ML17339A049

Proposed Tech Specs,Reflecting Installation of Time Delay Circuit in Auxiliary Feedwater Actuation Sys

ML17339A049
Person / Time
Site:	Saint Lucie
Issue date:	10/17/1986
From:	FLORIDA POWER & LIGHT CO.
To:
Shared Package
ML17216A739	List: L-86-360, Application for Amend to License NPF-16,revising Tech Specs to Reflect Installation of Time Delay Circuit in Auxiliary Feedwater Actuation Sys.Fee Paid ML17339A049
References
NUDOCS 8610270368
Download: ML17339A049 (36)

Text

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FUNCTIONAL UNIT TOTAL NO.

OF CHANNELS CHANNELS TO TRIP HININH CHANNELS OPERABLE APPLICABLE NODES 7.

LOSS OF POWER (LOV) a.

(1) 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) 1/Bus (2) 480 V Emergency Bus Undervoltage (Loss of Voltage) 2/Bus b.

(1) 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) 3/Bus 2/Bus (2) 480 V Emergency Bus Undervoltage (Degraded Voltage) 3/Bus 2/Bus AUXILIARYFEEOWATER (AFAS~~~

a.

Manual (Trip Buttons) 4/SG 2/SG 1/Bus 2/Bus 1/Bus 2/Bus 2/Bus 2/Bus 4/SG 1

2 3

1>>

2>> 3 1, 2, 3

1, 2, 3 1, 2, 3

TABLE 3.3"3 Continued ENGINEERED SAFETY FEATURES ACTUATION SYSTEH INSTRlNENTATION ACTION 17 17 15 b.

Automatic Actuation Logic 4/SG 2/SG 3/SG 1, 2, 3 12 SG 2A -

SG 2B Differential Pressure 4/SG C.~

SG Level (2A/2B) - Low 4/SG 2/SG 2/SG 3/SG 3/SG 1, 2, 3 1, 2, 3

13" 14 13" 14 Feedwater Header SG 2A -

SG 2B Oif" ferential Pressure 4/SG 2/SG 3/SG 1, 2, 3

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TABLE 3.3-3 Continued TABLE NOTATION (a)

Trip function may be bypassed in this MODE when pressurizer pressure is less than 1836 psia; bypass shall be automatically removed when pressurizer pressure is greater than or equal to 1836 psia.

(b)

An SIAS signal is first necessary to enable CSAS logic.

(c)

Trip function may be bypassed in this MODE below 700 psia; bypass shall be automatically removed at or above 700 psia.

The provisions of Specification 3.0.4 are not applicable.

ACTION STATEMENTS ACTION 12-ACTION 13-With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

With the number of channels OPERABLE one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may continue provided the inoperable ch'annel is placed in the bypassed or tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

If the inoperable channel is

bypassed, the desirability of maintaining this channel in the bypassed condition shall be reviewed in accordance with Specification 6.5. 1.6m.

The channel shall be returned to OPERABLE status no later than during the next COLO SHUTDOWN.

With a channel process measurement circuit that affects multiple functional units inoperable or in test, bypass or trip all associated functional units as listed below.

Process Measurement Circuit Functional Unit Bypassed 1.

Containment Pressure

- High Containment Pressure

- High (SIAS,

CIAS, CSAS)

Containment Pressure

- High (RPS) 2.

Steam Generator-Pressure-Low 3.

Steam Generator Level 4.

Pressurizer Pressure Steam Generator Pressure - Low (MSIS)

Steam Generator hP 1 and 2 (AFAS)

Thermal Margin/Low Pressure (RPS)

Steam Generato~

Level - Low (AFAS,

+t m+e r'a+r eel lt,H h Ql Pressurizer Pressure - High (RPS)

Pressurizer Pressure - Low (SIAS)

Thermal Margin/Low Pressure (RPS)

ST.

LUCIE - UNIT 2 3/4 3-15

TABLE 3.3-3 Continued TABLE NOTATION ACTION 14-With the number of channels OPERABLE one less than the Minimum Channels

OPERABLE, STARTUP and/or POWER OPERATION may continue provided the following conditions are satisfied:

Verify that one af the inoperable channels has been bypassed and place the other inoperable channel in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />; b.

All functional units affected by the bypassed/tripped channel shall also be placed in the bypassed/tripped condition as listed below.

g~i)

Process Measurement Circuit Functional Unit Bypassed/Tripped 1.

Containment Pressure Circuit Containment Pressure - High (SIAS,

'IAS, CSAS)

Containment Pressure - High (RPS) 2.

Steam Generator Pressure-Pgfch 3.

Steam Generator Level - Low 4.

