactor trip will be. initiated when the i parameter monitors by each channel or combination thereof reaches its setpoint, (2) the specified coincidence logic is maintained, (3) sufficient I redundancy is maintained to permit a channel to be out of service for testing or maintenance, and (4) sufficient system functional capability is available i from diverse parameters. j The OPERABILITY of these systems is required to rovide the overall reliability, redundancy, and diversity assumed availab e in the facility design for the protection and mitigation of accident and transient conditions. The-integrated operation of each of these systems is consistent with the assumptions used in the safety analyses. The Surveillance Requirements specified for these systems ensure that the overall system functional ] capability is maintained comparable to the original design standards. The 1 periodic surveillance tests performed at the minimum frequencies are sufficient to demonstrate this capability. The Engineered Safety Features Actuation System Nominal Trip Setpoints j specified in Table 3.3-4 are the nominal values at which the bistables are set i for each functional unit. The Nominal Trip Setpoints are considered the i Limiting Safety System Settings as identified in 10CFR50.36 and have been selected to mitigate the consequences of accidents. A Setpoint.is considered to be consistent with the nominal value when the measured "as left" Setpoint is within the administrative 1y controlled (i) band identified as the - calibration tolerance. Maintenance and Test Equipment accuracy is administrative 1y contro11edo by plant procedures and is included in the plant uncertainty calculations as defined in WCAP-10991. Operability determinations /c based on the use of Maintenance and Test Equipment that conforms with the accuracy used in the plant uncertainty calculation. Maintenance and Test Equipment should be MILLSTONE - UNIT 3 B 3/4 3-2 Amendment No. J. 0421

^ i INSTRUMENTATION BASES REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION (Continued) i consistent with the requirements of ANSI /ISA 51.1-1979 or the most accurate practicable. The administrative 1y controlled limit for operability of a device is ) determined by device drift being less than the value required for the surveillance interval. In the event the device exceeds the administrative 1y s controlled limit, operability of the device may be evaluated by other device performance characteristics, e.g., comparison to historical device drift data, calibration characteristics, response characteristics, and short-term drift characteristics. A device (RTD, relay, transmitter, process rack module, j etc. ), whose "as found" value is in excess of the calibration tolerance, but within the operability criteria (administrative 1y controlled limit), is considered operable but must be recalibrated such that the "as left" value is within the two sided (1) calibration tolerance. Plant procedures set i administrative limits ("as left" and "as found" criteria) to control the determination of operability by setting minimum standards based on the methodology in WCAP-10991 and the uncertainty values included in the determination of the Nominal Trip Setpoint, and allow the use of other device characteristics to evaluate operability. REPORTABLE EVENTS are identified l when the minimum number of channels required to be operable are not met. l The methodology, as defined in WCAP-10991 to derive the Nominal Trip Setpoints, is based upon combining all of the uncertainties in the ch&nnels. s Inherent in the determination of the Nominal Trip Setpoints are the magnii.ndes of these channel uncertainties. Sensors and other instrumentation utilized in these channels should be capable of operating within the allowances of these i uncertainty magnitudes. Occasional drift in excess of the allowances may be i determined to be acceptable based on the other device performance i characteristics. Device drift in excess of the allowance that is more than occasional, may be indicative of more serious problems and would warrant further investigation. The measurement of response time at the specified frequencies provides assurance that the Reactor trip and the Engineered Safety Features actuation associated with each channel is completed within the time limit assumed in the safety analyses. The RTS and ESF response times are included in the Operating Procedure OP-3273 " Technical Requirements--Supplementary Technical Specifications." Any changes to the RTS and ESF response times shall be in accordance with Section 50.59 of 10CFR50 and approved by the Plant Operations Review Committee. 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. Sensor response time verification may be demonstrated b/ either: (1) in place, onsite, or offsite test measurements, or (2) util', zing replacement sensors with certified response time. Detector response times may be measured by the in situ on line noise analysis-response time degradation method described in the Westinghouse Topical Report, "The Use of /rocess Noise Measurements To Determine Response Characteristics of Protection Sensors in U.S. Plants," August 1983. MILLSTONE - UNIT 3 B 3/4 3-2a Amendment No. 0421

l i INSTRUNENTATION BASES i REACTOR TRIP SYSTEM INSTRUMENTATION and ENGINEERED SAFETY FEATURFS ACTUATION SYSTEM INSTRUMENTATION (Continued) 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 combina-tions indicative of various accidents, events, and transients. Once the required logic combination is completed, the system sends actuation signals to those Engineered Safety Features components whose aggregate function best serves the requirements of the condition. As an example, the 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) feed-water isolation, (4) startup of the emergency diesel generators, (S) quench spray pumps start and automatic valves position, (6) containment isolation, (7) steam line isolation, (8) Turbine trip, (9) auxiliary feedwater pumps start, (10) service water pumps start and automatic valves position, and (11) Control Room isolates. REACTOR TRIP BREAKERS This trip function applies to the reactor trip breakers (RTBs) exclusive of l individual trip mechanisms. The LC0 requires two operable trains of trip breakers. A trip breaker train consists of all trip breakers associated with a single RTS logic train that are racked in, closed, and capable of supplying power to the control rod drive (CRD) system. Thus, the train may consist of the main breaker, bypass breaker, or main breaker and bypass breaker, depending upon the system configuration. Two OPERABLE trains ensure no single random failure can disable the RTS trip capability. These trip functions must be OPERABLE in MODE 1 or.2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip functions must be OPERABLE when the RTBs or associated bypass breakers are closed, and the CRD system is capable of rod withdrawal. NILLSTONE - UNIT 3 B 3/4 3-2b Amendment No. 7, 77 om

( Docket No. 50-423 B15306 i P i t i' Millstone Nuclear Power Station, Unit No. 3 Proposed Revision.to Technical Specifications l 24-Month Fuel Cycle Instrumentation Surveillance Extensions [ Description of the Proposed Technical Specification changes I i i i l i i i t July 1995 l i 4 l i i i I

.j l i U.S. Nuclear. Regulatory Commission. B15306/ Attachment 4/Page l' i July 26, 1995 u Millstone Nuclear Power Station, Unit No. 3 Description of the Proposed Technical Specification Changes Introduction [ On June 7, 1995, - Millstone Unit No. 3 began operating on a nominal 24-month fuel cycle. To be consistent with the longer j fuel cycle, Northeast Nuclear Energy Company (NNECO) is proposing to modify the frequency of number of Surveillance Requirements existing in ' the Millstone Unit No. 3 Technical Specifications. The proposed changes are described below: i 1. Section 2.2, Reactor Trio System Instrumentation Satooints l The current ' Table 2.2-1 lists the reactor trip system instrumentation and interlock. setpoint in a five column i format. NNECO proposes to replace the existing five column i format with one column format containing nominal trip setpoints for all functions except pressurizer pressure j (functional units 9 and 10) and steam generator water level l low-low-(functional unit 13). During the November 2,'1994, meeting with the NRC, NNECO indicated that the transmitters for the pressurizer pressure and steam generator water level will be replaced due to undesirable drift. However, due to the production and delivery problems of the-new transmitters, the transmitters for these functions could not be replaced during the.fifth refueling outage. To accommodate the 24-month fuel' cycle, the following actions are being taken. No drift. analysis or' evaluation will be performed to extend the frequency of the calibration for-- these existing transmitters. Therefore, the current format (five column approach) for these functional units will be preserved for one cycle. It is expected that NNECO. will-replace these transmitters during the sixth refueling outage. Appropriate changes to Technical Specifications will be submitted to the NRC in the future. The ACTION statements have been revised to reflect one column approach' for all the functional

units, except for pressurizer pressure and steam generator water level.

The existing Notes 2 and 4 are no longer applicable since we are using a l one column approach; Notes 2 and 4 are deleted and the l remaining Note is renumbered. In addition, the proposed change decreases the reactor trip setpoint for the reactor l coolant pump (RCP) low shaft speed (underspeed trip setpoint) from 95.8 percent to 92.5 percent of rated speed. Bases Section 2.2.1 has been revised to include the information regarding'the operability determination for the r reactor trip system instrumentation.

i I U.S. Nuclear Regulatory Commission B15306/ Attachment 4/Page 2 July 26, 1995 2. Section 4.3.1.1. Table 4.3-1. Reactor Trio System Instrumentation Surveillance Recuirements Table 4.3-1, Reactor Trip System Instrumentation Surveillance Requirements, lists the following functional units and their 18-month surveillance requirements: Surveillance n 18-M nth No. Functional Unit Frequency 1. Manual Reactor Trip Trip Actuating Device Operational Test (TADOT) 2. Power Range, Neutron Flux a. High Setpoint Channel Calibration b. Low setpoint Channel Calibration 3. Power Range Neutron Flux Channel Calibration High Positive Rate 4. Deleted Not applicable 5. Intermediate Range Channel Calibration 6. Source Range, Neutron Flux Channel Calibration 7. Overtemperature AT Channel Calibration 8. Overpower AT Channel Calibration 9. Pressurizer Pressure - Low Channel Calibration 10. Pressurizer Pressure - 111gh Channel Calibration 11. Pressurizer Water Level - High Channel Calibration 12. Reactor Coolant Flow - Low Channel Calibration 13. Steam Generator Water Level - Low-Low Channel Calibration 14. Low Shaft Speed - Reactor Coolant Pumps Channel Calibration 15. Turbine Trip a. Low Fluid 011 Pressure Channel Calibration b. Turbine Stop Valve closure Channel Calibration 16. Safety Injection Input from ESF TADOT 17. Reactor Trip System Interlock Channel Calibration and Analog Channel Operational Test 20. Three-Loop Operation Bypass Circuitry TADOT 21. Reactor Trip Bypace Breaker TADOT

U.S. Nuclear Regulatory Commission B15306/ Attachment 4/Page 3 July 26, 1995 It is noted that Amendment No. 116 revised the technical specifications to delete the power range Neutron Flux, High Negative Rate from Tables 2.2-1, 3.3-1, and 4.3-1 and to delete description associated Bases Section 2.0. The above surveillance requirements are noted by a notation 'R' which indicates that the surveillance is required to be performed once per 18 months. NNECO is proposing to extend this interval to at least once each refueling (i.e., nominal 24 months) for all the functions noted above except for pressurizer pressure - low, pressurizer pressure - high, and steam generator water level - low-low. The definition of 'R' is included in Table 1.1 and is being revised under a separate technical specification (Refer to NNECO submittal dated May 1, 1995). Therefore, no changes are proposed to the above functions. For the functions pressurizer pressure - low, pressurizer pressure - high, and steam generator water level - low-low, the surveillance interval will remain at the current interval (i.e., 18 months). Therefore, the notation for the surveillance frequency for these functions is being revised from 'R' to "18 months" and NNECO will continue to perform these surveillances at the 18-month frequency. NNECO expects to install new transmitters for these three functions during the sixth refueling outage to accommodate the undesirable drift-related errors for the 24-month fuel cycle operation. NNECO will submit a license amendment request to the NRC to extend the frequency for these surveillances from once per 18 months to at least once each refueling interval (i.e., nominal 24 months) in the future. 3. Section 4.3.1.2 and Section 4.3.2.2. Response Time Testina of the RTS and ESFAS Instrumentatio_D Surveillance Requirements 4.3.1.2 and

4. 3. 2. 2 require that the reactor trip system (RTS) response time of each RTS function and Engineered Safety Features Actuation System (ESFAS) response time of each ESFAS function shall be demonstrated to be within the limit at least once per 18 months.

NNECO proposes to extend the frequency of Surveillance Requirements 4.3.1.2 and 4.3.2.2 from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). The RTS and ESFAS instrumentation are required to be response time tested once every 18 months on a N-1 frequency where N is the total number of channels or trains in a system. This results in train-related equipment, such as pumps,

valves, and the solid-state protection

system, being tested once every 36 months.

Channel-related instrument loops are tested on a 1

'I l l- 'U.S. Nuclear Regulatory Commission l B15306/ Attachment 4/Page 4 l July 26, 1995 i once every 54-month or 72-month frequency, depending on the total number of instrument channels for..a given parameter. 1 The. proposed change will extend ~the N-1 testing frequency currently in technical specifications from once-per 18 months to once each refueling interval (i.e., nominal 24 months). The result will be that for train-related components and systems, the maximum test interval for an individual or system will be extended from once per l 36 months to once every 48 months. The result for 3land 4 { channel instrument systems will-be that instrument loops I currently tested every 72 months will have their test interval extended to once every 96 months. In addition, ) NNECO proposes to add specific statements - regarding the response time testing of the resistance temperature detectors that provide input to the overtemperature AT and overpower AT reactor trips. i 4. Section 3.3.2. ESFAS Instrumentation Table 3.3-4 lists the ESFAS instrumentation trip. setpoints in a five column format. NNECO proposes to replace' the existing five column format with one column format containing nominal trip setpoints for all functions except' pressurize pressure -Low (Functional Unit 1.d), steam generator water level - high-high (Functional Unit 5.b) and steam generator water level - low-low (Functional Unit 6.c). During the November 2, 1994, meeting with the NRC, NNECO indicated that the transmitters for the pressurizer pressure and steam generator water level will be replaced due to undesirable drift. However, due to production and' delivery problems of the new transmitters, the transmitters for these functions could not be replaced during the fifth refueling outage. To accommodate the 24 month fuel

cycle, the following actions are being taken..

No drift -or evaluation will be performed to extend the frequency of the calibration of these transmitters. Therefore, the ' current. fornat (i.e.,, five column) for these functional units will be .i preserved for Cycle 6. It is expected that NNECO will replace these transmitters during the sixth refueling outage. Appropriate changes to technical specifications will be submitted to the NRC in the-future. Action i statements have been revised to reflect one column approach for all functions except for pressurizer pressure and steam generator water level. Bases Section 3/4.3.2 has been revised to include the i -information regarding the operability determination for the i ESFAS instrumentation.

