ML20095L417

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Nonproprietary Margin to Overfill Analysis for Stgr for Millstone Nuclear Power Station Unit 3 Four-Loop Operation
ML20095L417
Person / Time
Site: Millstone Dominion icon.png
Issue date: 08/31/1991
From: Robert Lewis, Stackhouse J
WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:
Shared Package
ML19303E730 List:
References
WCAP-13003, NUDOCS 9205070077
Download: ML20095L417 (32)
v • d • e


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WESTINGHOUSE CLASS 3 WCAP-13003 4

MARGIN TO OVERFILL ANALYSIS FOR A STEAM GENERATOR TUBE RUPTURE FOR MILLSTONE NUCLEAR POWER STATION UNIT 3 FOUR-LOOP OPERATION AUGUST 1991 J. L. Stackhouse R. N. Lewis

. Nuclear Safety Department Westinghouse Electric Corporation Energy Systems Business Unit P.O. Box 355 Pittsburgh, Pennsylvania 15230

  • 1991 Westinghouse Electric Corporation HP0519:lD/082891

TABLE OF CONTENTS f

Paae

1. INTRODUCTION 1
11. ANALYSIS 3 A. Desigii Basis Accident 3 B. Conservative Assumptions 4 C. Operator Action Times 7 D. Transient Description 11 III. CONCLUSION 16 a

IV. REFERENCES 17 WP0519:1D/080891 i

I LIST Of TABLES Jele Ittle bae 1 Operator Action Times fer Design Basis Analysis 18 2 Sequence of Events 19 1

WP0519:10/080891 11

LIST Of FIGURES i

fioure litig Pug 1 Pressurizer Level 20 2 RCS Pressure 21 3 Secondary Pressure 22 4 Intact loop Hot and Cold leg RCS Temperatures 23 5 Primary to Secondary Break flow Rate 24 6 Ruptured SG Water Volume 25 WP0519:1D/080891 iii

._. . . _ _ .-- _ _ _ -- ._ __ _ ~. . __ .

I. INTRODUCTION An Analysis for a design basis steam generator tube rupture (SGTR) event has been performed for the Hillstone Nuclear Power Station Unit 3 to demonstrate margin to steam generator overfill. Millstone Unit 3 employs a Westinghouse pressurized weter reactor (PWR) unit rated at 3411 MWt. The reactor coolant system has four reactor coolant loops with Model F steam generators. The SGTR analysis was performed for four-loop operation and is applicable for an uniform steam generator tube plugging level of up to 10 percent *. The SGTR  :

analysis is bounding for operation with a Westinghouse standard fuel core, a Vantage-SH fuel core, or a standard fuel / Vantage-5H fuel transition core installed with a positive moderatur temperature coefficient.

The steam generator tube rupture analysis was performed for Hillstone Unit 3 using the methodology developed in WCAP 10698 (Reference 1). This analysis methodology was developed by the SGTR Subgroup of the Westinghouse Owners Group and was approved by the NRC in a Safety Evaluation Report dated March 30, 1987. The LOFTTR2 program, an updated version of the LOFTTRI program, was used to perform the SGTR analysis for Millstone Unit 3. The LOFTTnl program was developed as part of the revised SGTR analysis niethodology ar,i was used for the SGTR evaluations in Reference 1. However, the LOFTTRI program was subsequently modified to accommodate steam generator overfill and the revised program, designated as LOFTTR2, was used for the evaluation of tf consequences of overfill in WCAP-11002 (Reference 2). The LOFTTR2 program is identical to the LOFTTR1 program, with the exception that the LOFTTR2 program has the additional capability to represent the transition from two regions (steam and water) on the secondary side to a single water region if overfill occurs, and the transition back to two regions again depending upon the calculated secondary conditions. Since the LOFTTR2 program has been validated against the LOFTTR1 program, the LOFTTR2 program is also appropriate for performing licensing basis SGTR analyses.

WP0519:lD/082891 1

Plant response to the SGTR event was modeled using the LOFTTR2 computer code with conservative assumptions of break size and location, ctadenser availability and initial secondary water mass in the ruptured steam generator.