Pressurizer Pressure team Generator Pressure - Low

(

IS) team Generator hP 1 and 2 (AFAS)

Thermal Margin/Low Pressure (RPS)

Steam Generator Level - Low (RPS)

AF ehg ne+toh,Lhel ~Hi++

Pressurizer Pressure

- High (RPS)

Pressurizer Pressure Low (SIAS)

Thermal Margin/Low Pressure (RPS)

ACTION 15-ACTION 16-ACTION 17-With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable channels to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in HOT SHUTDOWN within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

With the number of OPERABLE channels one less than the Total Number of Channels, restore the inoperable char el to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or declare the associated valve inoperable and take the ACTION required by Specification 3.7. l. 5.

With the number of OPERABLE Channels one less than the Total'umber of Channels, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or place the inoperable channel in the tripped condition and verify that the Minimum Channels OPERABLE requirement is demonstrated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />; one additional channel may be bypassed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for surveillance testing per Specification 4.3.2.1.

ST.

LUCIE - UNIT 2 3/4 3-16

TABLE 3. 3-4 Continued ENGINEERED SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION TRIP VALUES 6.

c.

Automatic Actuation Logic LOSS OF POWER a.

(1) 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)

(2) 480 V Emergency Bus Undervoltage (Loss of Voltage) b.

(1) 4. 16 kV Emergency Bus Undervoltage (Degraded Voltage)

FUNCTIONAL UNIT 5.

CONTAINMENT SUMP RECIRCULATION (RAS) a.

Manual RAS (Trip Buttons) b.

Refueling Water Storage Tank - Low TRIP VALUE Hot Applicable 5.67 feet above tank bottom Not Applicable

> 3120 volts

> 360 volts

> 3848 volts with a 10-second time delay

~

ALLOWABLE VALUES Not Applicable 4.62 feet to 6.24 feet above tank bottom Not Applicable

> 3120 volts

> 360 volts

> 3848 volts with a 10-second time delay 7.

(2) 480 V Emergency Bus Undervoltage (Degraded Voltage)

AUXILIARYFEEDWATER (AFAS) a.

Manual (Trip Buttons) b.

Automatic Actuation Logic

> 432 volts Hot Applicable

. Not Applicable

> 432 volts Hot Applicable Hot Applicable Xc. QSt~m er or

-Hi+

Q. )I(,

SG 2M2B Level Low

+e.

Fe at He~er ~h h 8.

AUXILIARYFEEOWATER ISOLATION a.

Steam Generator aP-High b.

Feedwater Header

~P "igh

<18 Op d

> 20.6X

<+00. 0 fd

<275 psid

<150.0 psid 7.5

> 20.0X

< ~7.5 ~id Q.g $~ 2'si4 g1.0 ~ (S7.%ps/i pe+

WINCH pgy JAIL g~ pupWaRl v~m~

TABLE 3. 3-5 Continued ENGINEEREG SAFETY FEATURES

RESPONSE

TIMES INITIATING SIGNAL AND FUNCTION 10.

Steam Generator Level-Low Au)(l 1 iary Feedwater b.

F dwater 0 1 atib ll.

F Water eader a.

Auxili ry Fee ater b.

edwate Isolat'on 12.

earn Ge rator a.'uxil ry Fe ater edwat r Isol tion

RESPONSE

TIME IN SECONOS ggyg~/ e y~ IllsV~Ig

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or-Ori n and team-0 ven ilia Feedw er Pum o

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1

.0 bC~Fie TASLE NOTATION loading delays included.

Response

and attainment of pump or blower loading delays not included.

Offsite ncludes movement of valves and pressure.

applicable to the valves specified Diesel generator starting and sequence time limit includes movement of valves discharge pressure.

Diesel generator star ting and sequence power available.

Response ties limit f attainment of pump or blower discharge Containment Isolation response time is in Soecification 3.6.3.

ST.

LUCIE - UNIT 2 3/i 3-21 Amendment No.

TABLE 4.3.-2 Continued ENGINEEREO SAFETY FEATURES ACTUATION SYSTEM INSTRUMENTATION SURVEILLANCE RE UIREHENTS C

M m

C:

4Pa I

hD tA FUNCTIONAL UNIT 6.

LOSS OF POWER (LOV) a.

4. 16 kV and 480 V Emergency Bus Undervoltage (Loss of Voltage) b.

4. 16 kV and 480 V Emergency Bus Undervoltage (Oegraded Voltage) 7.

, AUXILIARYFEEOWATER (AFAS) a u

b.

evel nd ess e (A

)

n P

Hi SG e

o a d No s

e-

)

-Automatic c ua )on Log>c CHANNEL CHECK N.A.

S N.A.

CHANNEL CALIBRATION N.A.

R N.A.

CHANNEL FUNCTIONAL TEST R

H(1), SA(2)

HOOES FOR WHICH SURVEILLANCE'ttl ED 1, 2, 3, 4 1, 2, 3, 4 1, 2, 3 1, 2, 3 TABLE NOTATION (1)

Testing of Automatic Actuation Logic shall include energization/de-energization of each initiation re'lay (solid-state component) and verification of the OPERABILITY of each initiation relay (solid-state component).