U.S. Nuclear Regulatory Commission B15306/ Attachment 4/Page 5 July 26, 1995 1 5. Section 4.3.2.1. Table 4.3-2, ESFAS Surveillance Recuirements Table 4.3-2, ESFAS instrumentation surveillance requirements lists the following functional units and their 18-month surveillance requirements: 1 8"#**i11*"C" No. Functional Unit 18-Month Frequency 1.a safety Injection - Manual Initiation TADOT 1.c Safety Injection - Containment Channel Calibration Pressure - High-1 3.d Safety Injection - Pressurizer Pressure -Low Channel Calibration 1.e safety Injection - Steam Line Pressure - Low Channel Calibration 2.a containment Spray - Manual Initiation TADOT 2.c containment spray - Cor.tainment Pressure - Channel Calibration High-3 3.a. Containment Isolation - Phase A Isolation, TADOT 1 Manual Isolation 3.b. Containment Isolation - Phase B Isolation, TADOT 1 Manual Initiation 3.b. Containment Isolation - Phase B Isolation, Channel Calibration 3 Containment Pressure - High-3 4.a steam Line Isolation - Manual Initiation TADOT 4.c Steam Line Isolation - Containment Pressure Channel Calibration High-2 4.d Steam Line Isolation - Steam Line Channel Calibration Pressure - Low 4.s Steam Line Pressure - Negative Rate - High Channel Calibration 5.b Turbine Trip and Feedwater Isolation - Steam Channel Calibration Generator Water Level - High-High 5.c Turbine Trip and Feedwater Isolation - TADOT Safety Injection Actuation Logic 5.d Turbine Trip and Feedwater Isolation - Tavg Channel Calibration Low Coincident with Reactor Trip P-4 6.a Auxiliary Feedwater - Manual Initiation TADOT 6.c Auxiliary Feedwater - Steam Generator Water Channel Calibration j Level - Low-Low

l U.S. Nuclear Regulatory Commission B15306/ Attachment 4/Page 6 July 26, 1995 I 8"#'*ill""*" No. Functional Unit 18-Month Frequency 7.a control Building Isolation Manual Actuation TADoT 7.b Manual Safety Injection Actuation 7.d control Building Isolation Containment Channel Calibration Pressure - High-1 7.e control Building Inlet Ventilation Radiation channel Calibration 8.a Loss of Power - Channel Calibration 8.b 4 kV Undervoltage (Loss of Voltage) 4 kV Undervoltage (Grid Degraded Voltage) 9.a ESFAS Interlocks - Pressurizer Pressure P-11 Channel Calibration 9.b ESFAS Interlocks - Low-Low T..,, P-12 Channel Calibration 9.c ESFAS Interlocks - Reactor Trip, P-4 TADoT The above surveillance requirements are noted by a notation 'R' which indicates that the surveillance is required to be performed once per 18 months. NNECO is proposing to extend this interval to at least once each refueling (i.e., nominal 24 months) for all the functions except for safety injection - pressurizer pressure low (Functional Unit 1.d), auxiliary feedwater - steam generator water level low-low (Functional Unit 6.c) and steam generator water level high-high (Functional Unit 5.b). The definition of 'R' is included in Table 1.1 and is being revised under a separate technical specification (refer to NNECO submittal dated May 1, 1995). Therefore, no changes are proposed to the above functions (i.e., no change to 'R' term in Table 4.3-2). For functions i Pressurizer Pressure (Functional Unit 1.d) steam generator water level -high-high (Functional Unit 5.b) and Steam Generator Water Level (Functional Unit 6.c), the surveillance interval will remain at the current interval (i.e., 18 months). Therefore, the notation for the surveillance frequency for these two functions is being revised from 'R' to "18 months" and NNECO will continue to perform these surveillances at the 18-month frequency. NNECO expects to install new transmitter (i.e., same transmitter listed in Table 4.3-1) for these two functions during the sixth refueling outage to accommodate the undesirable-drift for the 24-month fuel cycle operation. NNECO will submit a license amendment request to the NRC to extend the frequency for these surveillances from once per 18 months to at least each refueling interval (i.e., nominal 24 months) in the future. In addition, the Action Statement i 1 1

U.S. Nuclear Regulatory Commission B15306/ Attachment 4/Page 7-July 26, 1995 has been revised to reflect a one column approach for all functional units, except for pressurizer pressure steam generator water level - high-high and steam generator water low-low. Changes to surveillance Requirements of level l, i Functional Unit 7.e, control building isolation control building inlet ventilation radiation, are addressed later in this submittal. t 6. Section 4.3.3.5.1. Remote Shutdown Instrumentation Table 4.3-6. Remote Shutdown Monitorina Instrumentation Surveillance Recuirements Surveillance Requirement 4.3.5.1 requires that each remote shutdown instrumentation channel shall be demonstrated operable by performance of a channel check on a monthly basis and channel calibration once per 18 months. Table 4.3-6 lists the remote instrumentation that requires a channel check and channel calibration. All remote instrumentation listed in Table 4.3-6, except the reactor trip breaker indication, are calibrated once per 18 months and are denoted by 'R'. NNECO proposes to extend this 1 frequency to at least once each refueling and will also be denoted by 'R' (i.e., nominal 24 months). The 'R' term is defined in Table 1.1 and a change to the definition of 'R' is addressed in our submittal dated May 1, 1995. That change redefines 'R' as "at least once each refueling" or l "at least once per 24 months." Therefore, no changes are proposed to this table. 7. Section 4.3.3.5.2. Surveillance Resuirement for Remote Shutdown Instrumentation Surveillance Requirement 4.3.3.5.2 requires that each remote. shutdown instrumentation transfer switch, power and control circuit including the actuated components, shall be demonstrated operable at least once per 18 months. NNECO proposes to extend this frequency to at least once each refueling interval (i.e., nominal 24 months). 8. Section 4.3.3.6. Accident Monitorina Instrumentation Surveillance Requirement 4.3.3.6 requires that each accident monitoring instrumentation channel shall be demonstrated operable by performance of a channel check on a monthly basis and a channel calibration at least once per 18 months. NNECO proposes to extend this frequency to at least once each refueling interval (i.e., nominal 24 months). The instrumentation is listed in Table 4.3-7. The 18-month frequency is denoted by 'R' in Table 4.3-7. The 'R' term is defined in Table 1.1 of the Millstone Unit No. 3 Technical I

1 U.S. Nuclear Regulatory Commission B15306/ Attachment 4/Page 8 July 26, 1995 Specifications and the change to definition 'R' is addressed in NNECO submittal dated May 1, 1995. That change redefines 'R' as "at least once each refueling" or "at least once per 24 months." Therefore, no changes are proposed to Table 4.3-7. It is noted that Functional Unit 16, Containment High Rar.ge Radiation Monitor of Table 4.3-7 is Area addressed later in this submittal. 9. Table 3.3 1, ACTIONS In Amendment 99, Section 4.4.1.4.2.3 was deleted and the information contained (list of valves) was relocated to Section 4.1.1.2.2. Therefore, ACTION 5 of Table 3.3-1 has been revised to reflect this change. This change is purely administrative. 10. Section 4.2.3.1.4. 4.2.3.1.5, and 4.2.3.1.6. RCS Flow Rate-- Four Looo Ooeration The proposed change modifies the frequency of Surveillance Requirements 4.2.3.1.4, 4.2.3.1.5, and 4.2.3.1.6 of the Millstone Unit No. 3 Technical Specifications. Surveillance l Requirement 4.2.3.1.4 requires that the reactor coolant l system (RCS) flow rate indicators shall be subject to a i channel calibration at least once per 18 months. Surveillance Requirement 4.2.3.1.5 requires that the RCS total flow rate shall be determined by precision heat balance measurement at least once per 18 months. Surveillance Requirement 4.2.3.1.6 requires that an additional 0.1% be added to the total RCS flow if the feedwater venturis are not inspected at least once per 18 months. NNECO proposes to extend the frequency of Surveillance Requirements 4.2.3.1.4, 4.2.3.1.5, and 4.2.3.1.6 from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). 11. Sections 4.2.3.2.4. 4.2.3.2.5. and 4.2.3.2.6. RCS Flow Rate- -Three Loon Operation The proposed change modifies the frequency of Surveillance Requirements 4.2.3.2.4, 4.2.3.2.5, and 4.2.3.2.6 of the Millstone Unit No. 3 Technical Specifications. Surveillance Requirement 4.2.3.2.4 requires that the RCS flow rate indicators shall be subjected to a channel calibration at least once per 18 months. Surveillance Requirement 4.2.3.2.5 requires that the RCS total flow rate shall be determined by precision heat balance measurement at least once per 18 months. Surveillance Requirement 4.2.3.2.6 requires that an additional 0.1% be added to the total RCS flow if the feedwater venturis are not inspected at least

U.S. Nuclear Regulatory Commission B15306/ Attachment 4/Page 9' July 26, 1995 once per 18 months. NNECO proposes to extend the frequency of Surveillance Requirements 4.2.3.2.4, 4.2.3.2.5, and 4.2.3.2.6 from at least once per 18. months to at least once each refueling interval (i.e., nominal 24 months). i 12. Process and Area Radiation Monitorina System Instrumentation Plant Technical Specification Surveillance Requirements for Process and Area Radiation Monitors pertaining to channel calibration and surveillance testing requirements of process and area radiation monitoring instruments and component. is currently performed on an 18 month frequency. NNECO proposes to extend this frequency for only two instruments (i.e., Table 4.3-3 Functional Unit 1.a, Containment Area Purge and Exhaust Isolation; and Table 4.3-7, Instrument 16, containment Area High Range Radiation Monitor) from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). All other process and, area radiation monitoring instruments listed in Tables 4.3-2, 4.3-3, 4.3-8, and 4.3-9 will remain at the 18 month frequency. Currently, it is denoted as 'R'. The definition I cf.'R' is being changed to state that the surveillance.will be performed once per 24 months or once each refueling l interval (i.e., nominal 24 months). Therefore, for the Functional Units remaining on an 18 month surveillance i interval, the 'R' in Tables 4.3-2, 4.3-3, 4.3-8 and 4.3-9 i will be changed to "18 months." This is purely an administrative change. l i l I i I i

~ 7... Docket No. 50-423 B15306 e i P 'I s 1, t-4 Millstone Nuclear Power Station, Unit No. 3 Proposed Revision to Technical Specifications 24-Month Fuel Cycle i Instrumentation and Reactor Coolant System 6 Surveillance Extensions i i l Safety Assessment 'and Significant Hazards -Consideration' for Changes to: t Reactor Trip System Instrumentation ESFAS Instrumentation Remote Shutdown Instrumentation Accident Monitoring Instrumentation RCS Total Flow Rate l Process and Radiation Monitoring Instrumentation i i I t July 1995 l t i i t

t U. S. Nuclear Regulatory Ccamission B15306/ Attachment 5/Page 1 July 26, 1995 Millstone Nuclear Power Station, Unit No. 3 Proposed Revision to Technical specifications 24-Month Fuel Cycle Instrumentation and Reactor Coolant System Safety Assessment and Significant Razards Consideration

Background

On June 7,

1995, Millstone Unit No. 3 began operating on a nominal 24-month fuel cycle.

To take advantage of this longer fuel cycle, Northeast Nuclear Energy Company (NNECO) is proposing to modify the frequency of a number of the Surveillance Requirements existing in the Millstone Unit No. 3 Technical Specifications. This request modifies the frequency of Surveillance Requirements for the reactor trip system (RTS), the engineered safety features. actuation system (ESFAS), the remote shutdown monitoring and the accident monitoring instrumentation, process and area radiation monitoring and the reactor coolant system flow monitoring instrumentation which are performed on an 18-month basis. I. section 4.3.1.1, surveillance Recuirements for Trio Actuatina Devices, Analoa ODerational Devices, Emercency Bus Voltmeter Safety Assessment The solid-state protection system (SSPS) provides the mechanism by which periodic testing of the trip actuating device during power and shutdown are permitted without initiating a protective action. Surveillance Requirement 4.3.1.1, among other

tests, requires that each RTS instrumentation channel and interlock and logic shall be demonstrated operable by a performance of a trip actuating device operational test (TADOT) for the RTS instrumentation listed in Table 4.3-1.

Table 1 provides the functional units that require a TADOT on an 18-month basis. NNECO proposes to extend the frequency of the TADOT of the instrumentation listed in Table 1 from at least once per 18-months to at least once each refueling (i.e., nominal 24 months). In addition, the frequencies of analog channel operational test of the reactor trip system interlocks Functional Unit 17 and channel calibration of emergency bus voltmeter (Table 4.3-6, item 16) are being extended from at least once per 18 months to at least once each refueling (i.e., nominal 24 months). L

i l U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 2 July 26, 1995 The proposed changes do not alter the intent or method by which the surveillances are conducted, do not involve any physical changes to the plant, do not alter the way any structure, system, or component functions, and do not modify the manner in which the plant is operated. As such, the proposed change to the frequency of the TADOT, channel calibration and analog channel operational test of the instruments listed in Table 1 will not degrade the ability of each instrument to perform its intended function. The components listed in Table 1 are covered under Procedures SP 3447S, OP 3622.1, .2, .3, SP 3446F31, SP 3444B11. A review of the past test data did not indicate any evidence of differences in the data which could be attributed to time dependent drift-related surveillance test failures. In addition, the SSPS TADOT and analog channel operational tests were successful. There have been no corrective maintenance activities, other than those associated with these surveillances, involving these components. A probabilistic risk assessment (PRA) review concluded that the proposed changes are not risk significant. On the basis of the above evaluation, there is a reasonable assurance that the frequency of the instruments listed in Table 1 can be extended from at least once per 18 months to at least once each refueling (i.e., nominal 24 months). Siunificant Hazards Consideration NNECO has reviewed the proposed changes in accordance with 10CFR50.92 and has concluded that the changes do not involve a significant hazards consideration (SHC). The basis for this conclusion is that the three criteria of 10CFR50.92(c) are not compromised. The proposed changes do not involve an SHC because the changes would not: 1. Involve a significant increase in the probability or consequences of an accident previously evaluated. The proposed changes e:: tend the frequency of the TADOT, channel calibration and analog channel operational tests for instruments listed in Table 1. The proposal would extend the frequency from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). The proposed changes do not alter the intent or method by which the surveillance is conducted. In addition, the acceptance criterion for the surveillance is i . -- - N

.U. S. Nuclear Regulatory commission B15306/ Attachment-5/Page 3-July 26, 1995 unchanged. As such,. the. proposed - changes will. not - degrade the ability of the instruments listed in-Table 1 to perform their function. An evaluation of past 'surveillances, preventive maintenance records, and the frequency of the type of corrective maintenances concludes that decreasing ' the surveillance frequency will have.little impact on safety. Since the proposed. changes only affects the surveillance frequency, the proposed changes ' cannot affect the probability of any previously analyzed. accident. While the proposed changes can lengthen the intervals -between surveillances, the increase in intervals has been evaluated, and it is concluded that there is no significant impact on the reliability or availability of the instruments listed in Table 1,.and consequently, there is no impact on the consequences of any analyzed accident. 2. Create the possibility of a new 'or different -kind of accident from any accident previously evaluated. The proposed changes 'to surveillance Requirement 4.3.1.1 do not modify the' design or operation of - any plant system. The proposed changes do not alter the intent or method by which the surveillance is conducted other than increasing the interval from 18 months to 24 months (nominal). The proposed changes 'do not introduce a new failure. mode. Therefore, the proposed changes do not - create the. possibility of. ~ a ; new or, -difforent kind of accident from' any.previously-analyzed. j 3. Involve a significant reduction in a margin of safety. 1 I Changing the frequency of TADOT, channel calibration,. analog channel operational tests for ' the instruments listed in Table 1 from'at least once per 18 months to once each refueling interval does not change the-basis i for frequency. The proposed changes do not alter the j intent or method by which the surveillance is conducted, do not involve any physical changes to the plant, do not alter the way any structure, system,-or component functions, and does not modify the manner in which the plant is operated. Further, the previous history of the instruments listed in Table 1 provides assurances that the changes will not affect the-reliability of these systems. Thus the proposed changes have no impact on the margin of safety.