The analysis methodology includes the simulation of the operator actions for

-recovery from a steam generator tube rupture based on the Hillstone Unit 3 Emergency Operating Procedures (EOPs), which were developed from the Westinghouse Owners Group Emergency Response Guidelines (ERGS). The operator action times used for the analysis are based on the results of simulator studies of the SGTR recovery operations which were performed by the Millstone Unit 3 operations personnel using the plant training simulator. Thus, the SGTR analysis is based on the application of the actual plant procedures and operator training.

An SGTR resules in the le@ age of contaminated reactor coolant into the secondary system and subsequent release of a portion of the activity to the atmosphere, and an analysis is typically performed to assure that the offsite radiation doses resulting from an SGTR are within the allowable guidelines.

However, one of the major concerns for an SGTR is the possibility of steam generator overfill since this could potentially result in a significant increase in the offsite radiation t'oses. Therefore, to ensure that steam generator overfill will not occur for a design basis SGTR for Millstone Unit 3, an analysis wes performed to demonstrate margin to steam generator overfill assuming the limiting single failure relative to overfill.

The limiting single failure was assumed to be the _

- es ,t consistent with the methodology in Reference 1. The L0fT1R2 ani, lysis to determine the margin to overfill was performed for the time period from the tube rupture until the primary and secondary pressures are equalized and the break flow is terminated. The water volume in the secondary side of the ruptured steam generator was calculated as a function of time to demonstrate that overfill does not occur. The results of this analysis demonstrate that WP0519:lD/082891 2 l

there is margin to steam generator overfill for a design basis SGTR for Millstone Unit 3.

WP0519:lD/080891 3 4

//ALYSIS D An analysis was performed to determine the margin to steam generator overfill for a design basis SGTR event for four loop operation for Millstone Unit 3.

The analysis was performed using the LOFTTR2 program and the methodology developed in Reference 1. This section includes a discussion of the methods and assumptions used to analyze the SGTR event, as well as the sequence of '

events for the recovery and the calculated results.

A. Desian Basis Accident The accident modeled is a double ended break of one steam generator tube locatedatthetopofthetubesheet[ '

Thelocat'ionofthebreakf_

Itwasalsoassumedthatlossofoffsitepoweroccursat ,

the time of reactor trip, and the highest worth control assembly was assumed to be stuck in its fully withdrawn position at reactor trip.

For the three-loop reference plant in WCAP 10698, the most limiting single failure with respect to steam generator overfill was determined tobe[

The Millstone Unit 3 plant has one main steam pressure relieving lve (HSPRV) and one main steam pressure relieving bypass valve (MSPRBV) for each steam generator. The MSPRVs provide automatic pressure relief capability, but the manual operation of the valves is not seismically qualified. The MSPRBVs do not have automatic pressure relief capability, but provide a safety grade means for manual steam relief, and were assumed to be used for the plant cooldown. Thus, the equivalent single failure for Millstone Unit 3 would be ~

]Noweverbasedon previous sensitivity stedies for four-loop plants, the limiting single WP0519:lD/071891 4

fatlure may be _

7c The Millstone Unit 3 AFW system consists of two motor driven pumps, and one turbine-driven pump with a capacity equal to the combined capacity of the two motor driven pumps. Each motor driven pump normally feeds two steam generators and the turbine driven pump feeds all four steam generators. There are two AFW flow control valves for each steam generator, one in the flow path from the motor driven pump and one in the flow path from the turbine driven pumo. There is also an isolation valve in series with the control valve in each AFW flow path. The AFW flow control and isolation valves would be normally open and the flow control valves are used to terminate feedwater flow to the ruptured steam generator and control inventory in the intact steam generators.