(2)

A subgroup relay test shall be performed which shall include the energization/de-energization of each subgroup relay (solid-state component) and verification of the OPERABILITY of each subgroup relay (solid-state component).

8.

AUXILIARYFEEDMATER ISOLATION a.

.SG Level (A/B) - Low and

~

SG Differential Pressure (BtoA/AtoB) - High b.

SG Level (A/B) - Low and Feedwater Header Differential Pressure (BtoA/AtoB) - High N.A.

N.A.

1,2,3 1,2,3

ATTACHMENT2 SAFETY EVALUATION Introduction A change is proposed to revise Technical Specification 3/4.3.2, Engineered Safety Features Actuation System (ESFAS) Instrumentation for St. Lucie Unit 2.

This change is needed to support the installation of a time delay circuit in the St. Lucie Unit 2 AuxiliaryFeedwater Actuation System.

Discussion A time delay in the St. Lucie Unit 2 Auxiliary Feedwater Actuation System (AFAS) circuitry would provide additional time for the operators to assess the plant conditions and take positive control of the Auxiliary Feedwater (AFW) system following a reactor-turbine trip.

This time delay period allows the operators to perform the immediate post-trip actions without the AFW system actuating shortly after the trip. Full actuation of the AFW system under certain scenarios could lead to overcooling of the Reactor Coolant System (RCS) unless the AFW flow is manually throttled by the control room operators.

The presently installed AFW system for St. Lucie Unit 2 includes automatic actuation of auxiliary feedwater on low steam generator level.

The proposed change to the St. Lucie Unit 2 AFW system adds an adjustable time delay to the St. Lucie Unit 2 AFAS to'make it operationally similar to the AFAS for St. Lucie Unit I.

The time delay incorporated into the AFAS circuitry provides additional time for the operators to assess the post-trip plant condition without the concern of the automatic actuation of the AFW system within seconds of the trip.

Thus, the addition of the AFAS time delay allows the operator to perform the normal post-trip actions, and then take manual control of the AFW system to throttle flow and provide a controlled recovery of steam generator level without overcooling the RCS.

The primary function of the AFAS time delay is to reduce challenges to the AFW system under the condition of a plant trip with offsite power and main feedwater available.

Under these conditions, if steam generator level recovers prior to the expiration of the time delay, the AFW system will not be actuated.

The proposed license amendment addresses those Technical Specifications (see Attachment I) needed to support the installation of a time delay circuit in the St.

Lucie Unit 2 AFAS.

The proposed change revises Table 3.3-5 (Engineered Safety Features

Response

Times) to reflect the addition of an AFAS time delay.

In addition, editorial changes have been made to the following tables to make them consistent with the St. Lucie Unit I AFW system Technical Specifications which were approved by the NRC in Amendment No. 72 to Facility Operating License No. DPR-67: Table 3.3-3 (ESFAS Instrumentation),

Table 3.3-4 (ESFAS Instrumentation Trip Values), and Table 4.3-2 (ESFAS Instrumentation Surveillance Requirements).

The proposed change revises Table 3.3-3 (Engineered Safety Features Actuation System Instrumentation) to be consistent with the St. Lucie Unit I table.

The +"

footnote to item 7 has been

deleted, as the AFW automatic initiation system installation was completed during the construction and startup of St. Lucie Unit EJWI/00I/4

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Item 7.d. has been renumbered as item 7.c.

A new item 8, entitled Auxiliary Feedwater Isolation, has been added, with the old items 7.c. and 7.e. relocated as the new items 8.a.

and 8.b., respectively.

This change was made as the AFW system, can only be actuated automatically (on low steam generator level) or manually.

Auxiliary feedwater isolation to a faulted steam generator is actuated when the AFAS logic circuit detects either a high steam generator differential pressure or a high feedwater header differential pressure signal in conjunction with the appropriate low steam generator level signal.

Channel requirements of the AFAS are unaffected.

Action l3, item 3, of Table 3.3-3 has been revised to remove the AFAS on high steam generator level. Action l4, item 2, of Table 3.3-3 has been revised to remove the AFAS on low steam generator pressure.

Action l4, item 3, of Table 3.3-3 has been revised to remove the AFAS on high steam generator level.

These three changes are made to remove information which does not reflect the operation of the AFAS.

The proposed change revises Table 3.3-4 (Engineered Safety Features Actuation System Instrumentation Trip Values) to also be consistent with the St. Lucie Unit I table.

Item 7.d. has been renumbered as item 7.c.

A new item 8,,entitled Auxiliary Feedwater Isolation, has been added, with the old items 7.c. and 7.e.

relocated as the new items 8.a. and 8.b., respectively.

The reason for this change is the same as that given above for the change to Table 3.3-3.

