Text

Nonproprietary LOFTTR2 Analysis for Steam Generator Tube Rupture W/Revised Operator Action Times for Shearon Harris Nuclear Power Plant
	ML20011D124
Person / Time
Site:	Harris
Issue date:	11/30/1989
From:	Huang P, Robert Lewis, Marmo C; WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:	;
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ML18009A302	List: ML18009A301; ML20011D124; ML20011D125;
References
	WCAP-12404, NUDOCS 8912190118
	Download: ML20011D124 (88)
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LOFTTR2 ANALY$1$ FOR A STEAM GENERATOR TUBE RUPTURE MITH REV15ED OPERATOR ACTION TIMES FOR SHEARON MARRIS NUCLEAR POWER PLANT P. M. Nuang R. N. Lewis C. A. Marmo K. Rubin NOVEMBER 1989 Nuclear Safety Department Nestinghouse Electric Corporation Nuclear Energy Systems P.O. Box 355 Pittsburgh, Pennsylvania 15230

1988 by Westinghouse Electric Corporation 2120v:1D/111389

r' 4

TABLE OF CONTENTS fAtt l

1.

INTRODUCTION 1

ANALYSIS OF WWtGIN TO STEAM GENERATOR OVERFILL 4

A.

Design lasts Accident 4

5.

Conservative Assumptions 4

C.

Operator Action Times 7

'D.

Transient Description 12

!!!. ANALYSIS OF 0FFSITE RADIOLOGICAL CONSEQUENCES 24 A.

Thermal and Nydraulic Analysis 24 1.

Design Basis Accident 24 2.

Conservative Assumptions 25 3.

Operator Action Times 27 4.

Transient Description 28 5.

Mass Releases 42 8.

Offsite Radiation Dose Analysis 51 IV.

CONCLUSION 72 V.

REFERENCES 73

'2120v:1D/092989 1

J

i e

l LIST OF TABLES httle lith fatt

!!.1 Operator Action Times for Design Basis Analysts 11 l

II.2 Sequence of Events - Margin to Overfill Analysis 17 l

111.1 Sequence of Events - Offsite Radiation Dose Analysts 32 i

!!!.2 Mass Releases - Offstte Radiation Dose Analysts 47 III.3 Summartred Mass Releases - Offsite Radiation Dose 48.

I Analysis

!!!.4 Parameters Used in Evaluating Radiological 58 i

Consequences

!!!.5 Iodine Specific Activities in the Primary and Seew dary 61 Coolant

!!!.6 Iodine Spike Appearance Rates 62

+

l

!!!.7 Noble Gas Specific Activities in the Reactor Coolant 63 Based on 11 Fuel Defects l

!!!.8 Atmospheric Dispersion Factors and Breathing Rates 64 l

!!!.9 Thyroid Dose Conversion Factors 65

!!!.10 Average Gamma and Beta Energy for Noble Gases 66 111.11 Offsite Radiation Doses 67 i

2120v:1D/092989 11 l

j i

1 LIST OF FIGURES II.1 Pressuriter Level - Margin to Overft11 Analysis 18 11.2 RCS Pressure - Margin to Overft11 Analysts 19 II.3 Secondary Pressure - Margin to Overf111 Analysis 20 11.4 Ir. tact Loop Not and Cold Leg RCS Temperatures -

21 Margin to Overf111 Analysts 11.5 Primary to Secondary treak Flow Rate - Margin to 22 Overfl11 Analysis l

II.6 Ruptured SG Mater Volume - Margin to Overfill Analysis 23 III.1 RCS Pressure - Offsite Radiation Dose Analysis 33 J

III.2 Secondary Pressure - Offsite Radiation Dose Analysis 34 III.3 Pressuriter Level - Offsite Radiation Dose Analysis 35 III.4 Ruptured Loop Not and Cold Leg RCS Temperatures -

36 Offsite Radiation Dose Analysis III.5 Intact Loop Not and Cold Leg RCS Temperatures -

37 Offsite Radiation Dose Analysis III.6 Differential Pressure Between RCS and Ruptured 38 SG - Offsite Radiation Dose Analysis III.7 Primary to Secondary Break Flow Rate - Offsite 39 Radiation Dose Analysis