However, when isolating the AFW flow to the ruptured steam generator, the operator would first close the firm control valve in each of the ,

flow paths to the ruptured steam gen <arator, and then if the flow does not decrease, the operator would immediately close the corresponding isolation valve. Thus, a single failuro of a ruptured steam generator flow control valve to close would not require signif' cant additional time to terminate AFW flow to the ruptured steam generator. Since a single failure of an AFW flow control valve is not limiting, the single failurewasassumedtobe[

This failure increases the time required to perform the RCS cooldown,

}M

'which results in additional primary to secondary leakage and decreases the margin to steam generator overfill.

B. Conservative Assumotions Sensitivity studies were performed previously to identify the initill plant conditions and analysis assumptions which are conservative relative to steam generator overfill, and the results of these studies WP0519:10/071891 5

l l

I were reported in Reference 1. The conservative conditions and assumptions which were used in Reference 1 were also used in the LOFTTR2 analysis to determine the margin to steam generator overfill for Hillstone Unit 3 with the exception of the following differences.

1. Reactor Trio and Turbine Runback A turbine runback can either be initiated automatically or the operator can manually reduce the turbine load following an SGTR to attempt to prevent a reactor trip. For the reference plant analysis in WCAP 10698, reactor trip was calculated to occur at approximately

~

~

nd turbine runback to u .-

was simulated based on a runback rate of The effect of turbine runback was conservatively simulated by ,_

-c However, if reactor trip occurs prior to turbine runback to ,

,would not be possible. It is noted that earlier reactor trip -

wil'E result in earlier initiation of primary to secondary break flow accumulation in the ruptured steam generator and earlier initiation of AFW flow. These effects will result in an increased secondary mass in the ruptured steam generator at the time of isolation since the isolation is assumed to occur at a fixed time after the SGTR occurs rather than at a fixed time after reactor trip, it would be overly conservative to include the simulation of turbine runback to

.- aa L in addition to the penalty in secondary mass due to earlier reactor trip. Thus, for this analysis, the time of reactor trip was determined by modeling the Millstone Unit 3 reactor protection system, and turbine runback was simulated --. __

34 F

WP0519:lD/071891 6

2. Steam Generator Secondary Mass

. n.c A

initial secondary water mass in the ruptured steam generator was determined by Reference 1 to be conservative for overfill. As noted above, turbine runback was assumed to be initiatedandwassimulategy _

l The initia_1 steam generator total fluid masswasconservativelyasTumedtobe

~~

0.L

3. AFW System Operation For the reference plant analysis in WCAP 10698, reactor trip ~

occurred on

~

after the_S

, and 51 was initiated on low pressurizer pressure at ,

after reactor trip. The reactor and turbine trip and the assumed concurrent loss of affsite power will result in the termination of mair feedw flow and actuation of the AFW system, The SI signal will also result in automatic isolation of the main feedwater system and actuation of the AFW systtm. The flow from the turbine-driven AFW pump will be available within approximately 10 seconds following the actuation signal, but the flow from the motor-driven AFW pumps will not be available until approximately 60 seconds due to the startup and load sequencing for the emergency diesel e merators. For the reference plant analysis, it was assumed that AFW flow from both the turbine and motor driven pumos is g initiated The total AFW flow from all of the AFW pumps was assumed to be distributed uniformly to each of the steam generators until operator actions are simulated to throttle AFW flow to control steam generator water level in accordance with the emergency procedures.

WP0519:lD/071891 7

~

It is noted that if reactor trip occurs on

]mtthe pressure at the time of reactor trip may be significantly higher than the 51 initiation setpoint. In this event, there may be a significant time delay between reactor trip and 51 initiation, and it would not be conservativetomodelg]

Thus, for this analysis, the time of reactor tripwasJeterminedTymodelingtheHillstoneUnit3 reactor protection systen., and the actuation of the AFW system was based on the[ ]% cit was assumed that flow from both the turbine and motor-drivea AFW pumps is initiated at _

fA conservatively high AFW flow rhte of 300 gpm per steam generator was assumed for the analysis since cavitating venturi flow elements are provided in the AFW supply lines to each steam generator which limit the flow to less than this value,

(

4. lnstrument Uncertainties Instrumert uncertainties bave been included as a part of the analysis assumptions where they produce conservative results.