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 4 July 26, 1995. II. Section 4.3.3.5.2. Remote Instrumentation surveillance Safety Assessment Surveillance Requirement 4.3.3.5.2 verifies the operability of each remote shutdown instrumentation transfer switch, power and control circuits including the actuated components at. least once per 18 months. NNECO proposes to extend the frequency of Surveillance Requirement 4.3.3.5.2 from at least once per 18 months to at least-once each refueling interval (i.e., nominal 24 months). The transfer switch panels allow the operators to change the control from the control room main control board to the auxiliary shutdown panel (ASP) when the plant operators must evacuate the control room for any reason. The devices listed in Table 3.3-4 of the Millstone Unit No. 3-Technical Specifications are controls required to safely shut down the plant from outside the control room. The operation of the components switched from the control room to the ASP are not time dependent. The transfer of control verifies that operability can be achieved from the ASP and confirms that the wiring and switches function as designed. i During shutdown, at least once per 18 months, all ASP controlled devices are transferred and tested using l Surveillance procedure SP 3673.4. Procedure SP 3673.4 is 'f followed to transfer control of only one device at a time after noting the open and closed position. The device is operated from the ASP and control is switched back to the control room. The device is operated again and restored to its initial position. The position is verified by an independent operator before the next device is tested. The proposed change to Surveillance Requirement 4.3.3.5.2 does not alter the intent or method by which the surveillances are conducted, does not involve any physical changes to the plant, does not alter the way.any structure,

system, or component functions, and does not modify the a

manner in which the plant is operated. As such, the proposed change to the frequency of Surveillance Requirement 4.3.3.5.2 will not degrade the ability of each remote shutdown transfer switch to transfer the control from the control room main board to the ASP. 1. A review of past surveillance results from Surveillance 4.3.3.5.2 indicates that there have been only two cases j where a transfer was not successful. The first case involved a valve (RCS*MV898) which failed to operate after transfer of control to the ASP. The second case involved a l x--

t U. S. Nuclear Regulatory Commission l B15306/ Attachment 5/Page 5 July 26, 1995 I ) valve (3RCS*MV8000A) which'would open from the ASP but would not close. Control was transferred back to the control room and the valve cycled normally. In both cases, the trouble was related to the wiring on the transfer switches which are General' Electric Type SB-9. Appropriate corrective actions were completed, and the devices were ratested successfully. An information memo was sent to all department heads to advise'of this problem with GE Type SB-9 & SB-1. NNECO considers these two cases as a random failure. A PRA review concluded that the proposed changes are not risk significant. On the basis of the above evaluation, there is a reasonable assurance that the frequency of Surveillance-Requirement 4.3.3.5.2 can be extended from at least once per 18 months to at least once each refueling (i.e., nominal 24 months). Significant Essards Consideration NNECO has reviewed the proposed change in accordance with 10CFR50.92 and has concluded that the change does not involve an SHC. This basis for this conclusion is that the three criteria of 10CFR50. 92 (c) are not compromised. The proposed change does not involve an SHC because the change l would not: ) 1. Involve a significant increase in the probability or j consequence of an accident previously evaluated. The proposed change to Surveillance Requirement 4.3.3.5.2 extends the frequency for demonstrating the" operability of each remote shutdown instrumentation transfer switch by transferring control from the control room to the ASP. The proposal would extend the frequency from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). The proposed change does not alter.the intent or method by which the surveillance is conducted. In addition, the acceptance criterion for each surveillance is unchanged. As such, the proposed change will not degrade the ability of each remote shutdown transfer switch to transfer the control from the control room main board to the ASP. An evaluation-of past surveillances, preventive maintenance records, and the frequency of the type of corrective maintenances concluded that decreasing the surveillance frequency will-have little impact on safety. Since the proposed change only affects the

k c

U. 8. Nuclear Regulatory Commission.

815306/ Attachment S/Page 6 + July 26, 1995 i surveillance frequency, the. proposed change. cannot. -affect the probabilityL of any previously analyzed i accident. While the proposed-change can lengthen tho' y ' intervals between surveillances, the increase' in intervals has been evaluated, and it is concluded-that there is no significant' impact on the reliability. or i availability of transfer switches.- consequently, there 1 is no impact on the consequences ofL any analyzed. accident. i 2. Create ' the possibility of a new ' or ' different kind of accident from any accident previously. evaluated.. The proposed change to surveillance ~ Requirement 4.3.3.5.2 does not modify the design or operation of any plant system. The proposed change does not alter the intent or method by which the surveillance is conducted other' than increasing the interval. from 1 18 months to 24 months. (nominal). The proposed change-1 does not introduce a new failure mode. Therefore,.the' i proposed change-does not create the possibility of a j new or different kind.of accident from any previously: l analyzed. j 3. Involve a significant reduction.in a margin of safety. j Changing the frequency of Surveillance ' Requirement l 4.3.3.5.2 from at least once-per-18 months to once each refueling interval does not change.the basis for frequency. The proposed change does: not alter. the intent or method by which the surveillance is j conducted, does not involve any physical' changes to the Plant, does not alter the way any structure, system, or. J component functions, and does not modify the' manner in which the plant is operated. Further, the _ previous history of each remote shutdown instrumentation i transfer switch provides assurances that the change will not affect the reliability: of these transfer switches. Thus, the proposed change has no-impact on the margin of the safety. ,.--.-m .w--

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U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 7 July 26, 1995 III. Section 4.3.1.2 and Section 4.3.2.2, ResDonse Time Testina of the Reactor TriD System and Encineered Safety Features Actuation system Instrumentation Safety Assessment Surveillance Requirements 4.3.1.2 and 4.3.2.2 require that the RTS and the ESFAS response time shall be demonstrated to i be within the limit at least once per 18 months. NNECO i proposes to extend the frequency of Surveillance Requirements 4.3.1.2 and 4.3.2.2 from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). Response time testing of RTS and ESFAS equipment is done in several distinct parts using an overlap method.

Response

times can be broken down into several different elements. Those elements are typically: sensor response time, signal processing response time, actuation logic response time, and finally, component response time. Technical specifications allow response time testing to be done on an N-1 testing i frequency according to the number of channels or trains in a given function. As a result, a component that is part of a 4 channel. system would be required to be tested every 72 months, while a component that is part of a two-train system would be required to be tested every 36 months. Technical specifications also allow testing to be done with i the use of overlap testing. A typical instrument loop is shown in Figure 1. Individual components are tested, and the sum of individual response 4 times is determined to determine the total instrument loop / ) train response time. The total response time for a reactor trip function may include as many as 8 different time measurements. The response time for a ESFAS function could include as many as 25-30 components. Table 2 shows the breakdown of how often various functions and components required to be tested. In order to evaluate the effect of a six-month increase in testing frequency on plant safety, the response time of each individual component will need to be reviewed. In excess of 300 instruments, relays, and components are tested in the response time testing program. The review of the tested components has been broken down into five different subsets as follows:

i ( l' . U. S. Nuclear Regulatory Commission-B15306/ Attachment 5/Page 8 July'26, 1995 1 l 1. Effect -of-the increased surveillance frequency on L' 4-channel instrumentation systems. 2.- Effect of. the increased frequency on-3-channel. i instrumentation systems. ] 3. Effect' of 'the increased ~ surveillance frequency 'on two-train component (actuation logic) systems. 4. Effect of the' increased surveillance frequency on two- . train components (pumps, valves diesel generators). l 5. Effect of the proposed change on tho' response times of resistance temperature detectors-(RTDs). Four Channel Instrumentation Systems The proposed change will extend the testing frequency of j four channel instrumentation systems such. as ' high neutron flux,. low pressurizer pressure, and steam generator water level from one channel every 18 months to one protection set once every 24 months. Millstone Unit No. 3 has four i protection sets of. reactor trip - and ESFAS instrumentation. j For four channel. systems, each protection set contains-one 1 channel. The and result,is that each protection set channel will be tested once every'96 months, up to a maximum of 120 months with a 25 percent extension.versusL the present ( maximum of once every 90 months. j A review of four channel ~ instrument response time' data for instrument ' loops which do.not contain RTDs for Millstone-j Unit No. ' 3 shows that the-longest reactor: trip and safety injection instrument, signal processing. equipment, and I actuation logic response times when determined on a worst case overlap basis consistently remain below 0.5 seconds for over 95% of all tests and in no case. have every exceeded - i 1.0 ceconds. This is to be compared against an analysis assumption of less than 2 seconds. The time between tests j has no effect on instrument response time. LThe interval between test has varied for particular instrument loops from l between 18 months and 86 months. The change in response time betwean instrument loops-test on a more. frequent basis j to those tests on a less frequent basis shows :no i distinguishable trend. As such it can be concluded that measured instrument response time does not show any significant change between testing. intervals. In-addition, all instrument loops which have response time testing requirements will continue to be. calibrated once every i 24 months and have analog operational channel checks j performed on a quarterly basis. The performance of

i U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 9 July 26, 1995 instrument calibrations and operational checks provides additional assurance that response time has not degraded. Instrument failure data shows that the response of electronic components does not typically slow down, but shows up as a failure. As such, continued performance of channel calibration and operational tests will provide assurance that the channel will remain operable. In addition, the data for response time tests on 7300 process instrumentation and SSPS is consistent with the information contained in WCAP-13595, " Feasibility Study for Elimination of

Response

Time

Testing, December,

1992, Proprietary Class 2" which supports the elimination of response time testing those components completely.

On the basis of the above evaluation, the frequency of response time can be extended from 18 months to 24 months with a maximum of 30 months with a 25% extension without adversely affecting safety. i A PRA review concluded that the proposed changes are not risk significant. Three Channel Instrumentation Systems The proposed che.nge will change the testing frequency of j three channel instrumentation systems such as pressurizer level and Reactor Coolant System (RCS) flow from one channel every 18 months to one protection set once every 24 months. I Millstone Unit No. 3 has four protection sets. Three channel instrument systems are distributed through the four protection sets such that each protection set will support some three channel loops, but no protection set will have all three channel instrument loops. The proposed change to the wording in the technical specifications will result in each three channel instrument loop being tested on the same frequency as four channel instrument loops. The instrumentation in three channel protection systems is identical to the instrumentation in four channel protection systems. Placing three channel instrument loops on the same testing frequency as four channel loops will not result in a degradation of performance as the equipment is the same. The evaluation provided for four channel systems supports the extension of three channel instrument loops to the same testing frequency. A PRA review concluded that the proposed changes are not risk significant.

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 10 July 26,.1995 TRAIN-RELATED EQUIPNENT Actuation Logic Train-related equipment would include the SSPS logic

cabinets, SSPS slave relays, emergency diesel generator diesel sequencer and relays, and actuated components such as reactor trip breakers, diesel generators,. circuit breakers, pumps, valves, and dampers.

Electronic components such as the load sequencer and SSPS would have their response time testing frequency extended from one train every 18 months to one train every 24 months. The not effect would be that each train of equipment would be tested once every 48 months versus the present once per 36 months. Past data for Millstone Unit No. 3 shows that the response time for electronic actuation logic plus instrument loop -response is consistently less than 0.5 seconds and have never exceeded 1 second. Safety analysis assumes 2 seconds for response time of instruments and actuation logic for functions that do not include RTDs. For those reactor trip functions which rely on pulse inputs such as Nuclear Instrument Overpower and RCP low speed total response has always been under 0.20 seconds in comparison to the 0.5 second limit. The history of response time measurements at Millstone Unit No. 3 supports an extension of the frequency of train-related. actuation logic to one train once per 24 months. Additionally, train-related components such as the emergency generator load sequencer and SSPS will continue to have other tests performed on a more frequent basis which will ensure operability. Technical specifications will continue to require performance of monthly actuation logic tests, quarterly. slave relay

tests, and monthly reactor trip breaker tests.