The setpoints for items 8.a. and 8.b. have been established at the same values as for St. Lucie Unit I, for consistency between units.

The increase in these trip values has been evaluated and it has been determined that analysis conclusions utilizing these setpoints as inputs remain unaffected.

A minimum allowable value has been added to items 8.a. and 8.b. to ensure that the signal actuates to the correct train.

The proposed change to Table 3.3-5 (Engineered Safety Features

Response

Times) modifies item IO.a., response time for auxiliary feedwater actuation on steam generator level-low, to include an AFAS time delay.

The new values for the AFW system response time have been established to meet the present accident analysis assumptions.

Item IO.b. of Table 3.3-5 (Feedwater Isolation on Steam Generator Level-Low) has been deleted for the following reasons.

The fast closure safety function of the main feedwater isolation valves is to close on a Main Steam Isolation Signal (MSIS) for Steam Line Break considerations.

This response time requirement for the main feedwater isolation valves is presently reflected and tested in Items 3.e.

and 6.a. of Technical Specification Table 3.3-5.

For AFW

concerns, main feedwater isolation occurs only to prevent backflow of AFW into the main feedwater system (note that St. Lucie Unit I has check valves which prevent backflow of AFW). An Auxiliary Feedwater Actuation Signal is the actual initiating signal for feedwater isolation in this case.

However, the integrated response time test for the AFW system (Item IO.a. of Table 3.3-5) ensures that feedwater isolation occurs before the total AFW system response time expires.

Verification of this functions ensures that the AFW system operates as modeled in present safety analyses.

Old items I I and l2 have been deleted, as the functions listed (auxiliary feedwater and feedwater isolation) are not actuated on feedwater header or steam generator differential pressure.

The NOTE following old Item l2 has been deleted as it is redundant with the AFW system response time indicated in Item IO.a. and the table notation at the bottom of the page.

The proposed change revises Table 4.3-2 (Engineered Safety Features Actuation System Instrumentation Surveillance Requirements) to be consistent with the St.

Lucie Unit I table.

Item 7.b. has been deleted as these parameters do not actuate AFAS.

Item 7.c.

and 7.d.

have been renumbered as items 7.b.

and 7.c.,

respectively.

The new item 7.b.

has been revised to include only the steam generator low level signal for AFAS actuation.

A new item 8, Auxiliary EJW I /00 I /5

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Feedwater Isolation, has been added to be consistent with the information presented in Tables 3.3-3 and 3.3-4, and to reflect the actual operation of the AFAS. The AFW system surveillance requirments are unaffected.

Evaluation Two classes of events, increased heat removal and decreased heat removal, were evaluated to determine the effect of the time delay.

Increased Heat Removal Events The St. Lucie Unit 2 Cycle 2 Stretch Power Reload Safety Evaluation (RSE) Steam Line Break (SLB) events have been reanalyzed.

This reanalysis was performed to consider the most bounding assumptions concerning the AFW system and to add additional conservatism which would preclude any future reanalysis efforts.

Both the Hot Full Power and the Hot Zero Power SLB events are bounding for the current cycle (Cycle 3).

Both the Hot Full Power and the Hot Zero Power SLB

events, included as Attachment 3, are submitted as the new reference analyses and supersede those included in the Cycle 2 RSE.

These revised SLB analyses have been verified as bounding for the current cycle (Cycle 3).

Although this reanalysis yields results (peak reactivity, post-trip return to power, and minimum DNBR) slightly less conservative than those previously evaluated in the Cycle 3 RSE, they are still well within the previously established acceptance criteria.

Also, the most limiting peak containment pressure SLB event contained with the Cycle 2

RSE was reevaluated to verify that the peak containment pressure did not exceed the design limit with the addition of the AFAS time delay.

Based on this reevaluation, it is concluded that the results and conclusions reached in the Cycle 2 limiting containment pressure analysis are valid and the peak containment pressure is less than the 44 psig design limit.

Thus, it is concluded that operation of the AFW system within the response time requirements proposed in Item 10.a. of Table 3.3-5 will not impact the bounding increased heat removal and containment pressure events that have been established for Cycle 3.

Decreased Heat Removal Events The loss of feedwater, loss of condenser

vacuum, and feedwater line breaks presented in the Cycle 2 Stretch Power RSE were evaluated to determine the effect of the AFAS time delay.

Peak RCS pressure occurs during the first few seconds following reactor trip for these events, and it is not affected by the AFAS time delay.

However, the criteria for these events with the time delay was established to prevent the pressurizer from filling water solid as a result of the RCS heatup.

The feedwater line break is limiting for 'this criteria and has been used to establish the maximum allowable time delay of seven minutes total from the time the AFAS setpoint on low steam generator level is reached until the time AFW must be delivered to the steam generators.

(Note that the feedwater line break analysis, submitted to the NRC via L-85-474, dated December 30, l985, to support a Moderator Temperature Coefficient (MTC) Technical Specification

change, also assumes a 7 minute time delay for AFW delivery.)