Anaiysis results should be reviewed if the uncertainties ft.r the instruments used in the steam generator tube rupture analysis increases.

C. Operator Action Times In the event of an SGTR, the operator is required to take actions to stabilize the plant and terminate the primary to secondary leakage. The operator actions for SGTR recovery are provided in Millstone Unit 3 E0P 35E-3 which is based on the Westinghouse Cwners Group ERG E-3, and

, these actions were explicitly modeled in this analysis. The operator actions modeled include identification and isolation of the ruptured WP0519:10/082891 8

= -

r steam generator, cooldown and depressurization of the RCS to restore inventory, and termination of Si to stop primary to secondary leakage.

These operator actions are described below.

1. Identify the ruptured steam generator.

High secondary side activity, as indicated by the main steamline radiation monitors, condenser air ejector radiation monitor, or steam generator blowdown radiation monitors typically will provide the first indication of an SGTR event. The ruptured steam generator can be identified by an unexpected increase in steam generator level, or i high radiation indication from a steam generator sample, a main steamline, or steam generator blowdown line. For an SGTR that results in a reactor trip' at high power as assumed in this analysis, the steam generator water level as indicated on the water level instrumentation will decrease significantly for all of the steam generators. The AFW flow will begin to refill the steam ,

ger.arators, distributing approximately equal flow to each of the steam generators. Since primary to secondcy leakage adds additional liquid inventory to the ruptured steam generator, the water level in that steam generator will increase more rapidly.

This response, as indicated by the steam generator water level instrumentation, provides confirmation of an SGTR event and also identifies the ruptured steam generator.

2. Isolate the ruptured steam generator from the intact steam generators and isolate feedwater to the ruptured steam generator.

Once a tube rupture has been identified, recovery actions begin by 1solating steam flow from and stopping feedwater flow to the ruptured steam generator. In addition to minimizing radiological releases, this also reduces the possibility of overfilling the ruptured steam generator with water by 1) minimizing the accumulation of feedwater flow and 2) enabling the operator to WP0519:10/080891 9

establish a pressure differential between the ruptured and intact steam generators as a necessary step toward terminating primary to secondary leakage. In the Millstone Unit 3 E0P for steam generator tube rupture recovery, the operator is directed to isolate feed flow to the ruptured steam generator when the wide range level is greater than 58*.. For the Millstone Unit 3 SGTR analysis, it was assumed that the ruptured steam generator will be isolated when the steam generator wide range level reaches 58', or at the time determined from simulator studies, whichever is longer.

3. Cool down the Reactor Coolant System (RCS) .. sing the intact steam generators.

After isolation of the ruptured steam generator, the RCS is cooled as rapidly as possible to less than the saturation temperature corresponding to the ruptured steam generator pressure by dumping steam from only the intact steam generators. This ensures adequate subcooling in the RCS after depressurization to the ructured steam generator pressure in subsequent actions. If offsite power is available, the normal steam dump system to the condenser can be used to perform this cooldown. However, if offsite power is lost, the RCS is cooled using the MSPRBVs on the intact steam generators. ,

Since offsite power is assumed to be lost at reactor trip for this analysis, the cooldown was performed by dumping steam via the MSPRBVs on the intact steam generators.

4. Depressurize the RCS to restore reactor coolant inventory.

When the cooldown is completed, 51 flow will increase RCS pressure until break flow matches S1 flow. Consequently, SI flow must be terminated to stop primary to secondary leakage. However, adequate reactor coolant inventory must first be assured. This includes both sufficient reactor coolant subcooling and pressurizer 'nventory to maintain a reliable pressurizer level indication after 51 flow is WP0519:lD/080891 10

r i

stopped. Since leakage from the primary side will continue after 51 flow is stopped until RCS and ruptured steam generator pressures equalize, an " excess" amount of inventory is needed to ensure pressurizer leve': remains on span. The " excess" amount required depends on RCS pressure and reduces to zero when RCS pressure equals l

the pressure in the ruptured steam generator. l The RCS depressurization is performed using normal pressurizer spray if the reactor coolant pumps (RCPs) are running. However, since offsite power is assumed to be lost at the time of reactor trip, the RCPs are not running and thus normal pressurizer spray is not available. In this event, RCS depressurization can be, performed using the pressurizer PORVs or auxiliary pressurizer spray. Because the pressurizer PORVs are the preferred alternative, it was assumed -;

that a pressurizer PORY is used for the RCS depressurization for this analysis.