Engineered safety features loading testing will also be performed on both trains every.24 months. The extension in the testing frequency only moves out the actual measurement frequency for the equipment. A 'PRA review concluded that the proposed changes are not risk significant. CONPONENTS The extension of the response time testing frequency on actuated components will not effect the interval over which equipment is tested and timed. The extension of the surveillance interval will only effect the periodicity at which the total response tine summation is performed. Major-

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 11 July 26, 1995 components, such as pumps, valves, and diesel generators, are started and timed on a more frequent basis. Diesel generators are time tested once every six months. Pump and valves are tested in accordance with the requirements of Technical Specification 4.0.5. The time limits for the individual component operation time are less that the total response time limit. As timed components will continue to be tested on a more frequent basis, with time limits that are set conservatively with respect to overall response time, the extension in the response time will have no effect on the operation of the test components. A PRA review concluded that the proposed changes are not risk significant. RESISTANCE TEMPERATURE DETECTORS RTD are currently response time tested every 18 months. The trend history of RTDs has shown that RTD response time changes over time. Millstone Unit No. 3 has also modified RTD bypass piping and thermowells in the past making it difficult to trend RTD performance. RTD response time is subject to the mechanical fit between the sensing element and the RTD casing and the RTD casing in the RCS thermowell. The mechanical fit between these components is subject to change with the heatup and cooldown of the RCS. RTD response time trend history does not appear to be consistent enough to justify an increase in response time test interval as the present time. An increase in the response time test interval can still be supported provided that the total number of RTD response time tests performed per test interval is increased. Currently, each RTD is response time tested every fourth test interval. This results in each RTD being tested every 72 months up to a maximum of 90 months when a 25% extension is considered. As past data does not support an extension of a potential maximum of 120 months, a combination of increased test interval with increased testing will be proposed. The result will be that rather than one RTD set being tested once every 18 months, two RTD sets will be tested every 24 months. This will result in the actual RTD test interval being reduced to a maximum of once every 60 months versus the present maximum of once every 90 months. As a result, the actual test frequency on RTDs increases, therefore, the change can be implemented safely. A PRA review concluded that the proposed changes are not risk significant.

I U. S. Nuclear Regulatory Commission-B15306/ Attachment 5/Page 12 July 26, 1995 Sianificant Easards Consideration NNECO has reviewed the proposed changes in accordance with 10CFR59.92 and has concluded that the changes do not involve an SHC. The basis for this conclusion is that the three criteria of 10CFR59.92(c) are not compromised. The proposed changes do not involve an SHC because the changes would not: 1. Involve a significant increase in the probability or consequences of an accident previously evaluated. The proposed changes to Surveillance Requirements 4.3.1.2 and 4.3.2.2 extend the frequency for demonstrating the response times for the RTS and ESFAS instrumentation to be within the limit from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). The proposed changes do not alter the intent or method by which the surveillances are conducted. In addition, the acceptance criterion for each response time testing. is unchanged. The increase ~in intervals has been evaluated, and it is concluded that there is no significant impact on the reliability or availability of these RTS or ESFAS instrumentation systems on any analyzed accident. . The RTS and ESFAS are monitoring and actuation systems which operate to shut down the reactor and/or to mitigate the consequences of an accident. The scope of evaluation performed gives reasonable assurance that there will not be an adverse-impact on the consequences of any previously analyzed accident. 2. Create the possibility of.a new or different kind of accident from any accident previously evaluated. The proposed changes to Surveillance Requirements 4.3.1.2 and 4.3.2.2 do not modify the design or operation of any plant system. The proposed changes do not alter the intent or method by which the surveillances are conducted, other than increasing the interval from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). The proposed changes do not introduce a new failure mode. Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated. e

u e o U..'s.-Nuclear Regulatory Commission B15306/ Attachment 5/Page 13-J July 26, 1995 j. 3.- Involve a significant reduction in a margin.of safety. 4q changing the frequency of Surveillance Requirements' '4.3.1.2 and 4.3.2.2 from at least once per 18. months =to once each refueling interval.does not change the basis for frequency. The proposed change does'not alter the. intent or method by which the surveillance (i.e.,_ the i response time test) is conducted, does not involve any physical changes to the plant,;does not alter _the way i any structure,-system, or component functions, and does' i not modify the manner in which the plant is operated. I Further, - the ' previous history of response time tests i provides assurances that the change will not~ affect-the -l reliability and availability of the RTS and-ESFAS 1 instrumentation. Thus the proposed change has~ no impact on the margin of safety. 1 IV. surveillance meauirements for Loss of' Power 4 kV Undervoltaae - chamael calibration. Table 4.3-2. Functional Units s.a and s.b and 6.e. l i Safety Assessment J Surveillance Requirement 4.3.2.1 verifies the operability of ESFAS-instrumentation by performance of. various surveillances (e.g., -channel check, channel calibration, .l analog operational. tests, etc.) ~ t.various frequencies l a (e.g.,

shift, monthly, 18 months, etc.)._

The channel i calibration of Functional Units 8.a, 8.b and 6.e of Table l 4.3-2, Loss.of. Power,;is currently performediat least once per 18 months. NNECO proposes to extend the frequency of the channel calibration for the Loss of Power 4 kV 3 undervoltage instrumentation (i.e.,. relays) from at least once per 18 months to'at least once each refueling interval (i.e., nominal 24 months). 1 The 4160 volt,- Class 1E busses for Millstone Unit'No. 3.are designated 34C and 34D for the A and B trains, respectively. ' Each bus has'its own emergency diesel generator to_ provide power in the event of a loss of power or a voltage reduction. that is inadequate to run the loads that protect' tho' reactor. The voltage of. each bus is-. monitored by undervoltage relays that are set to ; detect a degraded ' voltLge condition (< 90%) and 'a loss of power (< 70% nominal). These relays ' are connected into a 2 out of 4 logic and time delayed at. 300 seconds with no accident signal or 8 seconds with an accident signal for the degraded voltage condition and < 2 seconds for the loss of power. a .i .a .. J

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 14 July 26, 1995 The proposed change to the frequency of the calibration for Functional Units 8.a and 8.b of Table 4.3-2 does not alter the intent or method by which the surveillances are conducted, does not involve any physical changes to the plant, does not alter the way any structure, system, or component functions, and does not modify the manner in which the plant is operated. As such, the change to the frequency of the calibration of Functional Units 8.a and 8.b of Table 4.3-2 will not degrade the ability of the Loss of Power 4 kV undervoltage relays to perform their safety function. During the first surveillance to confirm the setpoints in March 1987, the values were found to be below the required 80 volts which equates to 2800 volts on the 4160 volt busses. Two Plant Incident Reports (PIRs) and one License Event Report (LER) were written describing this occurrence. LER 87-011-00 describes the event and method to set the relays higher to ensure the trip point is reached before going below the technical specification value of 2800 volts. The relays performed well and all acceptances were met until October 1992 when relay 27B on bus 34D had to be adjusted to achieve t:ae correct value > 80 volts. The latest event of failure to meet the acceptance criteria occurrad on September 29, 1993, when relays 27C and 27D on bus "J4C tripped low and were replaced because satisfactory adjustment could not be achieved. The major problem with meeting the tight tolerances for this surveillance is the nature of the undervoltage relay which is a General Electric Type NGV13B and is adjusted by bending the contacts to achieve the setpoint. Another contributing factor is the volt meters used are 0.5% accuracy which can i differ from one surveillance to the next by 1.2 volts and still within the limits at the secondary voltage of the potential transformers. Even at the 80 volt settings this represents 0.4 volts allowed above or below the design setpoint. This setting is not that critical and could achieve the same goal at 82 or even 85 volts provided it operates before technical specification limit is reached. Time is not a factor in the setting of these relays as much as the technique of adjustment. An increase to a maximum 30 months (i.e., 24 months + 25%) before testing is reasonable since five years passed before a relay was out of tolerance. As already mentioned, the tight tolerance combined with the meter accuracy can cause a 0.4 volt out of a desired 0.5 volt range for this setting. Deviations from test to test are clustered around the desired setpoint. At

l 1 t U. S. Nuclear Regulatory Commission l B15306/ Attachment 5/Page 15 July 26, 1995-i sach surveillance the goal is to reset the relay as nearly j as possible to the-center of the desired range to preclude exceeding the limit at the next surveillance. This has been fairly successful and can be improved by making a change to -l the acceptance criteria. Even without a change, the longer interval between surveillances will have no impact on plant i safety. j A PRA review concluded that the proposed changes are not risk significant. i Significant Essards Consideration NNECO has reviewed the proposed change in accordance with l 10CFR50.92 and has concluded that the change does not involve an SHC. The basis for this conclusion is that the l three criteria of 10CFR50.92(c) are not compromised. The i proposed change does not involve an SHC because the change would not: i 1. Involve a significant increase in the probability or i consequence of an accident previously evaluated. The proposed change to Surveillance Requirement 4.3.2.1 ~ i extends the frequency for channel calibration of Functional Units 8.a, 8.b and 6.e of Table.4.3-2. The proposal would extend'the frequency from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). j The proposed change does not alter the intent or method by which the surveillance is conducted. In addition, the acceptance criterion.'for each surveillance. is unchanged. As such, the proposed' change will not degrade the ability of the Loss of Power 4 kV undervoltage relays to perform their safety function. An evaluation of past surveillances, preventive maintenance records, and the frequency of the type of l corrective maintenances concluded that decreasing the i surveillance frequency will have little impact on safety. Since the proposed change. only affects the j surveillance frequency, the proposed change cannot i affect the probability of any previously analyzed-accident. While the proposed change can lengthen the intervals.between surveillances,' the increase in intervals has been evaluated, and it is concluded that there is no significant impact on the reliability or l availability of the. Loss of Power 4 kV undervoltage i l 1 l g -.m c. .--n..

. ~. _' r ? '. _~\\_ \\ ~ f !l ~U.

s. Nuclear Regulatory Commission 1

d B15306/ Attachment 5/Page 16' i July.26, 1995 1 i relays and consequently, there is no impact on the-l ~ consequences of any analyzed accident. l j 2. Create the possibility of a new ' or different kind of I accident from any accident previously. evaluated. The proposed change to surveillance Requirement 4.3.2.1 does not modify the design or operation ~ of any plant system.. _ The proposed. change does not alter the. intent j or method by.which the surveillance is conducted other -l than increasing the interval-from 18 months to' 24 months _(nominal). The proposed ' change -does not l introduce a new failure mode. Therefore, the proposed change does not create the _ possibility of a new or different kind of accident from any _previously i analyzed. 3. Involve a significant reduction in a margin of safety. Changing the frequency of Surveillance. Requirement l 4.3.2.1 from at least once per 18 months to once each j refueling interval does not change the basis ~ for frequency. The proposed changes do not alter the intent or method by which the surveillance. is i conducted, do not involve any physical changes to the plant, do not. alter the way any structure, system, or component functions, and do not modify the manner in which the - plant is operated. Further, the previous - history of the Loss of Power 4 kV undervoltage relays provides-assurances that the changes will not affect a the reliability of these relays. Thus, the proposed. ) changes have no impact on the margin of the safety. v. surveillance meauirements for anaineerina - safety Features-natuation sys+- Instrumentation, channel caliheation. and' ch===es to

===otor Trin system Instr - =tation-Trin setnoints.- Table 2.2-1 and namineered safety features actuation system Instrumentation setpoints Table 3.3-4. A. -safety Assessment 1. surveillance meauirements for Reactor Trin system rastrumentation surveillance: meauirement. 4.3.1.1. Table 4.3-1 Millstone Unit No. 3 RTS monitors _ parameters related to safe operation and - trips the reactor to protect the reactor core against fuel rod cladding damage caused by a departure from nucleate boiling. The RTS also protects against reactor coolant system damage caused i ~ __-

r + G 1 i U. S. Nuclear Regulatory Commission. O B15306/ Attachment 5/Page 17.- i July-26, 1995. by high system pressure. The RTS automatically trips the reactor to protect the. core under the following-conditions:- l i . a. The reactor. power, as monitored by neutron flux,. l reaches a preset limit' s, b. The temperature . rise across the

core, as determined from the loop AT, reaches.a limit from l

an overpower AT setpoint or an overtemperature AT l -setpoint.. c. The ' pressurizer pressure reaches an established

]

minimum limit. d. Loss of reactor coolant flow. e. Pressurizer pressure or level trips the~ reactor-to-protect the primary coolant. ' boundary when pressurizer pressure or level reaches ~tho' 'l established maximum limit. f. Steam generator water level low-low. g. Reactor coolant pump low shaft speed. h. Turbine Trip. i. RTS Interlocks - P-6. P-7, P-8. P-9, P-10, P-13. Surveillance Requirement 4.3.1.1 and. Table 4.3-1 specify the modes and required frequency for the performance of the channel check, Channel Functional Test, and Channel Calibration operations for-each RTS instrument : channel. The' Technical Specification also defines the number of: channels of. instrumentation. required to be operable for each RTS functional. unit. For most instruments, Channel checks are performed at shiftly intervals, channel Functional Tests' at a quarterly interval, (it is noted that for the :RTS interlock, the channel functional tests are' performed at an 18-month interval) and channel Calibrations at an 18 month interval. - These surveillance requirements-1! assure that the instrumentation shall be operable and-define the action (s) to be t a k e n-- i f the operability-requirements are not met. NNECO proposes.to extend the frequency of the channel calibration from at least once g per 18 months to at least once each refueling interval-(i.e., nominal 24 months). No word changes are-required to Table 4.3-1, since the term 'R' is defined j ^l w e u.4 -9 +w-a L.. y yg

f L U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 18 July 26, 1995 in Table 1.1. The existing definition of the 'R' is being redefined separately. It is noted that an extension for the functional test interval for the RTS interlocks is already covered.under Section I of this attachment. 2. Surveillance Reauirements for Engineered Safet? Features Actuation System Instrumentation Surveillance Recuirements. 4.3.2.1, Table 4.3-2 Millstone Unit No. 3 ESFAS Instrumentation is designed to initiate actuation of-engineered safeguards equipment depending on the values of various process parameters that are provided as inputs to the ESFAS. When an ESFAS parameter exceeds the setpoint value, one or more ESFAS functions actuate responses intended to limit equipment damage, provide protection for control Room personnel, minimize offsite radiation releases, and mitigate the consequences of postulated accidents. Surveillance Requirement 4.3.2.1 and Table 4.3-2 specify the modes and required frequency for the performance of the Channel check, Channel Functional Test, and Channel Calibration operations for each ESFAS instrument channel. The Technical Specification also defines the number of channels of instrumentation-required to be operable for each ESFAS Functional Unit. For most instruments, Channel checks are performed at shiftly intervals, Channel Functional Tests at a quarterly interval, and Channel Calibrations at an 18 month interval. These surveillance requirements assure that the instrumentation shall be operable and define the action (s) to be taken if the operability requirements are not met. i Surveillance Requirement 4.3.2.1, Table 4.3-2, lists the following functional Units for ESFAS Instrumentation Channel Calibration. a. Containment Pressure-High 1 b. Pressurizer Pressure-Low & (P-11) c. Steamline Pressure-Low d. Containment Pressure-High 3 e. Containment Pressure-High 2 I f. Steamline Pressure Negative Rate-High

i i .U.LS. Nuclear Regulatory Commission-B15306/

Attachment:

5/Page 19 { July _26,-1995 l g. Steam Generator Water Level-High-High i h. T Low Coincident with Rx Trip (P-4) I 1. Steam' Generator Water Level-Low-Low Ej. Control BLDG. inlet Ventilation Radiation k. Low-Low T. (P_-12) NNECO proposes to extend the. frequency of1the Channel Calibration from at least once per 18 months to at least once.each refueling interval- (i.e., nominal'24 months). No word changes are required. to Table 4.3-2 since the term 'R' is defined - in Table 1.1. The existing definition of the term 'R' is being redefined separately.. j i 3. Surveillance Extension Program for RTS/ ESFAS Functions l The NRC staff has determined that Licensees should -[ address a number of. issues in providing an acceptable ~ i basis for extending the calibration-' interval- 'for. j instruments that are used to perform safety. functions. 1 NRC Generic Letter 91-04, (Reference 1) specifies the licensee actions to be taken to address-these issues. 'The " actions" include: q a. Confirming that instrument drift as determined by j as-found and as-left calibration data from surveillance and maintenance records has ~not, except on rare occasions,. exceeded acceptable limits for a calibration interval; b. Confirming that-the values of drift for each instrument type (make, model and range) and application have been determined with a high probability and a high degree of confidence; and-providing a summary -of the methodology and assumptions-used to determine the rates of instrument drift with time based upon historical i plant calibration data; c. Confirming.that the magnitude of instrument' drift-has been determined with a high probability and a high degree of-confidence for a bounding calibration interval of 30 months for each

y a

(

J s j ' U. S. Nuclear Regulatory Commission i B15306/ Attachment.5/Page 20 July.26, 1995 -instrument type and application that performs a . safety : function;.and providing a list of the 1 channels by - technical specification section that identifles these instrument applications;- d. Confirming that a comparison 'of the projected' instrument drift errors ~ has been made with the i values of drift use ein the setpoint analysis, providing proposed technical ~ specification changes 'to ' update trip setpoints if the-comparison indicates the' need-to revise setpoints. to accommodate large drift errors, and providing a j summary of the updated analysis conclusions to confirm that' safety limits and safety analysis' l assumptions are not exceeded; 'I e.. Confirming that the projected: instrument errors caused by drift are acceptable for control ~ of plant parameters to effect a safe shutdown with i the associated instrumentation; l f. Confirming that all. conditions and assumptions of the setpoint and safety analysis have been checked. and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel

checks, channel functional-tests, and channel calibration; and g.

Providing a summary description of the program for monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and'its effect on safety. To satisfy the requirements of Enclosure _2 to Generic j Letter 91-04, the general approach 'taken by - NNECO in evaluating the proposed calibration extensions includes l the comparison and-analysis of' actual versus. l theoretical instrument performance, the -. statistical ~ projection of actual past drift values.to arrive at maximum expected future drift values over_ a ' 30 month interval, and the performance of loop accuracy /setpoint calculations. The RTS/ESFAS' instrument drift analysis (Reference 3) documents actual-past and predicted future drift calculations used to evaluate actual and expected performance, and addresses most of the requirements of action items a., b.,- and c. listed above. The loop accuracy /setpoint calculations address

e U.'s. Nuclear Regulatory Commission l B15306/AttachmentL5/Page 21: 'I July 26,-1995 ) i parts of action items d. and f. (Reference 2). The l monitoring. program established in response to action j item g. is described later in this evaluation. (Action item e. is not applicable to the. RTS/ESFAS). Reference 1 2 brings the results of the drift analysis-and the loop i accuracy /setpoint calculations together to complete the l requirements of. action items c., d., and f. The report-evaluates the results and identifies the recommended i technical-specification changes. Drift analysis and the l ' loop accuracy /setpoint calculations summary is provided j below. 4. Instrument Drift Analysis j i I A plant -specific instrument drift analysis -was completed for. the RTS/ESFAS (Reference 3). . Field I I calibration data for RTS/ESFAS components-currently calibrated once every 18 (plus 25% for a maximum of 22.5) months was evaluated to-assess'the acceptability of extending the component's calibration-interval to 24 l (plus 25% for a maximum of 30)- months. The instrument i drift evaluation (IDE) for each RTS/ESFAS is comprised i of two phases. Phase 1 compares -past instrument performance to theoretical. acceptance limits (vendor l drift allowance (VDA) or calibration tolerance (CT)]. Phase 2 predicts future drift by statistically '[ extrapolating ' the component's derived drift data to arrive at a value for maximum expected drift over a 30-month intervcl (MED30). Reference '3 provides a detailed description of the methodology and assumptions used to assess field calibration data and to predict maximum expected instrument drift. j f Past performance is indicated by instrument " drift", which is derived from field calibration data by taking the absolute value of the difference between the "as-1, Found" and "as-left" calibration values. j i Generally, if phase 1 of the IDE-shows that a component's derived drift. data falls within the VDA or j the CT (with the exception of rare occurrences), past 1 performance is considered acceptable. Deviations fron the VDA or the - CT are ~ explained on a case-by-case basis.- Phase 2 predicts future instrument performance over a maximum MED30'using data-obtained from phase 1. i The MED30 values bounds hardware performance with a.95% probability at a 95% confidence level (i.e., there is a 95% probability that 95% of all past, present and future calibration results will be less than the -maximum expected drift). Loop accuracy /setpoint

3 1 i U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 22 July 26, 1995 calculation are then updated to include 30 month calibration uncertainties. 5. Loop Accuracy /setpoint calculations Enclosure _ 2 to Generic Letter-91-04 requires the-licensee to evaluate the effects: of an. increased calibration interval on instrument errors in order to confirm that drift will not result in instrument errors that exceed the assumptions of_the safety analysis. Loop accuracy calculations establish' total channel uncertainties by accounting for instrument inaccuracies consistent with industry methods described' in j Westinghouse Report WCAP 10991 Rev. 4 (Reference 2). .) The loop accuracy calculation for an instrument channel- ,i uses conservative values for-30 month calibration-uncertainties (vendor specified uncertainties or MED30, j) whichever is larger). If MED30 is the worst projected value of instrument drift but the value is unrealistic, vendor specified uncertainty values.may be used in the j calculation. The value calculated for MED30.is considered unrealistic or overly conservative if too few data points are available, resulting. in a high statistical multiplier. The loop accuracy /setpoint calculations must show that sufficient margin _ exists between the analytical limit and the existing field trip setting in order to be consistent with the j assumptions of the safety analysis. The calculations also verify whether technical specification setpoint limits provide sufficient margin over the analytical j limit to allow for instrument inaccuracies. t 1 The results of the loop accuracy setpoint calculation j hold the greatest weight.in-determining whether a calibration interval can be safely extended or not. If the loop accuracy /setpoint calculations indicate that sufficient margin exists and the'. assumptions of the I safety analysis are not-violated, reasonable assurance exists that the calibration interval may be extended. The -results of the drift analysis and the ' loop -l accuracy /setpoint calculations for the instruments used 'l in performing the functions required by the technical specifications'in question are discussed in References 1 2 and 3. References 2 and 3 provide a summary l description of. the methodology used to perform the j drift

analysis, and provides copies of loop i

accuracy /setpoint calculations for the RTS/ESFAS { instrumentation. i l .. ~. -

3 1 f f .) J l U. S. Nuclear Regulatory Commission-B15300/ Attachment'5/Page.23 .. July 26,'1995 i The results ' of the Millstone Unit No. 3 calibration 4 extension program show that RTS/ESFAS trip settings 1 were conservatively selected in the mid 1980's, leaving ] adequate safety margins between.the. analytical and the-j field trip' settings even after accounting for instrument. ~ loop ~ inaccuracies resulting. from the extended calibration intervals. Millstone Unit No.-3 confirmed these margins by performing loop accuracy calculations in accordance with WCAP 10991, Rev. 4, using the statistically adjusted field drift ~ data to account for tho' additional' instrument uncertainties i associated'with the extended calibration intervals.- l A PRA review concluded that the proposed changes are not risk.significant. s. Drift Monitorina Procram In accordance with Generic Letter 91-04, a program to i monitor future calibration data is established to access the.effect a longer calibration interval has on.- l instrument drift. -The intent of the program is - to i confirm that actual future drift values are within. projacted . limits. The -program identifies. l instrumentation whose drift is -not ~within the assumed values in the loop accuracy /setpoint calculations. l The calibration procedure for each RTS/ESFAS component j or instrument channel receiving approval for extension l of its calibration interval is revised to specify an as-found acceptance criterion which reflects the-projected limit. 'A-component-showing as-found ~ conditions beyond the specified ' acceptance. tolerance i may indicate a faulty or degraded device. Data for this instrument will be' evaluated over a series of calibration intervals to more. closely monitor instrument performance. Exceeding the as-found acceptance criteria, will result.in immediate action for appropriate corrective action and channel i operability. However, this does not necessarily result l in a technical specification violation. or a safety concern since the loop accuracy / setpoint calculations show additional margin exist between--the safety j analysis assumptions and the field trip settings even after accounting' for instrument loop ~ inaccuracies resulting from the extended calibration-intervals. j I

_+. A - U.-S.' Nuclear Regulatory Commission B15306/ Attachment 5/Page 24 July 26, 1995 7. Calibration Freauencies Remainina at 18 Month Interval The following functional-units listed in Table. 4.3-1 and Table 4.3-2 to the Millstone Unit No'. 3 Technical Specifications are not being changed at this time:- Calibration frequency of the Steam Generator water j level transmitters (Functional Unit - 13 of Table j 4.3-1, Functional Units 5.b and 6.c _ of Table. 4.3-2). _q Calibration frequency of the pressurizer pressure.. L transmitters (Functional Units 9 and 10. of Table 1 I 4.3-1, Functional Unit 1.d'of Table'4.3-2). Past performance of the above listed components did not meet Millstone Unit No. 3 acceptance criteria for the i extension of surveillance requirements. j 'I However, extension of the calibration interval for.the pressurizer pressure transmitters and steam generator transmitters may be; sought in the future. S. RTS and ESFAS SetDoints. Table 2.2-1 and 3.3-4 currently Millstone Unit.No.

3. Technical Specifications utilize the concept of an allowable value as.a means of triggering an operability determination for channel.-

This has created a burden due to fixed, allowable value in plant technical specification. Furthermore, it does not allow accurately to satisfy the plant procedures - 1 and practices for determining equipment operability. Based on Millstone Unit. No. 3 equipment performance,. j Westinghouse has developed an enhanced method 'of determining equipment operability _ without' _ the j restrictions of the 5 column technical specification. and fixed allowable value. Based on the evaluation of equipment drift data for l Millstone Unit.No. 3 over.the past.4 cycles, the need to reduce. Technical Specification.chenges,and the objective of. increasing surveillances (tron the current. 18 month interval to a ~ nominal 24 month interval) for< f' RTS and ESFAS functions, NNECO-proposes the elimination of the allowable value - as a means - for determining j channel operability. As an alternative to the allowable value as an i operability trigger, NNECO proposes that the allowable value operability criteria be eliminated from the i i

U.'S.' Nuclear Regulatory Commission ' y B15306/ Attachment 5/Page 25 ' July 26, 1995 Millstone Unit'No'. 3 Technical Specifications and only the Nominal Trip'Setpoint be-included'in the Millstone Technical Specificationsifor.RTS & ESFAS functions. Operability criteria would-be' included in the Millitone Unit -No. 3 administrative procedures(surveillance procedures) and controlled by NNECO. -) The Operability criteria for. sensors and racks will be { based on the following: q l The identification -of trigger points based on actual channel instrumentation drift. 3 Ability to recalibrate. the hardware . ith. w 4 acceptable calibration tolerances. The evaluation of equipment performance overftime i utilizing actual plant drift performance data as. part of a monitoring program. To accomplish -the Operability

Criteria, NNECO.has collected RTS/ESFAS function hardware data over the 1

past four (4) operating cycles of Millstone Unit No. 3, i in accordance with Generic Letter 91-04. Enclosure 2 l (Reference -1). This data was further analyzed by .l Westinghouse, utilizing enhanced methods of~ determining equipment operability and is discussed in detail in Reference 3. .j Reference '2' analysis has demonstrated - that adequate margin for nominal trip setpoints exist and safety analysis limits are - preserved in. all RTS/ESFAS ? functions. Based on this. analysis, NNECO is - proposing that the Millstone Unit No. 3 Technical Specification revision reflecting nominal trip setpoint-be-reported for. 1 RTS/ESFAS Table 4.3-1 and Table 4.3-2. { NNECO is also requesting the Bases Section, 2.2.1,-for 'RTS and Bases Section 3/4.3 for;ESFAS be also changed to accommodate'the operability requirements for the RTS

j and ESFAS respectively.

r It. is noted that certain Functional Units,- where j calibration frequency remains at the 18 month i frequency, will use the. existing operability criteria-l (i.e.-allowable value). l 1 i ~..

I "U.~8. Nuclear Regulatory Commission
B15306/ Attachment 5/Page 26 July 26, 1995 The proposed changes do not alter the intent or method by which the lsurveillances are conducted, do -not

.j involve and physical changes'to the plant,.do not. alter the way.any structure, system, or component functions, and ' do - not' modify the manner. in, which the plant-is operational.. As such the proposed change to the ' frequency of the channel calibration of the. instruments listed in Tables 4.3-1 and'4.3-2 will not degrade the ability of each - instrument to perform its. intended functions. In addition,. this safety assessment addresses the e proposed request to change the Reactor Coolant Pump (RCP) low shaft speed trip set point (Table 2.2-1 Functional Unit 15) from 95.8% to 92.5% of rated. speed. ~ Electrical grid instabilities could cause significant changes in RCP speed in that grid frequency decay would-cause a decrease in RCP pump shaft' speed. The purpose'. of the proposed change to Functional Unit 15 of Table 2.2-1 is to lower the trip :setpoint on low RCP pump ~ shaft speed to allow additional time to' correct a grid ~ underfrequency condition. A premature plant trip during a grid underfrequency transient would tend to further destabilize the electrical grid. j Currently Millstone Unit No. 3 low shaft Speed RCP has a set point.of 95.8%. of rated

speed, which is equivalent to an electrical system grid frequency of 57.5 Hz and it supports the safety analysis. limits of-55.2 Hz (i.e. 92% of rated speed).