'l 2120v:10/092989 111 l

LIST OF FIGURES (Cont) l E18E1 111h FAtt

!!I 8 Ruptured SG Mater Volume - Offsite Radiation Dose 40 Analysis j

III.9 Ruptured SG Mater Mass - Offsite Radiation Dose Analysts 41

!!!.10 Ruptured SG Mass Release Rate to the Atmosphere -

49 Offsite Radiation Dose Analysis

!!!.11 Intact $Gs Mass Release Rate to the Atmosphere -

50 t

Offsite Radiation Dose Analysts i

4 111.12 lodine Transport Model - Offsite Radiation Dose Analysis 68 i

III.13 Break Flow Flashing Fraction - Offsite Radiation 69 Dose Analysis III.14 SG Mater Level Above Top of Tubes - Offsite 70 Radiation Dose Analysis 111.15 Iodine Scrubbin9 Efftetency - Offsite Radiation Dose 71 Analysis 2120v:10/092989 1v

I.

INTRODUCTION A LOFTTR2 analysts for a design basis steam generator tub 6 rupture (SGTR) event was previously performed for the haron Harris Nuclear Power plant U

($NNPP) and the results were presented in Reference 1.

The SGTR analysts was performed using the analysts methodology developed in NCAP-106g8 (Reference 2)

.and Supplement 1 to NCAP-106g8 (References 3). The methodology was developed by the SGTR Subgroup of the Nestinghouse Duners Group (NDG) and was approved by the NRC in Safety Evaluation Reports (SERs) dated December 17, 1985 and March 30,1987. The $NNPP SGTR analysts in Reference 1 included an analysts of the margin to steam generator overftll, as well as an analysis of the offstte radiation doses for a design basis SGTR. h analysts results demonstrated that there was margin to steam generator overft11 with the most l-Itatting single failure with respect to overf111, and that the calculated j

offstte radiation doses would be acceptable assuming the most limiting single failure for the offsite dose evaluation.

The $NNPP SGTR analysts was subsequently revised to support operation with Vantage 5 fuel, and the results of the revised analysts are included in the Vantage 5 Reload Transition Safety Report for SMNPP (Reference 4). The analysts results in Reference 4 support operation of SNNPP with a Standard fuel / Vantage 5 fuel transition core, Standard fuel core or Vantage 5 fuel core with up to 61 steam generator tube plugging. The SGTR reanalysts for the l

change to Vantage 5 fuel also demonstrated margin to steam generator overftli and acceptable offstte radiation doses for $NNPP.

The SGTR analyses performed for $NNPP in References 1 and 4 uttilred operator action times which were based on simulator demonstration runs that were performed by Carolina Power and Light Company. In the review of the SGTR analysts in Reference 1, the NRC (Reference 5) noted that the operator action times assumed in the analysis did not bound the results of the simulator demonstration runs. The NRC requested that Carolina Power and Light company perform additional simulator demonstration runs to verify the app 11cability of the operator action times used in the analysts, prior to the next refueling outage. The NRC also specified that, In the event that the additional 2120v:10/112089 1

2

i i

simulator demonstration runs generate operator action times that are not I

bounded by those assumed in the SGTR analysis for SHNPP, supplemental SGTR

{

analyses shall be submitted using conservative operator action times based on those obtained during the simulator demonstration runs.

Carolina Power and Light Company performed the additional simulator demonstration runs and the operator action times observed are longer than those used in the SHNPP SGTR analyses in References I and 4.

Therefore, the l

SGTR analysis for $NNPP has been repeated using the revised operator action times, and the results of the analysis are documented in this report. This i

updated SGTR analysis uttltres the same analysis methodology as the previous '

analyses in References 1 and 4, and is also applicable for SHNPP operation I

with a Standard fuel / Vantage 5 fuel transition core Standard fuel core or Vantage 5 fuel core with up to 6% steam generator tube plugging. However, in i

addition to the revised operator action times, credit is taken for the operation of the pressurizer power operated relief valves (PORVs) to perform l

the reactor coolant system (RCS) depressurization in this updated analysis, whereas it was assumed that the pressurizer PORVs would not be used for this purpose in the analyses in References 1 and 4.