5. Terminate 51 to stop primary to secondary leakage.

The previous actions will have established adequate RCS subcooling, a secondary side heat sink, and sufficient reactor coolant inventory to ensure that Si flow is no longer needed. When these actions have been completed 51 flow must be stopped to terminate primary to secondary leakage. Primary to secondary leakage will continue after Si flow is stopped until the RCS and ruptured steam generator pressures equalize. Charging flow, letdown, and pressurizer heaters will then be controlled to prevent repressurization of the RCS and reinitiation of leakage into the ruptured steam generator.

Since these major recovery actions are modeled in the_SGTR analysis, it is necessary to establish the times required to perform these actions.

Although the intermediate steps between the major actions are not explicitly modeled, it is also necessary to account for the time required to perform the steps, it is noted that the total time required WP0519:lD/080891 11

c to complete the recovery operations consists of both operator action time and system, or plant, response time. For instance, the time for each of the major recovery operations (i.e., RCS cooldown) is primarily due to the time required for the system response, whereas the operator action time is reflected by the time required for the operator to perform the intermediate action steps.

The operator action times to identify and isolate the ruptured steam generator, to initiate RCS cooldown, to initiate RCS depressurization, and to perform safety injection termination were developed in Reference 1 for the_ design basis analysis. Northeast Utilities has performed simulator studies to determine the corresponding operator action times to perform these oper,ations for Hillstone Unit 3. The operator actions and the corresponding operator action times used for the Millstone Unit 3 analysis are listed in Table 1. These operator action times represent bounding times for a typical operations crew.

D. Transient Descrintion The LOFTTR2 analysis results for the margin to overfill analysis are described below. The sequence of events for this transient is presented in Table 2.

Following the tube rupture, reactor coolant flows from the primary into the secondary side of the ruptured steam generator since the primary pressure is greater than the steam generator pressure. In response to this loss of reactor coolant, pressurizer level decreases as shown in Figure 1. The RCS pressure also decreases as shown in Figurt 2 as the steam bubble in the pressurizer expands. As the RCS pressure decreases due to the continued primary to secondary leakage, automatic reactor trip occurs at approximately 110 seconds on an overtemperature delta T trip signal.

WP0519:lD/080891 12

After reactor trip, core power rapidly decreases to decay heat levels.

The turbine stop valves close and steam flow to the turbine is terminated. The steam dump system is designed to actuate following reactor trip to limit the increase in secondary pressure, but the steam dump valves remain closed due to the loss of condenser vacuum resulting from the assumed loss of offsite power at the time of reactor trip, Thus, the energy transfer from the primary system caus,es the secondary side pressure to increase rapidly ofter reactor trip until the steam generator MSPRVs (and safety valves if their setpoints are reached) lift ._

to dissipate the energy, as shown in Figure 3, The main feedwater flow will be terminated and AFW flow will be automatically initiated following reactor trip and the loss of offsite power.

The RCS pressure and pressurizer level continue to decrease af ter reactor trip as energy transfer to the secondary shrinks the reactor coolant an( the tube rupture break flow continues to deplete primary inventory. The decrease in RCS inventory results in a low pressurizer pressure 51 signal at approximately 338 seconds. After SI actuation, the 51 flow rate initially exceeds the tube rupture break flow rate, and the RCS pressure and pressurizer level begin to increase and trend toward the equilibrium values where the 51 flow rate equals the break 4

flow rate.