The RCP low shaft speed present set point of 95.8% does not assure adequate coordination with grid load shed relays designed to -restore load / generation unbalance during some grid underfrequency events. In order to address this issue and to support a revised (new) set point of 92.5% of rated speed, which is the equivalent of grid 1 frequency of 55.5 Hz, the following evaluation is-performed. For the Functional Unit Table-4.3-1. item 15, low shaft speed RCP, instrumentation drift analysis and loop calculation / set points were performed.under the 24 month fuel cycle-Calibration-Extension program j (References 2 and 3). Based on the results of. the - 1 Calibration Extension program and current Safety analysis limits (92% of rated speed), it is concluded that there exist sufficient margin to accommodate the new nominal trip set point of 92.5% of rated speed. i

.) l U. S. Nuclear. Regulatory Commission B15306/ Attachment 5/Page 27- . July 26, 1995 1 3. Significant Rasards consideration NNECO'has reviewed the proposed changes'to Table 2.2-1, ~ i Table 3.3-4,. Table .4.3-l' and Table 4.3-2 and has concluded that the-proposed-changes do not involve an SHC. The basis for this conclusion in that the-three criteria. of 10CFR50.92 (c) are.not compromised. The proposed changes. do not involve an SHC because the-changes would not: 1. Involve a-significant increase in the probability or consequences of an accident .previously evaluated. The proposed changes to Tables 2. 2-1. and 3.3-4 simply involve changes from five column format to one column format. The RTS trip setpoints and ESFAS trip setpoints remain ' unchanged. The operability criteria has been moved-to surveillance-procedures. and Reference 2 has demonstrated that an adequate. margin' for. normal trip setpoints exist and. safety analysis limits-are preserved in all RTS/ESFAS functions. Changing the RCP low shaft speed trip setpoint will;not change the probability of occurrence of the event. The existing accident analysis (Millstone Unit No. 3 FSAR section 15.3.2) of. the-complete loss of forced reactor coolant flow remains valid for the proposed change. Therefore, .) the change to the RCP low shaft' speed trip 1 setpoint does not significantly increase the probability or consequences of any previously analyzed accident. The proposed changes to Surveillance Requirements. 4.3.1.1 and 4.3.2.1 ~ extend the frequency for-channel calibration of 'the instruments listed in Tables 4.3-1 and 4.3-2. The' proposal would extend the frequency from at least once per.18-months to at least once each refueling interval (i.e.,; nominal 24. months). Extension of the calibration and surveillance test intervals in

question, was ; evaluated and the results are documented in References 2 and 3.

These~ references document.that none of the proposed extensions of calibration and-surveillance test intervals degrade performance of

U. 3 S.-Nuclear Regulatory Commission B15306/ Attachment 5/Page 28-July 26, 1995 the RTS and ESFAS. Additionally,.a; comprehensive on-line surveillance program-demonstrates the operability of the RTS and ESFAS instrumentation i and readily detects potential. instrument failures. In' addition, the proposed changes to Tables.2.2-1 3.3-4, 4.3-1, and 4.3-2 do not alter the intent.or j method by which the surveillances are conducted. Therefore,'the scope of evaluation performed gives i reasonable assurance that there - will not be an l adverse impact on' the consequences or the probability of any previously analyzed accident. 2. Create the possibility of a new or different kind of . accident from 'any accident. previously-J evaluated. j The existing. design basis adequately covers' the plant response with the proposed change to the RCP low shaft 1 speed trip setpoint. The change 'does not introduce new failure modes. { The proposed changes to Tables 2.2-1, 3.3-4, 4.3-1, and 4.3-2 do not modify the design or operation of any plant system. The proposed changes do not alter the intent or method by which the surveillances are conducted,. other than-increasing the interval from at least once per 18 months to at least ' once each refueling interval (i.e., nominal 24 months). Therefore, the proposed changes do not create the possibility of a new or different. kind of accident-from any_ accident previously evaluated. 3. Involve and significant. reduction in a margin. of. safety. The proposed changes to. Tables '2.2-1 and 3.3-4 simply modify the existing five column format to a one column' format to show the RTS'and ESFAS trip setpoints for-- individual functions.- The operability criteria (allowable values) has been moved to the surveillance procedures. The RTS'and ESFAS setpoints remain unchanged and Reference' 2 has demonstrated that an adequate margin. for. normal - trip setpoints exist and safety analysis limits are preserved ~in all RTS/ESFAS functions. l i

k k,' US L ' Nuclear Regulatory Commission .915306/ Attachment 5/Page:29' i July 26,'1995 i Since the safety limits. of the design are still met,. the proposed change to the RCP low shaft. speed. trip setpoint does not reduce the margin of safety. l The proposed changes to Tables 4.3'-1 and. 4 '. 3 -2 extend the frequency for. channel calibration for i the instruments listed in Tables. 4.3-1 and 4.3-2 from at least once per 18 months to at least once-l each refueling. The extension of;the calibration frequency has been evaluated and the. results are i documented. in References '2' and 3. These references demonstrate that none of the proposed extensions of calibration degrade the performance of the RTS*and the ESFAS. Therefore,7 the proposed changes have no impact on the margin of safety' -t VI. section 4.3.3.5. surveillance Reauirements for the Accident Monitorina-Instrumentation and section 4.3.3.5.1. surveillance Resuirements-for Remote shutdown Instrumentation, Channel Calibration i A. safety Assessment 1. Surveillance Reauirements for Accident Monitorina Instrumentation. Section. 4.3.3.6. Table 4.3 Millstone Unit No. 3 Accident Monitoring ^ Instrumentation (AMI) provides the mechanism by which the plant operations personnel can monitor the plant. parameters throughout all-operating. conditions, including anticipated operational occurrences, accidents, and post accident conditions. Surveillance requirement 4.3.3.6 and Table.4.3-7 specify that channel Checks be performed' on a monthly basis and Channel Calibrations ' at an' 18 month ' interval. Surveillance Requirement 4.3.3.6 and Table 4.3-7 assure that-the instrumentation ~ shall be operable -and define the action (s). to be a taken if the operability requirements are not met. NNECO proposes to extend the frequency of the channel calibration from at least once per 18 ' months to at least once each refueling interval-(i.e., nominal.24 months). No word changed' are required to Table 4.3-7, since ' the term 'R' is defined in Table 1.1. The existing ~ definition of the 'R' is being redefined separately.

i i U. s.-Nuclear' Regulatory Commission ~ B15306/ Attachment 5/Page 30 July 26, 1995-( Surveillance Requirement 4.3.3.6 and Table 4.3-7 ' lists.the.following.' functional Units for AMI Instrumentation Channel Calibration. l i Containment Pressure f a) Normal Range l b) Extended Range j Reactor Coolant Outlet Temperature Tuar. (Wide Range) Tom 3 Reactor Coolant Inlet Temperature ' - (Wide Range) Reactor Coolant Pressure - Wide Range Pressurizer Water Level Steam Line Pressure Steam Generator Water Level - Narrow Range Steam Generator Water Level - Wide Range i Refueling Water Storage Tank Water Level i Demineralized Water Storage Tank Water Level' Auxiliary Feedwater Flow Rate Reactor Coolant System Subcooling Margin Monitor Containment Water Level (Wide Range) Core Exit Thermocouples High Range Radiation. Containment Area Monitor (This is. covered later in this submittal) i Reactor Vessel Water Level i Containment Hydrogen Monitor Neutron Flux ._m ,w w v g

i p U.,S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 31 l July 26, 1995 l 2. Surveillance Reauirements for Remote Shutdown Monitorina Instrumentation (RSMI) Section. 4.3.3.5.1. Table 4.3-6 Millstone Unit No. 3 Remote Shutdown Monitoring Instrumentation provides the mechanism by which the plant personnel can monitor the plant parameters at the remote.

location, when the

' control room is-uninhabitable. Surveillance requirement 4.3.3.5.1 and Table 4.3-6 specify that the channel checks be performed on a monthly basis and Channel Calibrations at an 18 month interval. Surveillance Requirement.4.3.3.5.1 and Table 4.3-6-assure that the instrumentation shall be operable and define the action (s) to be taken if the operability requirements are not met. NNECO proposes to extend the frequency of the channel calibration from at least once per 18 months to at least once each refueling interval. (i.e., nominal 24. months). No word changed are required to Table 4.3-6, since the term 'R' is defined in Table 1.1. the existing definition 'of the 'R' is being redefined separately. Surveillance Requirement 4.3.3.6 and Table 4.3-6 list the following Functional. Units for Remote Shutdown Monitoring Instrumentation Channel Calibration: Pressurizer Pressure Pressurizer Level Steam Generator Pressure Steam Generator Water Level Auxiliary Feedwater Flow Rate Loop Hot Leg Temperature Loop Cold Leg Temperature

t r U.~ S.5 Nuclear Regulatory Commission U B15306/ Attachment S/Page 32 July 26, 1995 Reactor. Coolant System Pressure (Wide ~ Range) i DWST Level i RWST Level -l Containment Pressure l t Emergency Bus Voltmeters (This is covered in item-l I of this submittal) i Source Range Count Rate i i Intermediate Range Amps i Boric Acid Tank Level 3. Surveillance Extension Procram for AMI/RSMI Functions ) The NRC staff has determined that Licensees. should; address a number of issues in providing'an acceptable basis for extending the calibration interval._for instruments that are used to perform safety functions. NRC Generic Letter ' 91-04, Enclosure 2. (Reference - -1). specifies the licensee ' actions to be ' taken to address-these' issues. The " actions" include: I a. Confirming that instrument drift as determined by as-found and .as-left calibration -data from' .) surveillance and maintenance records-has

not,

-l except on rare occasions, exceeded acceptable i limits for a calibration' interval; b. Confirming that the -values of drift for each instrument type (make, model and:. range) 'and' application have been determined with a high probability and a high degree of confidence; and providing a summary of the methodology' and assumptions used to determine the rate of

u. -I U. S.-Nuclear: Regulatory Commiasion

B15306/ Attachment 5/Page 33 July 26,11995 1

instrument' drift with time based upon historical plant calibration' data; j l c. Confirming that.the magnitude of instrument drift-I has been determined with a high probability and a high degree of confidence for... a bounding calibration interval of

30. months for

'each instrumant type and ' application that performs a; safety function; and providing -a list-of the 'i channels by technical specification section that-identifies these instrument applications; } d. Confirming that a comparison of the projected i instrument drift errors has been made.with' the values of drift use in the setpoint'. analysis,. .i providing proposed technical specification changes to-update trip-setpoints if the comparison indicates the need to revise. ~ setpoints to accommodate large. drift errors, and. providing -'a j summary of the updated analysis conclusions to ] confirm that safety limits and safety analysis .l assumptions are not exceeded,. i e. Confirming that the. projected instrument errors caused by _ drift are acceptable _ for control of j plant parameters to effect a safe shutdown ; with the associated instrumentation: -l f. Confirming that all conditions'and-assumptions of j the setpoint and safety analysis have been checked-and are appropriately reflected in the acceptance criteria' of plant surveillance procedures for i channel

checks, channel. functional' tests, and channel calibration; and i

g. Providing a summary-description =of the program for k monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and its effect on safety. l To satisfy the requirements of Enclosure 2 to -' Generic Letter 91-04, the general approach taken by NNECO in evaluating the proposed calibration extensions includes the comparison and analysis of actual versus l theoretical instrument performance, the statistical l 1

p .U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 34 July 26, 1995 projection of actual past drift. values to arrive. at maximum expected' future - drift values over a 30 month' interval,.and the performance of loop accuracy /setpoint calculations. The AMI/RSM instrument drift analysis .(References 2_ and 3) documents actual pastL and predicted future drift calculations used to evaluate-actual and expected performance, and addresses most of the-requirements of action item a., b., an' c.= listed above. The loop accuracy calculations addre s parts of action items d., e., and f.. (Reference 3). The monitoring program established in response to action item g. is described later-in this_ evaluation. C References' b. and d. bring the results of the drift analysis and the loop accuracy calculations together to complete the requirements of action' items c.,

d.,

e, and f. .The report evaluates the results and-identifies-the recommended technical specification changes. Drift analysis and the loop accuracy calatlations summary is provided below. 4. Instrument Drift Analysis A-plant specific instrument drift. analysis was completed. for the AMI/RSM Instrumentation (Reference 2). Field calibration data for-AMI/ .RSM Instrumentation components currently' calibrated once every 18 (plus 25% for a maximum of 22.5) months was evaluated to assess the-acceptability of extending the component's calibration interval to 24- (plus 25%- for a maximum of 30) months. The instrument drift evaluation (IDE) for each AMI/RSM is comprised of - two phases. Phase 1 compares past' instrument performance to theoretical acceptance limits VDA or CT. Phase 2 predicts future drift by: statistically extrapolating the component's derived drift data to arrive-at-a value for maximum expected drift over a MED20. Reference'3 provides a detailed description of the methodology and assumptions used to assess field calibration data and to predict maximum expected instrument drift. Past performance is indicated by instrument " drift", which is derived from field calibration. data by taking the absolute value of the difference between-the "as-Found" and "as-left" calibration values. Generally, if phase 1 of the IDE shows that a component's derived drift data falls within the vendor drift allowance or the calibration tolerance (with the exception of rare occurrences), past. performance is considered acceptable. Deviations from the VDA or the i i l