This' updated SGTR analysis with the revised operator action times also includes an analysis to demonstrate margin to steam generator overfill as well as an analysis to demonstrate that the calculated offsite radiation doses are L

less than the allowable guidelines. Plant response to the event was modeled using the LOFTTR2 computer code with conservative assumptions of break size and location, condenser 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 SHNPP Emergency Operating Procedures (EOPs), which were developed from the Nestinghouse Owners Group Emergency Response Guidelines (ERGS). In subsequent references to the SHNPP-EOPs throughout the text, the specific SNMPP E0P will be listed along with the corresponding Westinghouse Owners Group ERG in parenthesis.

2120v:10/092989 2

lince the limiting single failure is different for the overf t11 analysis and the offsite radiation dose analysis, the two analyses were performed using different single failure assumptions.

For the margin to overfill analysis, thesinglefailurewasassumedtobethefailureofan{

,h,orthe

~

analysis of the offsite radiation doses, the ruptured stna generator PORV was assumed to fall open at the time the isolation of the rtptured steam generator is performed. These assumptions are consistent with the NRC approved methodology in References 2 and 3.

f The LOFTTR2 analysis to determine the margin to overft11 was performed for the j

time period from the steam generator tube rupture untti the primary and secondary pressures are equaltred (break flow termination). 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 i

this analysis demonstrates that there is margin to steam generator overfill for SHNPP, For the offsite radiation dose analysis, the primary to secondary break flow and the steam releases to the atmosphere from both the ruptured and intact steam generators were calculated for use in determining the activity released to the atmosphere. The mass releases were calculated with the LOFTTR2 p ogram from the initiation of the event untti termination of the break flow. For the time period following break flow termination, steam releases from and feedvater flows to the ruptured and intact steam generators were determined from a mass and energy balance using the calculated RCS and steam generator conditions at the time of leakage termination. The mass release information was used to calculate the radiation doses at the exclusion area boundary and low population zone assuming that the primary coolant activity is at the Standard Technical Specification limit prior to the accident. The results of i

this evaluation show that the offsite doses for SHNPP are well within the allowable guidelines specified in the Standard Review Plan, NUREG-0800, Section 15.6.3, and 10CFR100.

2120v:1D/092989 3

!!. ANALYSIS OF MARGIN TO STEAM GENERATOR OVERFILL An analysis was performed to determine the margin to steam generator overfill for a design basis SGTR event for SHNPP. The analysis was performed using the LDFTTR2 program and the methodology developed in Reference 2, and using the plant specific parameters for SHNPP. 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.

Design Basis Accident The accident modeled is a double-ended break of one steam generator tube locatedatthetogofthetubesheet fhe location of the break a,a It was

~

also assumed that loss of offsite power occurs at the time of reactor trip, and the highest worth control assembly was assumed to be stuck in its fully withdrawn position at reactor trip.

-The most limiting single failure with respect to steam generator overfill wasdeterminedtobea{

in Reference 2.

This limiting single

~

failure was also applied for the overfill analysis for the three-loop SHNPP. The failure of the causing an increase in total primary to secondary leakage. Consequently, more water will accumulate in the ruptured steam generator.

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Cantervative Atta=atlant Sensitivity studies were performed previously to identify the initial plant conditions and analysis assumptions which are conservative relative to steam generator overfill, and the results of these studies were reported in Reference 2.

The conservative conditions and assumptions 2120v:10/111389 4

which were used in Reference 2 were applied with the SHNPP parameters in the LOFTTR2 analysis to determine the margin to steam generator overfill for $NNPP with the exception of the following differences.

1.

Rameter Tria and Turbina aunhack A turbine runback can be initiated automatically or the operator can manually reduce the turbine load following an SGTR to attempt to j

prevent a reactor trip. For the reference plant analysis in reactor trip was calculated to occur at approximately Reference 2!$dturbinerunbackto

(

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simulated based on a runback rate of

~*fheeffectof

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turbinerunbackwasconservativelysiimlatedby

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s t.however, if reactor trip

,,'urbine runback to l

occurs prior to t

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would not be possible.