Since offsite power is assumed lost at reactor trip, the RCPs trip and a gradual transition to natural circulation flow occurs. Immediately following reactor trip the temperature differential across the core decreases as core power decays (see Figure 4); however, the temperature differential subsequently increases as the reactor coolant pumps coast down and natural circulation flow develops. The increase in the temperature differential slows the rate of the pressurizer level and pressure decrease as shown in Figures 1 and 2, respectively. The cold leg temperatures initially trend toward the steam generator temperature as the fluid residence time in the tube region increases. The RCS hot and cold leg temperatures then slowly decrease due to the continued WP0519:1D/080891 13

addition of the auxiliary feedwater to the sieam generators until operator actions are initiated to control the auxiliary feedwater flow.

Major Operator Actions

1. Identify and Isolate the Ruptured Steam Generator Once a tube rupture has been identified, recovery actions begin by isolating steam flow from the ruptured steam generator and isolating the auxiliary feedwater flow to the ruptured steam generator. As indicated previously, it is assumed that the ruptured steam generator will be identified and isolated when the wide range level reaches 58% on the ruptured steam generator or at 16.5 minutes after initiation of the SGTR, whichever is longer. For the Millstone Unit 3 analysis, the time to reach a wide range level of 58% is less than 16.5 minutes, and thus it was assumed that the actions to isolate the ruptured steam generator are performed at 16.5 minutes. The actual time used in the analysis is 2 seconds longer because of the computer program numerical requirements for simulating the operator actions.
2. Cool Down the RC3 to Establish Subcooling Margin After isolation of the ruptured steam generator is completed at 992 seconds, an 8 minute operator action time is imposed prior to initiating the cooldown. After this time, actions are taken to con' the RCS as rapidly as possible by dumping steam from the intact steam generators. Since offsite power is lost, the RCS is cooled by dumping steam to the atmosphere using the MSPRBVs on the intact steam generators. As noted previously, the limiting single failure wasassumedto{

_ at -

, _ Thus,itwasagsumedthat_

~

are opened for the RCS cooldown {

q Wp0519:lD/082891 14 ,

ct ,c.

was assumed to be opened at 1474 seconds and

.- a ,c. -

was assumed to be opened at 1476 seconds. The cooldown is continued until RCS subcooling at the ruptured steam generator pressure is 20'F plus an allowance of 30'F for subcooling uncertainty. When these conditions are satisfied at 2300 seconds, it is assumed that the operator closes the intact steam generator MSPRBVs to terminate the cooldown. This cooldown ensures that there will be adequate subcooling in the RCS after the subsequent depressurization of the RCS to the ruptured steam generator pressure. The reduction in the intact steam generator pressures required to accomplish the cooldown is shown in Figure 3, and the i

effect of the cooldown on the RCS temperature is shown in Figure 4.

As shown in Figure 2, the RCS pressure also decreases during this cooldown process due to shrinkage of the reactor coolant, and then begins to increase due to the increased 51 flow after the cooldown is terminated.

n

3. Depressurize RCS to Restore Inventory After the RCS cooldown, a 3 minute operator action time is included prior to the RCS depressurization. The actual delay time used in the Analysis is 3 minutes and 4 seconds because of the computer -

program limitations for simulating operator actions. The RCS depressurization is performed to assure adequate coolant inventory prior to terminating SI flow. With the RCPs stopped, normal pressurizer pray is not available and thus the RCS is depressurized by using a pressurizer PORV. The RCS depressurization is initiated at 2484 seconds and continued until any of the following conditions are shtisfied: RCS pressure is less than the ruptured steam generator pressure and pressurizer level is greater than the allowance of 13% for pressurizer level uncertainty, or pressurizer level is greater than 73%, or RCS subcooling is less than the 30*F allowance for subcooling uncertainty. For this case, the RCS c depressurization is terminated because the RCS pressure is reduced WP0519:lD/080891 15

to less than the ruptured steam generator pressure and the pressurizer level is greater than 13%. The RCS depressurization reduces the break flow as shown in Figure 5, and increases 51 flow to refill the pressurizer as shown in Figure 1.