= . = _

l i

l 'U. S.: Nuclear Regulatory Commission' EB15306/ Attachment 5/Page 35 .I July 26,.1995 CT are explained on a case-by-case basis. Phase 2 i predicts future instrument performance over a maximum- + MED30 using. data obtained ' from phase 1. The MED30 ? values. bounds hardware performance - with a. 95% probability at a 95%' confidence level (i.e., there is a-95% probability that - 95% of. all past, present and l ' future calibration. results will be less lthan the i maximum expected. drift).. . Loop accuracy /setpoint calculation are then updated-to include 30 month .j calibration uncertainties.' 5. Loon Accuraev/Setnoint calculations { . Enclosure 2 to Generic Letter 91-04 requires the licensee to evaluate the effects of an increased j calibration' interval' on instrument errors in order to confirm that drift will not result.in instrument errors j that exceed the assumptions of the safety. analysis. I Loop accuracy calculations establish' total channel uncertainties by accounting for instrument. inaccuracies j consistent with industry. methods described' in Westinghouse Report WCAP 14353 Rev. 4' (Reference 4). The loop accuracy. calculation for an instrument channel- ) uses conservative values for 30 month. calibration j uncertainties (vendor specified uncertainties or MED30, j whichever.is larger). If MED30 is the worst projected' value of instrument drift but the value.is unrealistic,. vendor specified uncertainty values may be used in the calculation. The value calcul'ated for MED30 is considered unrealistic' or overly conservative if too few data points are' available, resulting in a high statistical multiplier. The loop accuracy calculations i must show that sufficient margin exists between the required accuracy and the existing indicated errors in-inaccuracies. J The ressalts of the loop accuracy calculation hold the grantest weight in determining whether, a calibration intervalL can be safely. extended or not. If the-loop'. accuracy calculations indicate that sufficient margin l exists and the required accuracies are met, reasonable j assurance exists that tha calibration interval may be - l extended. i 3 The results of the drift analysis and the loop accuracy calculations for the instruments used in performing the functions required by the technical' specifications in question.are discussed' in References 2, 3, and 4. References 2, 3, and 4 provide a summary description of

T f i U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 36 July 26, 1995 i the methodology used to perform the drift analysis, and include loop accuracy calculations for the AMI/RSM instrumentation. i The results of the Millstone Unit No. 3 calibration extension program show that AMI/RSM instrumentation indication has adequate margin between the required accuracy and instrument uncertainties. A PRA review concluded that the proposed changes are not risk significant. 6. Drift Monitorina Proaram In accordance with Generic Letter 91-04, a program to l monitor future calibration data is established to access the effect a longer calibration interval has on instrument drift. The intent of the program is to confirm that actual future drift values are within projected limits. The program _ identifies instrumentation whose drift is not within the assumed values in the loop accuracy /setpoint calculations. The calibration procedure for each AMI/RSMI component or instrument channel receiving approval for extension i of its calibration interval is revise.d to specify an as-found acceptance criterion which reflects the l projected limit. A component showing as-found '1 conditions beyond the specified acceptance tolerance may indicate a faulty or degraded device. Data for i this instrument will be evaluated over a series of calibration intervals to more closely monitor instrument performance. Exceeding the as-found~ acceptance criteria, will result in immediate action for appropriate corrective action and channel operability. However, this does not necessarily result in a technical specification violation or a safety concern since the loop accuracy calculations show additional margin exist between the required accuracies and the instrument indication even after accounting for instrument loop inaccuracies resulting from the extended calibration intervals. B. Sionificant Hazards Consideration NNECO has reviewed the proposed changes to Table 4.3-6, and Table 4.3-7 and has concluded that the proposed changes do not involve an SHC. The basis for this conclusion in that the three criteria of 10CFR50.92 (c)

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 37 July 26, 1995 are not compromised. The proposed changes do not involve an SHC because the changes would not: j 1. Involve a significant increase in the probability or consequences of an accident previously evaluated. The proposed changes to Tables 4.3-6, and 4.3-7 extend the frequency for channel calibration of the instruments listed in Tables 4.3-6 and 4.3-7. The proposal would extend the frequency from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). Extension of the calibration and surveillance test interval in question were evaluated and results are documented in References 2, 3, 4 and 5. These references document that none of the proposed extensions of calibration and surveillance test intervals degrade performance of the AMI and RSMI. Additionally, a comprehensive on-line surveillance program demonstrates the operability of the AMI and RSM instrumentation and readily detects potential instrument failures. In addition, the proposed changes to Tables 4.3-6, and 4.3-7 do not alter the intent or method by which the surveillances are conducted. Therefore, the scope of evaluation performed gives reasonable assurance that there will not be an adverse impact on the consequences or the probability of any previously analyzed accident. 2. Create the possibility of a new or different kind of accident from any accident previously evaluated. The proposed changes to Tables 4.3-6, and 4.3-7 do not modify the design or operation of any plant system. The proposed changes do not alter the intent or method by which the. surveillances are conducted, other than increasing the interval from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

l I I U.-S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 38 July 26, 1995 3. Involve and significant reduction in a margin of safety. j i The proposed changes to Tables 4.3-6 and 4.3-7 extend the frequency for channel calibration for the instruments listed in Tables 4.3-6 and 4.3-7 from.at least once per 18 months.to at least each refueling (nominal 24 months). The' extension of 4 the calibration frequency has been. evaluated and results are documented in References 2, 3, 4 and i 5. These references demonstrate that none of the proposed extensions ~of calibration degrade the i performance of the AMI and the RSMI. Therefore, the proposed changes have no impact on the margin of safety. 1 i I j

U. S. Nuclear Regulatory Commission -B15306/ Attachment 5/Page 39 July 26, 1995 VII. Surveillance Remuirements Related to the Process and Area Radiation Monitorina System Safety Assessment The Millstone Unit No. 3 Technical Specification surveillance Requirements for process and area radiation monitors pertaining to the Channel Calibration are currently performed at least once per 18 months (i.e., by a notation 'R' in Tables 4.3-2, 4.3-3, 4.3-7, 4.3-8.and 4.3-9). NNECO is proposing to extend this interval to at least once each refueling interval (i.e., nominal 24 months) for only two instruments (i.e., Table 4.3-3, Functional Unit 1.a, containment Area Purge and Exhaust Isolation, and Table 4.3-7, Instrument 16, Containment Area High Range Radiation Monitor). The term 'R' is currently defined as once per 18 months in Table 1.1 of the Millstone Unit No. 3 Technical specifications. The change to Table 1.1 (i.e., a change from 18 months to 24 months) has been proposed under a separate submittal (i.e., NNECO submittal dated May 1, 1995). Therefore, no changes are required for the above instruments. However, all other process and area radiation monitoring instrument listed in Tables 4.3-2, 4.3-3, 4.3-8 and 4.3-9 will remain at the 18-month frequency. Therefore, the term 'R,' noted in Tables 4.3-8, 4.3-9, 4.3-3 and 4.3-2, for the process and area radiation monitoring instrumentation will be revised to "18 months." This change is purely an administrative change and has no impact on the consequences or probability of an accident previously evaluated. The proposed change to Surveillance Requirements for the instruments listed in Tables 4.3-3 and 4.3-7 (i.e., Functional Unit 1.a and Instrument 16, respectively) does not alter the intent or method by which the surveillance is' conducted, does not involve any physical changes to the

plant, does not alter the way any structure, system or component functions and does not modify in which the plant is operated.

As such, the proposed change.to the frequency of Surveillance Requirements for instruments-listed in j Table 1 will not degrade the ability of the plant's process ] and area radiation monitors to perform their functions. Surveillance Requirements for the subject process and area radiation monitors verify the calibration of the radiation monitors to ensure operability and accuracy once per 18 months. NNECO proposes to extend the frequency of the channel calibration of these monitors to at least once each refueling (i.e., nominal 24 months). A review of the past surveillance results indicate that these monitors were

U. S. Nuclear Regulatory Commission .B15306/ Attachment 5/Page 40 July 26,.1995 calibrated to be within the. acceptance criteria and there was no linear. time dependent drift. regard to the radiation monitors. A review'of corrective maintenance records for these monitors indicates that there have been no operationally significant equipment failures for the previous four operating cycles. A Channel Check on a shift basis and an Analog Channel operation Test on a quarterly basis provide additional assurance of the operability of the containment. area purge and exhaust isolation valve radiation monitor (Table 4.3-3, Functional Unit 1.a). A Channel Check on monthly basis provides additional assurance of the operability of the Containment Area - High Range Radiation. Monitor (Table 4.3-7, Instrument 16). On the basis of the above evaluation, there is a reasonable assurance that the frequency of Surveillance Requirements for the process and area' radiation monitors can be extended from at least once per 18 months to at least 'once each refueling. A PRA review concluded that the change in risk due to this technical specification change is negligible. Significant Hazards Consideration NNECO has reviewed the proposed change in accordance with 10CFR50.92 and has concluded that the changes do not involve an SHC. The basis for this conclusion is that the three criteria of 10CFR50.92(c) are not compromised. The proposed changes do not involve an SHC because the changes would not: 1. Involve a significant increase in the. probability or consequences of an accident previously evaluated. The proposed changes to Surveillance Requirements (the channel calibration) of the process and' radiation monitors extend the frequency for demonstrating the operability of the process and area radiation monitors. The proposal would extend the frequency.- from at least once per 18 months to at least once each refueling interval (i.e., nominal 24 months). 1 The proposed changes do not alter the intent or method by which the surveillances are conducted. In addition, the acceptance criterion for each surveillance is unchanged. As such, the proposed changes. will not degrade the ability of the process and area radiation monitors to perform their function.

i ,-U. S. Nuclear Regulatory Commission 'B15306/ Attachment 5/Page'4l' July 26, 1995 1 An1 evaluation of the past surveillances, preventive maintenance records and the. frequency and type of-corrective maintenance concluded that decreasing the: s frequency will have:little. impact.on safety. A review of the past surveillance results indicates that these monitors were calibrated within the acceptance criteria ( and there was no linear time dependent drift regard _to the radiation monitors. Since the proposed' changes only affect the surveillance frequency, the proposed. changes can not affect the probability of any-previously analyzed accident. While, the proposed. changes can . lengthen-the interval between l surveillances, the increase in interval has been evaluated and it is concluded that there is-no significant impact on the availability of the radiation-monitors and consequently, there is no impact on the consequences of any analyzed accident.- 2. Create the possibility of 'a new or different kind of accident from any accident previously evaluated. The. proposed changes to Surveillance Requirements of the process and-. area radiation monitors do not modify the design or operation. of any plant system. In addition,.the proposed changes do not alter the intent or method by which the surveillance are conducted other i than increasing the interval from 18 months to 24 months (nominal). The proposed ~' changes do not introduce a new failure mode. Therefore, the proposed changes do not create the possibility of a new or different kind of ' accident from .any previously. analyzed. 1 l 3. Involve a significant reduction-in a margin of safety. 1 Changing the frequency of surveillance requirements for the process and area radiation monitor calibrations do. not change the basis for frequency. The proposed - changes do not alter the intent or method by which the surveillances are conducted, do not involve.any physical changes to the plant, do not alter the way any structure, system or component functions and ' do not modify the manner in which the plant is operated. Further, the previous history of the radiation monitors provides assurance that the changes will not affect the reliability of the radiation monitors. Thus the proposed changes have no impact on the margin of safety.

t-o. U.'S. Nuclear Regulatory Commission: - B15306/ Attachment 5/Page 42 July 26, 1995 VIII. Enrveiliance' Reauirements 4.2.3.1.4. 4.2.3.1.5. and '4.2.3.1.6. Reactor Coolant System (RCS) Flow Rate For 'Four Loon -Operation and Surveillance Resuirements

4. 2. 3. 2. 4. - 4. 2. 3. 2. 5 and 4.2.3.2.6.

RCs Flow Rate For ThKSS_Idt9JLQRSIA%19R 1 safety Assessment 4 Surveillance Requirements

4. 2. 3.1. 4. and. 4. 2. 3. 2. 4 require:

that the'RCS flow instrumentation be calibrated once per 18 i months. NNECO proposes to extend. the. frequency-of Surveillance Requirements 4.2.3.1.4 and

4. 2. 3. 2. 4 - from at least once.per 18 months lto at least once each refueling interval

.(i.e., 24 months). Surveillance Procedure 'SP 3442G01 is used to perform the calibration and Table 3 lists the flow instruments covered under Surveillance Requirements 4.2.3.1.4 and 4.2.3.2.4. Eight tests were performed during the last four operating cycles with one failure in 1987.- l The five RCS flow transmitters. (3RCS*FT416, 425, 434, -444,. 445) -failed and required replacement during the: latter part. of operating cycle one. These transmitters were Rosemount, 9 Model 1153HD5C. A loss of oil'in the sensor module caused the transmitter-to fail to function.- properly. The transmitters failed non conservatively and the-failures were discovered during normal plant operations. The flow transmitters provide a trip function via the reactor trip i system. If two out of any three transmitters sense low j flow, a trip signal is initiated. The failures occurred { sporadically such that.two transmitters never ' failed simultaneously. Therefore, there was no adverse effect-on ~ plant operation. Northeast - Utilities notified the NRC of l this condition under part 21. This Rosemount transmitter failure resulted in issuance of a bulletin by the NRC (IE l Bulletin 90-01). In response to the bulletin,- NU developed j an enhanced monitoring program for Rosemount transmitters 1 installed at Millstone Unit No. 3. The purpose of this -i l program is to_ identify symptoms of potential loss of fill-oil for all. safety.related Rosemount 1153 and 1154 transmitters at Millstone Unit No. 3. 'This program ensures t that the RCS flow transmitters are checked-periodically to detect any failure. A transmitter failure similar to the Rosemount issue could impact the surveillance interval. increase (i.e., up to 24 months' nominal) because an J instrument. failure would only. be detected -when the transmitter is calibrated. This.is not the case because an ) transmitter failure would. be detected either during the monthly RCS flow surveillances or by the Rosemount enhanced monitoring program. Therefore,. the risk of a flow transmitter failure being undetected is small and will not ] impact the increase in the surveillance interval. Also, the q

l U. S. Nuclear Regulatory Commission B15306/ Attachment S/Page 43 July 26, 1995 drift analysis for the RCS flow channels was incorporated into the overall RCS flow uncertainty and found to be within the bounds of trip setpoint analysis and the current safety analysis. Surveillance Requirements 4.2.3.1.5 and 4.2.3.1.6 require that the RCS flow be verified to be above the technical specification limit once per 18 months. NNECO proposes to extend the frequency of Surveillance Requirements 4.2.3.1.5 and 4.2.3.1.6 from at least once per 18 months to at least once each refueling (i.e., nominal 24 months). Surveillance Procedure SP 31004 determines the RCS flow using a secondary side heat balance, the reactor coolant pump heat, chemical and volume control system losses, and the RCS hot and cold leg enthalpy to determine the flow. The calculated RCS flow is compared to the technical specification limit. Table 3 listo the component (i.e., instruments) covered by SP 31004. The RCS flow calibration includes the determination of reactor power. The instruments include steam pressure, feedwater

pressure, feedwater temperature and feedwater flow.