It is noted that earlier reactor trip will result in ear 1ier initiation of primary to secondary break flow accumuletion in the ruptured steam generator and earlier initiatian of auxili's.j feedwater (AFN) 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 1

after the $GTR occurs rather than at a fixed time after reactor trip.

~

It would,be overly conservative to include the turbine runback to

~ fli 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 SHNPP reactor protection system, and turbine runback was simu ted

]

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2.

Stena Generator secondary Mast

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A initial secondary water mass in the ruptured steam generator was determined by Reference 2 to be conservative for overfill. As

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noted above, turbine runback was assumed to be initiated and was

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simulated by

]*iheinItialsteamgeneratortotalfluidmasswasconservatively assumed'tobe{

p 3.

AFW tvsten Onoration i

i ForthereferenceplantanalysisinReference2.reactorJ'r,1poccurred l

'" b after the SGTR. and SI was initiated on low pressurizer pressure at

~

after reactor trip. The reactor and turbine trip and the assumed concurrent loss of offsite power will result in the termination of main feedwater flow and actuation of the motor-driven and turbine-driven AFH pumps. The SI signal will also result in automatic I

isolation of the main feedwater system and actuation of the motor-driven AFM pumps for the reference plant. The flow from the turbine-driven AFN pump will be available within approximately 10 seconds following the actuation signal, but the flow from the motor-driven AFM pumps will not be available until approximately 60 seconds due to the startup and load sequencing for the emergency i

diesel generators. For the reference plant analysis it was assumed that AFM flow from both the turbine and motor-driven pumps is,,,,

initiated The

~

total AFM flow from all of the AFM pumps was assumed to be distributed uniformly to each of the steam generators until operator actions are simulated to isolate or throttle AFW flow to control steam generator water level in accordance with the emergency procedures.

2110v:1D/111389.

6

~

m It is noted that if reactor trip occurs on

]Npressureat the time W reactor tr1p any be s1gnifIcantly h1gher than the $1 lattiation setpoint. In this event, there say be a significarit time delay between resttor trip and SI 1n1tIat1on, and 1t would not be conservativetomode,'the]

Thus, for the SNNPP analysts, the time of reactor trip was determined l

by modeling the SNNPP reactor protection system, and t,he attuation of g

the AFN system was based on the It was assumed that flow from both the turbine and motor-driven AFN" pumps is I

initiated, due to the assumption W a loss of offstte power at the timeofreactortrip,[

~YheAFNflowassumedfortheanalystsis500 spa i

per steam generator, which is based on the combined capability of the l

turbine-driven pump and both motor-driven pumps.

?

C.

Operator Action Times l

In the event of an SGTR, the operator is required to take actions to stablitze the plant and terminate the primary to secondary leakage. The operator acticas for SGTR recovery are provided in the SNNPP Plant Operating Manual. Procedure Number E0P-Path 1 (ERG E-3), and these actions were explicitly modeled in this analysts. The operator actions undeled 1nelude 1dontifIcation and 1solat1on of the ruptured steam generator, cooldoen and depressortsation W the RCS to restore inventory, and termination of $1 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 condenser vacuum pump effluent radiation monitor, steam generator blowdown line radiation monttor, or main stone 11ne radiation monttor, typically will 2120v:10/11200g 7

.. ~

i provide the first indication of an SGTR event. The ruptured steam generator can be identified by an unexpected increase in steam generator level, high activity in a steam generator water sample, or a 1

high radiation indication on the corresponding main steamline radiation monitor. For an SGTR that results in a high power reactor trip as assumed in this arjalysis, the steam generator water level will decrease to near the bottom of the narrow range scale for all of the steam generators. The AFN flow will Degin to refill the steam j

generators, distributing flow to each of the steam generators. Since primary to secondary leakage adds additional 11guld inventory to the ruptured steam generator, the water level will increase more rapidly in that steam generator. This response, as displayed by the steam i

generator water level instrumentation, provides confirmation of an L

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 isolating steam flow from and stopping feedwater flow to the ruptured i

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 establish a pressure differential

(

between the ruptured and intact steam generators as a necessary step toward terminating primary to secondary leakage.