4. Terminate Si to Stop Primary to Secondary Leakage The previous actions have established adequate RCS subcooling, verified a secondary side heat sink, and restored the reactor coolant inventory to ensure that Si flow is no longer needed. When these actions have been completed, the 51 flow must be stopped to prevent repressurization of tne RCS and to terminate primary to secondary leakage. The 51 flow is terminated at this time if RCS subcooling is greater than the 30*F allowance for subcooling uncertainty, minimum AFW flow is available or at least one intact steam generator level is in the narrow range, the RCS pressure is increasing, and the pressurizer level is greater than the 13% allowance for uncertainty.

After depressurization is completed, an operator action time of 3 minutes was assumed prior to Si termination. Since the above requirements are satisfied, SI termination was performed at this time. An additional 2 second delay was also assumed due to the computer program limitations in simulating the operator actions.

After 51 termination at 2794 seconds, the RCS pressure begins to decrease as shown in Figure 2. The RCS temperatures also begin to increase and the intact steam generator MSPRBVs are opened to dump steam to ma ntain the prescribed RCS temperature to ensure ti,at subcooling is maintained. When the MSPRBVs are opened, the increased er.ergy transfer from primary to secondary also aids in the depressurization of the RCS to the ruptured steam generater pressure. The primary to secondary leakage continues aft'.- the 51 flow is terminated until the RCS and ruptured steam generator pressures equalize.

WP0519:lD/080891 16 l

The primary to secundary break flow rate throughout the recovery operations is presented in Figure 5. The water volume in the ruptured steam generator is presented as a fuiiction of time in Figure 6. It is noted that the water volume in the ruptured steam b generator when the break flow is terminated is approximately 5496 ft', which is significantly less than the total steam generator volume of 5850 ft*. Therefore, it is concluded that overfill of the ruptured steam generator will not occur for a design basis SGTR for ,

Hillstone Unit 3. _

.j

).

4 WP0519:1D/080891 17

!!!. CONCLUSION An analysis has been perforced for a design basis SGTR event for four-loop operation for M'11 stone yriit 3 to demonstrate margin to steam generator overfill assuming the limiting single failure relative to overfill.

The limiting single failure is the failure of The results of this analysis indicate that tr.e recovery actiens can be completed to terminate the primary to secondary break fitw before overfill of the ruptured steam generator would occur, Thus, it is concluded that margin to steam generator overfill exists for a design basis steam generator tube rupture for four loop operation at Millstone Unit 3.

WP0519:lD/071891 18

,_____-------__-____--______-a. _ _ _ . - - _ _ - _ - _ . _ . _ , . . _ _ _ -

f IV. REFERENCES

1. Lewis, Huang, Behnke, Fittante, Gelman, "SGTR Analysis Methodology to Determine the Margin to Steam Generator Overffil " WCAP 10698 P-A (PROPRIETARY)/WCAP-10750 A [NON PROPRIETARY), August 1987.
2. Lewis, Huang, Rubin, Murray, Roidt, Hopkins, " Evaluation of Steam Generator Overfill Due to a Steam Generator Tube Rupture Accident,"

WCAP 11002 [ PROPRIETARY)/WCAP-11003 [NON-PROPRIETARY), February 1986. _

WP0519:10/080891 19

I Millstone Unit 3 Four-Loop Operation Steam Generator Tube Rupture Margin to Overfill Analysis TABLE 1 OPERATOR ACTION TIMES FOR DESIGN BASIS ANALYSIS Action Time identify and isolate ruptured SG 16.5 min or LOFTTR2 calculated time to reach 5B7. wide range level in the ruptured SG, whichever is longer.