The maximum AFW system response time of 305 seconds is determined by subtracting fill time for the affected feedwater piping (90 seconds) and instrument errors (25 seconds) from this seven minute limit. Based on this evalution, the events presented in the Cycle 2 Stretch Power RSE for St. Lucie Unit 2 are bounding for Cycle 3 when the AFW System is operated within the response time requirements proposed in Item I O.a. of Table 3.3-5.

EJW I /00 I /6

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ATTACHMENT 3 STEAM LINE BREAK EVENT REANALYSES EJW I /00 I /7

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3.2.I.5c STEAN SYSTEM PIPING FAILURE POST-TRIP ANALYSIS Identf ficatfon of Causes The Hot Full Power (HFP) and Hot Zero Power (HZP) Steam Line Break (SLB) Events were re-analyzed to show that the critical heat fluxes are not exceeded during this event when no delay time fs present for main

~ fecdwater rampdown 'nd auxf l 1 ary feedwater dcl 1 very.

A break fn thc main steam system piping.increases the rate of heat extraction by thc steam generators and causes a

cooldown of the Reactor Coolant System (RCS).

In the presence of e negative moderator temperature coefficient, this cooldown.produces a positive rcact1vfty addit1on.

For breaks located between the steam generators and the Nafn steam fsolatfon valve, the blowdown of the affected stcam generator cont1nues even after main steam fsolat1on.

Steam flow from the intact steam generator fs terminated with the closure of one of the two steam isolation valves.

3.2.1.5c.2 Anal sfs of Effects and Conse uences The HFP SLB fs initiated from the conditions listed fn Table 3.2.1.5c-1.

The following consideratfons were also included (applicable to both the HFP and HZP cases):

a)

The largest possible steam line break sfze (6.358 ft ) fs assumed, as it 2

results in the maximum post-trip R-T-P and

thus, the mfnfmum post-trfp ONBR.

This occurs because the largest break size causes the greatest temperature reduction

and, therefore, inserts the greatest magnitude of positive react1vity due to moderator and fuel reactivity feedback.

b)

The cooldown following a steam line break results in contraction of the reactor coolant.

For this analysis, if the pressurizer

empties, the reactor coolant pressure fs set equal to the saturation pressure corresponding to the highest temperature fn the reactor coolant system.

c)

A safety injection actuation signal (SIAS) fs actuated when the pressurfzer pressure drops below the SIAS setpo1nt.

Maximum time delays associated with the safety fn)ection pump acceleration, valve opening, and flushing of the unborated safety fn5ectfon lines were assumed.

d)

The cooldown of the RCS 1s terminated when the affected steam generator blows dry.

As the coolant temperatures begin increasing, positive react1vfty insertion from moderator reactivity feedback

'decreases.

The decrease 1n moderator reactivity combined with the negative reactivity inserted vfa boron fnjectfon causes the total react1vity to become negative.

c)

The rampdown of the main feedwater flow fs fnftfated at the time of reactor trfp.

f)

The delivery of auxiliary fcedwater flow fs assumed to occur famedfately (f.e., wfth no delay time) at the time of trip.

This fs more conservative than wafting for the level fn the affected steam generator to drop below the maximum auxiliary fcedwater actuation setpofnt.

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'hc Noderator Temperature Coefficient

{NTC) of reactivity assumed fn the anal sfs corresponds to the most negative allowable value fn the Tcchnical S eciffcatfons.

This negatfve NC results fn the greatest positive reactivity fon durfn the RCS cooldown caused by the steam lfne break.

Since thc n e associated

<<rith rroderator feedback varies significantly over the moderator density cover n

e ana th analysis a curve of r'oactfvfty fnsertion versus dens tp'a er an ft th than a single value of NC fs assumed fn thc analys s.

The Ioderator cooldown curve used fn the analysis was conser y

vatfvel calculated assuming that on reactor tr1p, the highest worth control clement assembly fs stuck fn the fully <<rfthdrawn posftfon.

The reactivity defect associated with fuel temperature decrease fs also based on a

most negative Fuel Temperature Coefficient

{FTC).

This

FTC, fn fth thc decreasing fuel temperatures, causes the greatest positive reactivity insertion during the steam line br'eak event.

The unce ta y

FTC assumed fn the analysis fs given fn Table 3.2.15c-1.

The 8 fraction assumed fs the maximum absolute value including uncertainties for cnd-of-life This fs also conservative since ft maximizes subcrftfcal aultfplfcatfon and thus, enhances the potential for Return-to-Power

( - - ).

R-T-P.

Th f i CEA <<rorth assumed to be available for shutdown at the tfme of e

m n mum

<<r reactor trip at the maximum allowed power level fs

-7.6%dp.

This available scram worth corresponds with the moderator cooldown curve and.stuck rod.worth used fn the analysis.