The feedwater flow calorimetric uncertainty has been determined to be 1.8% for four loop operation and 2% for three loop operation. These values are below the design basis conditions of 1.9% for four loop operation and 2.1% for three loop operation. The total channel uncertainty for a 24 month nominal surveillance interval has been calculated to be 2.2% RCS flow for four loop operation and 2.5% for three loop operation. These values are lower than the design basis values of 2.4% for four loop operation and 2.8% for three loop operation as given in the Millstone Unit No. 3 Technical Specification Sections 3.2.3.1 and 3.2.3.2. Based upon the

above, the surveillance frequency of Surveillance Requirements 4.2.3.1.5 and 4.2.3.2.5 can be extended to at least ence each refueling interval (i.e.,

nominal 24 months). Surveillance Requirements 4.2.3.1.6 and 4.2.3.2.6 require that 0.1% error be added to the uncertainty on the RCS flow measurement if the feedwater venturis have not been inspected or cleaned. There is a provision in Surveillance Procedure SP 31004 to increase the technical specification RCS flow by 0.1% if the venturis are not inspected. NNECO proposes to extend the frequency of Surveillance Requirement 4.2.3.1.6 and 4.2.3.2.6 from once per 18 months to at least once each refueling (i.e., nominal 24 months). The feedwater venturies were cleaned in each of the last four refueling outages. However, tests that' were performed in all refueling outages, an additional 0.1% error was added to the RCS flow for conservatism and even with this additional error, all the tests passed the acceptance criteria. It is

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 44 July 26, 1995 NNECO's experience that the venturi fouling reaches a maximum after approximately two to three months of plant operation. In addition, during down powers, the venturies can defoul (i.e., clean themselves) from the temperature transient in the feedwater system. Therefore, the venturi fouling will not be a concern or issue if the surveillance interval is increased to 24 months (nominal). A PRA review evaluated the number of failures, the root causes of the

failures, and the subsequent corrective actions, and concluded that the increase in risk due to this technical specification change is negligible.

Bionificant Hazards consideration NNECO has reviewed the proposed changes in accordance with 10CFR50.92 and has concluded that the changes do not involve an SHC. The basis for this conclusion is that the three criteria of 10CFR50.92 (c) are not compromised. The proposed changes do not involve an SHC because the changes would not: 1. Involve a significant increase in the probability or consequences of an accident previously evaluated. The proposed changes to Surveillance Requirements 4.2.3.1.4, 4.2.3.2.4 (RCS flow rate indicators), 4.2.3.1.5, 4.2.3.2.5 (RCS total flow rate) and 4.2.3.1.6, 4.2,.3.2.6 (a penalty of 0.1% to the RCS flow) extend the frequency of the channel calibration of the RCS flow rate indicators, RCS flow rate determination by precision heat balance method and cleaning of the feedwater venturies at least once per 18 months. The proposal would extend the frequency from at least once per 18 months to at least once each refueling (i.e., nominal 24 months). The proposed changes do not alter the intent or method by which the surveillances are conducted. In addition, the acceptance criterion for each surveillance is unchanged. As such the proposed changes will not degrade ability of the RCS flow indicators to perform their function. The evaluation of the past surveillance results, and the enhanced surveillance program from Rosemount transmitters concluded that the decreasing frequency will have little impact on safety. A review of the past surveillance results indicate that these transmitters were calibrated within the acceptance criteria. There were some failures (i.e., Rosemount

1. 741

U.,S. Nuclear Regulatory Commission-i

-B15306/ Attachment 5/Page 45 ' July 26, 1995'. transmitters) during Cycle 1 operation. However, an enhanced surveillancs. program is in. place to. ensure that the RCS flow transmitters are checked ~ periodically to. detect any failures. The risk of an RCS a flow - transmitter failure being undetected is small and will' not impact the increase in the surveillance interval.. Also, the drift analysis for the RCS flow channels was incorporated into the overall'RCS flow uncertainty-and found to be within the bounds of the current safety analysis. The feedwater - calorimetric uncertainty and the total channel uncertainty were lower than the design basis values. The feedwater venturis.were and. will be cleaned during every refueling. outage. LBy cleaning the venturis, the additional 0.1% for fouling was not required to be invoked. However, during the past RCS flow measurement tests, an additional 0.1% error was added to the RCS flow measurement for conservatism and even with this-. additional error, all-the test measurements passed the acceptance criteria. Since the proposed changes only affect.the surveillance frequency, the proposed changes can not affect the probability of any previously analyzed accident. While the proposed changes can lengthen the intervals-between surveillances, the increase in intervals has been-evaluated and it is concluded that there-is.no significant impact on the availability or reliability. of the RCS flow indicators-and the RCS flow transmitters and consequently, there is no impact on' the consequences of any analyzed accident. 2. Create the possibility-of a new or different kind of. r;ccident from any accident previously evaluated. The. proposed changes ' do not modify. the. design or operation of any plant system. In addition, the proposed changes do not alter the intent or method by which the surveillances are conducted.- other than increasing the interval from 18 months to 24 months-(nominal). The proposed changes do not-introduce'a new failure mode. Therefore, the proposed changes do not create the possibility of a new-or different kind of accident from any previously analyzed. ' n.the margin of 3. Involve a significant reduction i safety. Changing the frequency of Surveillance Requirements 4.2.3.1.4, 4.2.3.1.5, 4.2.3.1.6 and 4.2.3.2.4, 4.2.3.2.5 and 4.2.3.2.6 from at least once per 18 months to once each refueling interval does not change.

I U. S. Nuclear Regulatory; Commission B15306/ Attachment 5/Page 46 July 26, 1995 the basis for frequency. The proposed changes do not-alter the intent or method by which the surveillances i are conducted, do not involve ~any physical. changes-to the plant, do not alter the way any structure, system or componentifunctions and do not modify the manner in + which the plant is operated. Further, the enhanced monitoring program in place for detecting any failure of-Rosemount transmitters, provides assurance the changes will not offect the reliability of the RCS flow transmitters.

Thus, the proposed changes have no impact on the margin of safety, j

l i [ l N t i t t r b i i I [

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 47 July 26, 1995 Table 1 Trip Actuating Devices Operation Test Item Description Table 4.3-1, Functional Unit 1 Manual Reactor Trip r Table 4.3-1, Functional Unit 16 Safety Injection Input from ESF Table 4.3-1, Functional Unit 20 Three Loop operation Bypass Circuitry Table 4.3-1, Functional Unit 21 Reactor Trip Bypass Breaker Table 4.3-2, Functional Unit 1.a Safety Injection - Manual Initiation Table 4.3-2, Functional Unit 2.a Containment Spray - Manual Initiation Table 4.3-2, Functional Unit 3.a.1 Containment Isolation - Phase A'- Manual Initiation Table 4.3-2, Functional Unit 3.b.1 Containment Isolation - Phase B - Manual Initiation Table 4.3-2, Functional Unit 4.a Steam Line Insolation - Manual Initiation Table 4.3-2, Functional Unit 5.c Turbine Trip and Feedwater Isolation - Safety Injection Actuation Logic Table 4.3-2, Functional Unit 6.a Auxiliary Feedwater - Manual Initiation Table 4.3-2, Functional Unit 7.a Control Building Isolation - Manual j Actuation Table 4.3-2, Functional Unit 7.b Control Building Isolation - Manual Safety i Injection Actuation l Table 4.3-2, Functional Unit 9.c ESFAS Interlocks - Reactor Trip, P-4 Channel Calibration Table 4.3-6, Instrument 13 Emergency Bus Voltmeter Analog Channel Operational Test Table 4.3-1, Functional Unit 17 Reactor Trip System Interlocks

U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 48 July 26, 1995 Table 2 Test Intervals are in Months Present New Number of Present Interval New Interval Function Channels Interval Plus 25% Interval Plus 25% OTDT/OPDT 4 72 90 48 60 RTDs only OPDT/OPDT 4 72 90 96 120 Procese and Logic PRESSURIEER PRESSURE 4 72 90 96 120 RX TRIP S/G LEVEL 4 72 90 96 120 LOW LOW NI POWER 4 72 90 96 120 HIGH NI POWER 4 72 90 96 120 NEG RATE RCP LOW SPEED 4 72 90 96 120 RCS LOW FLOW 3 54 67.5 96 120 PRESSURIZER LEVEL 3 54 67.5 96 120 HIGH PRESSURIEER PRESSURE 4 72 90 96 120 LOW SI STEAMLINE PRESSURE 3 54 67.5 96 120 LOW SI STEAMLINE PRESSURE 3 54 67.5 96 120 NEG RATE CNMT PRESS HIGH 1 3 54 67.5 96 120 CNMT PRESS HIGH 2 3 54 67.5 96 120 CNMT PRESS HIGH 3 4 72 90 96 120 S/G WATER LEVEL 3 54 67.5 96 120 HI HI FWI WITH LOW T AVG 4 72 90 96 120 LOSS OF POWER 4 72 90 96 120 SOLID STATE PROTECT!ON SYSTEM 2 36 45 48 LOGIC 60

U. S. Nuclear. Regulatory Commission. B15306/ Attachment 5/Page 49 . July-26,.1995 j . Table 2 Test. Intervals are in Months (cont'd.) t i i Present New. i Number of Present ' Interval' New Interval i Punction Channels Interval 'Plus 25% Interval Plus'25% ~! i R MIP 2 36 45 48 _PREAKERS 60 { t SEQUENCER 2 36 45 ~48 60 l DIESEL GENERATORS 2 36 45 48 60 l 'I BI EQUIPMENT 2 36 45 48 (pumps valves) 60 t i i s I 'I i l i } i l i i I f 1

a U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 50 July 26, 1995 TABLE 3-f REACTOR COOLANT SYSTEM FLOWRATE INSTRUMENTATION EQUIPMENT DESCRIPTION 3RCS*F414 Loop 1 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F415 Loop 1 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F416 Loop 1 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F424 Loop 2 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F425 Loop 2 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F426 Loop 2 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F434 Loop 3 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F435 Loop 3 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F436 Loop 3 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F444 Loop 4 Reactor Coolant Elbow Tap Flow Measurement l 3RCS*F445 Loop 4 Reactor Coolant Elbow Tap Flow Measurement 3RCS*F446 Loop 4 Reactor Coolant Elbow Tap Flow Measurement 1

j l U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 51 July 26, 1995 TABLE 3 CALORIMETRIC INSTRUMENTATION LIST l EQUIPMENT DESCRIPTION 3 MSS-P514 "A" Steam Pressure 3 MSS-P515 "A" Steam Pressure 3 MSS-P516 "A" Steam Pressure 3 MSS-P524 "B" Steam Pressure 3 MSS-P525 "B" Steam Pressure 3 MSS-P526 "B" Steam Pressure 3 MSS-P534 "C" Steam Pressure 3 MSS-P535 "C" Steam Pressure 3 MSS-P536 "C" Steam Pressure 3 MSS-P544 "D" Steam Pressure 3 MSS-P545 "D" Steam Pressure 3 MSS-P546 "D" Steam Pressure 3FWS-T40A "A" Feedwater Temperature 3FWS-T40B "B" Feedwater Temperature 3FWS-T40C "C" Feedwater Temperature 3FWS-T40D "D" Feedwater Temperature l 1

i i i U. S. Nuclear Regulatory Commission B15306/ Attachment 5/Page 52 July 26, 1995 TABLE 3 CALORIMETRIC INSTRUMENTATION LIST (cont'd.) EQUIPMENT DESCRIPTION 3FWS-P37A "A" Feedwater Pressure 3FWS-P37B "B" Feedwater Pressure I 3FWS-P37C "C" Feedwater Pressure 3FWS-P37D "D" Feedwater Pressure 3FWS-F510 "A" Feedwater Flow 3FWS-F511 "A" Feedwater Flow 3FWS-F520 "B" Feedwater Flow 3FWS-F521 "B" Feedwater Flow 3FWS-F530 "C" Feedwater Flow i 3FWS-F531 "C" Feedwater Flow 3FWS-F540 "D" Feedwater Flow 3FWS-F541 "D" Feedwater Flow

Figure 1 Millstone Unit No.3 A Typicallnstrument Loop j PROCESS PARAMETERS FLOW TEMP PRESSURE ETC. j u RESULTANT ] EQUIPMENT SENSOR ACTION = = it?sWEin? h i i f l l 1 7300 l CABINET i PROTECTION SET RELAY l l l l l i i ! CONTROL ! POWER SOLID a EMERGENCY STATE d DIESEL EMERGENCY PROTECTION [ GENERATOR DIESEL i --+ SYSTEM LOADING GENERATOR LOGIC d ~~l SEQUENCER l ^ l l l REACTOR l TRIP --a BREAKER 1

7 ' U. 8. Nuclear Regulatory Commission B15306/ Attachment 5/Page 53 July 26, 1995-

REFERENCES:

1. NRC Generic Letter 91-04, Enclosure 2, " Guidance for Addressing the Effects of Increased Surveillance Intervals on Instrument Drift and Safety Analysis Assumption", April 2, 1991. 2. Westinghouse Setpoint Methodology for RPS/ESFAS System WCAP 10991 Rev. 4. May 1995. 3. ' Instrumentation Calibration and Drift Evaluation Process for Millstone Unit 3 Fuel Cycle Extension to 24 Months. Westinghouse Report No. WCAP 14354, May 1995. 4. Westinghouse Setpoint Methodology for Indication,

control, and Protection System for Millstone Unit 3 -WCAP 14353, May 1995.

5. Millstone Unit No. Monitorin, Technical Evaluation No PA 93-036-EE-048 for 3 Accident g Instrumentation and Remote Shutdown Instrumentation - PA 93-036-EE-46e. l l l I i .}}

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