For the reference plant analysis in Reference 2, it was assumed that the ruptured steam generator will be isolated when

[forSHNPP,thesteamgeneratornarrowrangelevel corresponding to being just on span is 101 and the comparable operator action time is 13 minutes and 35 seconds. Thus, applying the

~

Reference 2 methodology for the SHNPP analysis, the ruptured steam l

generator was assumed to be isolated at 30 percent narrow range level or at 13 minutes and 35 seconds, whichever was longer.

l l

2120v:1D/111489 8

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4

-3.

Cool down the RCS using the intact steam generators.

e 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 ruptured steam generator pressure in subsequent actions. If offsite power is I

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 PORVs on the intact steam generators.

Because offsitepowerisassumedtobelostandasingje,failureofthe,

]wasassumedforthe SHNPPanalysis,.thecooldownwasperformedbydumpingstum{

- a,c.

4.

Depressurize the RCS to restore reactor coolant inventory.

When the cooldown is completed, SI flow will increase RCS pressure

'untti break flow matches SI 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 inventory to maintain a reliable pressurtter level indication after SI flow is stopped. Since leakage from the primary side will continue after SI flow is stopped until f4CS and ruptured steam generator pressures L

equalize, an " excess" amount of inventory is needed to ensure pressurizer level remains on span. The " excess" amount required depends on RCS pressure and reduces to zero when RCS pressure equals the pressure in the ruptured steam generator.

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 tftp, the RCPs are not running and thus normal pressurizer spray is not available.

2'20v:1D/092989 9

1

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,x' 91 j

- In.this' event, RCS depressurization cari be performed using the

. pressurizer PORVs or auxiliary pressurizer spray. Because the pressurizer PORVs are the preferred alternative, it was assumed that a

. pressurizer PORV is used for the RCS depressurization for this analysis.

5.

Terminate SI 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 E

ensure that SI flow is no longer needed. When these actions have been completed, SI flow must be stopped to terminate primary to secondary leakage. Primary to secondary leakage will continue after SI flow is p

stopped until'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 tnese 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 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 ccoldown, to initiate RCS depressurization, and

.to perform SI termination were developed for the design basis analysis in

- Reference 2.

Carolina Power and Light Company has determined the corresponding operator action times to perform these c,perations for SHNPP. The operator actions and the corresponding operator action times used for the SHNPP analysis are listed in Table 11.1.

i

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TABLE !!.1 SHNPP SGTR ANALYSIS OPERATOR ACTION TIMES'FOR DESIGN BASIS ANALYSIS p

Time Intervals Identify and isolate ruptured SG 13 min and 35 see or LOFTTR2 calculated time from event-initiation to reach 301 narrow range level in the ruptured SG, whichever is longer Operator action time to initiate 8 min and I sec cooldown

.Cooldown Calculated by LOFTTR2 Operator action time to initiate 2 min and 16 sec-depressurization Depressurization Calculated by LOFTTR2 Operator action time to initiate-3 min

$1 termination SI termination and pressure Calculated by LOFTTR2 equalization

' 2120s:1D/111389 11

J 4.

s 1

D.

Transient Deterintion The LOFTTR2 analysis results for the SHNPP margin to overfill analysis are described below. The sequence of events for this transient is presented in Table II.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 L

Figure 11.1. The RCS pressure also decreases as shown in Figure II.2 as L

.the steam bubble in the pressurizer expands. As the RCS pressure

-decreases due to the continued primary to secondary leakage, automatic reactor trip occurs on an overtemperatere delta-T trip signal.

p L

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

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 causes the secondary side pressure to increase rapidly after reactor trip until the steam generator PORVs-(and safety valves if their setpoints are reached) lift to dissipate the energy, as shown in Figure 11.3. The main feedwater flow will be terminated and AFW flow will be automatically initiated following the loss i

. of offsite power assumed at the time of reactor trip.

The RCS pressure decreases more rapidly after reactor trip as energy transfer to the secondary shrinks the reactor coolant and the leak flow continues to deplete primary inventory. The decrease in RCS inventory results in a low pressurizer pressure SI signal. Pressurizer level also decreases more rapidly following reactor trip. After SI actuation, the SI flow rate initially exceeds the tube rupture break flow rate and the 4

L 2120v:lD/111389 12 L -

i

,, :* ?

pressurizer level begins to increase. This also results in an increase in thRCS pressure which trends toward the equilibrium value where thc SI e

flow rate equals the break flow rate.