The analysfs assumed that on a safety injection,actuatfon signal one high pressure safety fn)ection pump fails to start.

A maximum HFt inverse boron worth of 95 ppm/Xgp was conservatively assumed for safety infection.'or the HFP case, a low steam generator pressure rea=tor trip setpoin

.t of 510 psia was assume n

o er d f rder to generate the earliest trip time.

The time of loss of offsfte power was assumed to be simultaneous with the main ste am isolation sfgnal (HSIS).

These assumptions result in the coastdown of the main feedwater pumps concurrent

<<rfth the maf n fcedwater fsol ation val ve cl osure.

The combination of an earlfer trip time and delayed feedwater isolation results fn the maximum cooldown of the RCS.

Auxflfary feedwater (AFM) flow fs assumed to enter the steam generators as soon as the reactor trips.

The steam driven and both motor driven pumps are conser va ve y assume ti 1

ssumed to provide auxiliary fcedwater at their maximum flow to the ra es.

t The steam driven and one motor drfvcn pump provides 1280 gpm affected steam generator, while the other motor driven pump provides gp AFM to the unaffected steam generator.

This situation fs assumed to persist until the AFAS fsolatfon logic identifies the affected steam generator and isolates AFM to ft, based on a high steam generator differential pressure of 530 psfd, fn con)unction with a low level indication.

The HZP case was initiated at the conditfons given fn Table 3.2.).5c-).

The cooldown curve corresponds to the most negative allowable MTC.

The most negative FTC was also used for reasons previously discussed.

Th i f CEA sh tdown <<orth available is conservatively assumed to be the minimum required Technical Specification lfmit of -5.0%hp.

The ana y e

m n mum u

1 sfs also assumed that; on safety fn)ectfon actuation

signal, one high pressure safety fn)ection pump fails to start.

A maximum HZP inverse boron worth was assumed for the safety fn)ectfon during the HZP case.

When all CEA's are verified to be fully inserted (durfng modes 3 and i) ~ it is not necessary to assume a

t assume a

CEA fs stuck in the fully withdrawn pasftfon when cal cul atfng shutdown marfLfn.

For the HZP case, a low steam generatoj.

pressure trip setpoint of 510 psia was assumed.

Loss of Offsite power was assumed to be simultaneous with the steam line break.

These assumptions lead to the lowest core flow. at the tfme of return to power and results

$ n a lower calculated.

DNBR.

Results HPP Case Table 3.2.1.5c-2 presents the sequence of events for the Hpp 'case tntttated from the conditions given fn Table 3.2.1.5c-l.

The response of the NSSS for

power, heat flux, RCS temperature, RCS pressure, steam generator pressure and reactivity are given fn Figures 3.2.1.5c-1 through 3.2.1.5c-6.

The peak reactivity attained during the transient fs +.041% Dpi A peak post-trfp power of 11.8% is produced.

The minimum ONBR during the transfent does not violate the 1.3 lfmit.

Figures 3.2.1.5c-3 and 3.2.1.5c-6 together show how the continued productfon of decay heat from the fuel after termination of

blowdown, causes the reactor coolant temperatures to increase.

This fn turn reduces the atagnftude of the positive moderator reactivity inserted and thus the total reactivity at the end

.of the event fs becomfng increasingly more negative.

HZP Case Table 3.2.1.5c-3 pr esents the sequence of events for the HZP case initiated from the conditions given fn Table 3.2.1.5c-1.

The response of the NSSS for

power, heat flux, RCS temperature, RCS pressure, steam generator pressure and r'eactfvity is given fn Figures 3.2.1.5c-7 through 3.2.1.5c-)2.

The affected steam generator does not blow dry since AFM fs not isolated.

The peak reactivity attained during the transient fs +.31%ho and the maximum return-to-power fs 5.3%.

The minimum DNBR during the transient does not violate the 1.3 lfmft.

Like the HFP case, at the end of the event the total reactivity fs becoming increasing more negative.

Note that for the HZP

case, AFAS isolation does not occur since the differential pressure between the steam generators does not exceed 530 psid.

Conclusions The HFP and HZP Steam Line Rupture Event analyses with no time delay for main feedwater rampdown and AFM delivery, includfng the assumed loss of offsite

power, show that the core does not reach critical heat fluxes.

e

(~ l

~'ABLE 3.2 ~ 1.5c-1 XEV PARAMETERS ASSU%0 FOR THE STEAS LINE BREA< EVENT Parameter 4 Unfts Total RCS Power, %t (Core Thermal Power +

Pump Heat)

Inftfal Cor e Cool ant Inlet Temperature, oF Inftfal RCS Vessel Flow Rate, GPM Inftfal Reactor Coolant System. Prcssure Doppler Coefffcfent lhltfplfer Moderator Temperature Coefffcfent, 10 zp/