Operator action time to initiate 8 min from isolation cooldown Cooldown Calculated by LOFTTR2 Operator action time to initiate 3 min from end of c Idown depressurization Depressurization Calculated by LOFTTR2 Operator action time to initiate 3 min from end of depressurization Si termination SI termination and pressure Calculated time after SI equalization termination for equalization of RCS and ruptured SG pressures WP0519:lD/080691 20 l

Millstone Unit 3 Four Loop Operation Steam Generator Tube Rupture Margin to Overfill Analysis TABLE 2 SE0VENCE OF T. VENTS LyEil Time (sec)

SG Tube Rupture 0 _

Reactor Trip 110 St Actuation 338 Ruptured SG lsolated 992 RCS Cooldown Initiated 1476 RCS Cooldown Terminated 2300 RCS Depressurization Initiated 2484 ,

RCS Depressurization Terminated 2612 51 Terminated 2794 s Steam Relief to Haintain RCS Subcooling 3420

~

Break Flow Terminated 4040 WPOS19:lD/080891 21 l

- _ _ _ - _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - _-- _ _ _ _ - - _ __ O

Millstone Unit 3 Four Loop Operation Steam Generator Tube Rupture Margin to Overf t11 Analysis ICC.

.e..

80."

E V TC.- ,

5 6 0 . *\ l 3

a 60.+

C Ej 40.-

K p 10 . <

l

~

i 20.-

. i

! i

. 500. 1000. 1500. 2000. 2500. 3000, 350C. 40C0= *E00. 1000.

?!ntistti Figure 1 Pressurizer Level WP0519:lD/050291 22

Millstone Unit 3 Four Loop Operation Steam Generator Tube Rupture Margin to Overfill Analysis 1

  • t00. ,

2250.' l N i 2000. "

=

1750. "

L y ' 50 0. "

b G

'A >

g 12 5 0. <

c.

1

- ; 0 0 0.
  • E '

W i 750.

  • 1 1'

5 0 0. <  ;

2 $ 0 . ?,

I n.

C. 500. 1000. 1400. 2000. 2500. 3000. 3500. 4000. 45 0. i;;;.

Ytettstti Figure 2 RCS Pressure r

23 WP0519:10/050291

Millstone Unit 3 Four Loop Operation Steam Generator Tube Rupture Margin to Overfill Analysis 1400.

4

.20 0; + FAULTED-LOOP PRESSURE 4 3 I E' 2000.<

~ ,*

, e0 0. <

-g

. fi 600 v i

N 4 -i

-t 400.+

INTACT LOOP PRESSURE 20 0. + i

\

l C.

O. 600. 1000. 1500,- 2000. 2$00. 3000. 3500. 4000. 4500. 5000.

t!NEtsECl Figure 3 Secondary Pressure WP0519:10/050291 -24

Millstone Unit 3 Four Loop Operation Steam Genentor Tube Rupture g Margin to Overfill Analysis 650.

j 600.<

b 550. - ~

c.

500.- r

_ v t 450. -

/

g 400. "

-9 350.<

5 0

3 0 0. +

250.

200.

C. 500. 1000. !$00. 2000, 2500. 3000. 3500. 4000. 4500, 5000.

T!nt15EC1 figure 4 Intact Loop Hot and Cold leg RCS Temper 4tures

.WP0519:10/050291 25

Millstone Unit 3 Four Loop Operation Steam Generator Tube Rugt.

Margin to Overfill Analysis

50. -

N 40, I

~

,4 '

E 30.

N I d i E  !

J 20. I E 1

= :0.

i

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c. )
  • 1: 4 C. 500.

1000. 1500. 2000. 2500. 3000. 3500. 4000. 4500. 5;;;.

TIMEtSECi Figure 5 Primary to Secondary Break Flow Rate WP0519:10/050291 26

. . _ . . ,~ ._ .. _. _ , __ _ _ _ . . _ _ . . _ _ . _ . . . . .

.i Millstone: Unit 3 Four-Loop. Operation Steam Generator Tube Rupture Margin to Overfill Analysis ,

i t> 0 0 0 . .,

-$ -500D. +

t .

- 3 ~ d 0 0 0. "

c

.J.

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' W. 2 0 0 0. "

.3-.

. ,S. i 2000.<

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TIMEISEC3 Figure 6 Ruptured SG Water Volume 27 WP0519:1D/050291

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

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