F CEA cnorth at Trfp, %gp Inverse Boron @orth, ppm/%lno Full Power 2774 552 363,000 2410 1'5

-2.7

-7.6 95 Zero Power 540

. 363,000 2410 1.15

-2.7

-5.0 90

TABLE 3.2.1.5c-2 SE UENCE OF EVENTS FOR THE STEAN LINE BREAK EVENT AT ULL M

N N

N N

M L

Tfme sec O.D 4.7 5.4

)).9 15.2 20 7 21.8 26.1 51 8 135.2 230.4 240.6 244.6 252.8 Event Largest Steam Line Break Occurs Low Steam Generator Pressure Trip Signal Occurs

-Auxiliary Feedwater Delivery Begins CEA's Begfn to Drop into Core Nafn Steam Isolatfon Sfghal Generated; Loss of Offsite Power Occurs Nafn Stcam Isolation Valves Completely Closed Steam Generator Differential Pressure Setpof nt fs Reached; Auxf1 fary Feed-watcr Isolation Signal to Affected Steam Ge'nerator fs Actuated Pressurizer Empties Safety Ingectfon Actuation Signal Generated on Low Pressurizer Pressure Nafn Feedwatcr Rampdown Complete; Naxfmum Bypass Flow Continues to Reach Steam Generators HPSI Pump Reaches Full Speed Auxflfary Feedwater Block Valve Completely Closed Naxfmum Post-Trip Reactivity Affected Steam Generator Blows Dry Naxfmum Return to.Power Mfnfmum DNBR Vsfng NacBeth Correlatfon Set oint or Value 6.358 ft2 510 psfa 460 psfa 530 psfd; 120 second delay before valve

, closes 1578 psfa 5% of Full Nein Feedwater Flow

+.046Xap 2500 ibm

)2.1%, of 2700 tQt

~1.3

TABLE 3.2.1.5c-3 SEQUENCE OF EVENTS FOR THE STEAM l;INE BREAK EVENT AT HOT Z X

S N

S SITE POKR Time sec 0.0 3.5 4.1 10.5 23.3 25.7 60.3 192.9 209.9 211.7 Event Largest Steam Lfne Break Occurs

-Offfste Power Lost

-Four RCPs Coastdown Begins Low Steam Generator Pressure Trip Signal Occurs

-Auxiliary Feedwater Delivery Be9fns Kafn Steam Isolation Signal Generated on Low Steam Generator Pressure Kafn Steam Isolatfon Valves Completely

'Closed Safety In)ectfon Actuation Signal Generated on Low Pr essurfzer Pressure Pressurfzer Empties HPSI Pump Reaches Full Speed Maximum Post-Trip Reactivity Minimum DNBR Using MacBeth Correlation Maximum Return to Power Set oint or Valu.e 6 358 ft2 510 psia 460 psfa 1578 psia

%%%a

+ 30%hp

>1.3 5.3%, of 2700 HMT

0 100 200 390 Tl%, KCOSS SN Fl.ORtDA POSER 5 LIGHT Coo St.

Luc)e ttuclear Power Plant FQST-TRIP STEN LIflE BREAK EVENT HOT FlJLL POWER MITH ARf NI LOSS OF C NRE POWER VS TlNK FIQJPE 3,2.1,5C-I

XOO g

1S 0

200 RS lINE. SECMIS FLORlDA OWER h LlGHT COe St. Lucre 2 Nuclear Power Plant POST-TRIP STEN LINE BREAK EYENT pe flJLI. PSKR MITH AR NS LOSS OF hC CORE HEAT FNX VS TINE

AYG ZIN 500 206 1

200 300 TlNE, SECMI FLOR IDA POWER h L,lGHT COe St. Luc)e 2

'hclear Power Plant POST-TRlP STEN t.lNE BREAK KVKNT

'OT FULL RMR lfITH ARt NI LOSS OF At:

REACTOR COOLANT SYSTEN TKNPERATURES YS Tkl'lE FIHJK 3,2.1,5C-Y

200 300 Tlute, SECoeS LORIDA 5 LIGHT CO>>

. Luc)e >

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%ST TRiP STEN LlNE 1REAK EVENT HOT FULL POCR MITH AFM ND LOSS OF AC REACTOR COOLNT SYSTfN PRESSVRE VS Tl."IE

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'MO UNAFFE IED AFFECTS 10O 200 300 TINE, SEMI 500 FLORIDA POWER 5 LIGHT CO<

St.

Luc)e 2 Nuclear Power Plant POST-TRIP STEN LINE SREAK EVENT HOT FULL PNER MITH AFM NS UIS OF AC STKN.SENERATOR PRESSURE VS TINE FIRZ

~.~.I.SC-5

~ '

6

-2 TOTAL BORON c

~ j SCRAM

-10 200 500 TllK. $ENIS 400 500 FLORIDA OWER 5 LIGHT CO I St. Lucfe 2 Nuc1 ear Power PIant POST-TRIP 'STEAN LINK IREAKfVENT HOT FULL POMER MITH AFM ND UNS OF I'.

REACYIVETEKS VS T.I%

FIHJK 3,2,1,5C

25 20

~ +

200

'M0 TllKi SEC0NDS 400 500 FLQR IDA POWER 5

LIGHT CO.

St. t.ucfe Nuclear Po~er Plant POST-TRIP STER l.lHE SREAK KYENT NT zEM PONER NITH AFM Al USS OF AC t:DRE POm VS Tlm FIRE 5,2.1.5C-7

4

~

L 200 RO T1%g SECONN FLOR t DA

,'ONER

< LIGHT CO I St.'Lucre nuclear Power Plant POST-TRIP STKN Ltd IREAK EYKNT tiT 'Zy. PONER NITH I-N NI NSS OF At:

CORE HEAT I'QX VS. TNE

200 200 300 TINE, Sums 100 FLORIDA PG'E'ER h LIGHT CO Lucte>'::='.

~~r ?ewer PIant POST TRIP STEN ONE BREAK BENT HOT. mn ONER MITH ARt N LOSS OF AC K>CPlR V'L"lTV~STH1 TPFE>4TLKS '8 TI~F.

0

100 300 TINEA'ECONDS aoo soo Fi OR IDA l

OWER

~ LIGHT CO I St.

Lucite 2 Nuclear Power, Plant POST-TRtP STEN LlNE BREAK EVENT NT '2', PONER NlTH AN AtR LOSS OF C K(CTRL CPM'fT N)TIIPKKK VS TI."K FIRING 3,2,>.5C-1

C

~ i 2OO 3gl TINE, SENOS FLORIDA

<KR 5 LIGHT CO St. Lucre 2

lear Po~er Plant POST-TRIP STEN LINE BRPLK EVENT Nj 2K POND MlTH ARf NG SSS OF;.AC STBVt GEIEt'ATOR PASSU% VS TIfK

10 NDERATOR tNPPLER

~ I

-6

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Nuclear Power Plant NST-TRI~ STaN LlKIRM EvEe NT m. PONKR M1TH hFN N$ UNS OF AC V

ATTACHMENT4 DETERMINATIONOF NO SIGNIFICANT HAZARDS CONSIDERATION The standards used to arrive at a determination that a request for amendment involves no significant hazards consideration are included in the Commission's regulation, IO CFR 50.92, which state that no significant hazards considerations are involved if the operation of the facility in accordance with the proposed amendment would not (I) involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) create the possiblity of a new or different kind of accident from any accident previously evaluated; or (3) involve a significant reduction in a margin of safety.

Each standard is discussed as follows:

(I)

Operation of the facility in accordance with the proposed amendment would not involve a significant increase in the probability or consequences of an accident previously evaluated.

The addition of an Auxiliary Feedwater Actuation System (AFAS) time delay does not have any impact on the probability of, or the assumptions contained in, the bounding accident analyses.

Actuation of the Auxiliary Feedwater (AFW) system occurs within the time frames assumed in these analyses and as

such, the conclusions are not affected.

Conclusions reached in all applicable accident analyses are well within the acceptance criteria.

The addition of an AFAS time delay primarily reduces unnecessary challenges on the AFW system under the condition of a plant trip with offsite power and main feedwater available.

Therefore, this change does not increase the probability or consequences of an accident previously evaluated.

(2)

Use of the modified specification would not create the possibility of a new or different kind of accident from any accident previously evaluated.

Two classes of events, increased heat removal and decreased heat removal, are th'ose events which are affected by operation of the AFW system.

The St. Lucie Unit 2 Cycle 2 Stretch Power Reload Safety Evaluation (RSE) decreased heat removal events were re-evaluated and the limiting increased heat removal events reanalyzed to verify that operation of the AFW system with an installed time delay would not produce unacceptable results.

Therefore, installation of an AFAS time delay does not create the possibility of a new or different kind of accident.

(3)

Use of the modified specification would not involve a significant reduction

'n a margin of safety.

The results presented in the safety evaluation show that for the Steam Line Break (SLB) event, critical heat fluxes and containment peak pressure remain well within acceptance criteria. For the feedwater line break event, DNBR limits, radiological consequences, peak RCS pressure, and pressurizer fill considerations remain within previously established acceptance criteria.

Therefore, there is no significant reduction in margin of safety when operating with the proposed AFW system time delay.

Based on the above, we have determined that the amendment request does not (I) involve a significant increase in the probability or consequences of an accident previously evaluated, (2) create the probability of a new or different kind of accident from any accident previously evaluated, or (3) involve a significant reduction in a margin of safety; and therefore does not involve a significant hazards consideration.

EJW I /00 I /8

4

II II 4

II U

4 II II v

~

N II 4