Since offsite power is assumed lost at reactor trip the RCPs trip and a gradual transition to natural circulation flow occurs.

Ismediately

-following reactor trip the temperature differential across the core decreases as core power' decays (see Figure II.4); however, the temperature L

differential subsequently increases as the reactor coolant pumps coast down and natural circulation flow develops. The cold leg temperatures trend toward'the steam generator temperature as the fluid residence time L

in the tube region increases. The hot leg temperature reaches a peak and I

then s'iowly decreases, as steady state conditions are reached, until operator actions are initiated to cool down the RCS.

i 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, the ruptured steam generator is assumed to be identified and isolated when the narrow range level reaches 30% on the ruptured steam generator or at 13 minutes and 35 seconds after initiation of the SGTR, whichever is longer. For the Shearon Harris

-analysis, the time to reach 30% is less than 13 minutes and 35 seconds, and thus the ruptured steam generator is assumed to be isolated at 13 minutes and 35 seconds.

2.

Cool down the RCS to Establish Subcooling Margin After isolation'of the ruptured steam generator, there is a 8 minute and I second operator action time imposed prior to initiating the cooldown. The actual delay time used in the analysis is 1 second longer because of the computer program limitations for simulating the

2120v:1D/111389 13

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1 operator actions. After this time, actions are taken to cool 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 PORVs on the intact steam generators. However, as previously noted, the single failure was assumed to be the

,, bus,itwasassumedthat 4

_[A,lthough the steam flow from the ruptured steam generator to the turbine-driven AFM pump is isolated as part of the isolation step, steam flow from the intact steam generators to the turbine-driven AFM pump continues whichprovidesadditionalheatremovalcapabilityagenhancestheRCS cooldown.

is assumed to be

~

opened at 1297' seconds for.RCS cooldown. The cooldown is continued until RCS subcooling at the ruptured steam generator pressure is 20*F plus an allowance for subcooling uncertainty. When these' conditions-are satisfied at 2338 seconds,[it is assumed that the op i

o terminate the cooldown. This i

'cooldown' ensures that there will be adequate subcooling in the RCS after the subsequent depressurization of the RCS to the ruptured steam l~

generator pressure. The reduction in the intact steam generator pressure required to accomplish the cooldown is shown in Figure 11.3, and the effect of the cooldown on the RCS temperature is shown in Figure II.4. The pressurizer level and RCS pressure also decrease during this cooldown process due to shrinkage of the reactor coolant

.as -shown in Figures II.1 and II.2.

3.

Depressurize RCS to Restore Inventory After the RCS cooldown, a 2 minute and 16 second operator action time is included prior to-the RCS depressurization. The actual delay time used in the analysis is 2 minutes and 18 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 spray is not available and thus the RCS is depressurized 2120v:1D/111389 14

i

.3 by opening a pressurizer PORV. The RCS depressurization is initiated at 2476 seconds and continued untti any of the following conditions are satisfied: RCS pressure is less than the ruptured steam generator pressure and pressurizer level is greater than 101, or pressurizer level is= greater than 75%, or RCS subcooling is less than 20'F. For this case, the RCS depressurization is terminated because the RCS pressure is reduced to less than the ruptured steam generator pressure and the pressurizer level is above 101. The RCS depressurization

' reduces the break flow as shown'in Figure 11.5, and increases $1 flow to refill the pressurizer as shown in Figure 11.1.

4,

4.

Terminate SI to Stop Primary to Secondary Leakage The previous actions establish 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, the $1 flow must be stopped to prevent repressurization of the'RCS and to terminate primary to secondary leakage. The SI flow is terminated at this time if RCS subcooling is greater than 20'F.

minimum AFW flow is available or at least one intact steam generator level is in the narrow range, the RCS pressure is stable or increasing, and the pressurizer level is greater than 101. For the SHNPP analysis, SI was not terminated until the RCS pressure increased to 50 psi above the ruptured steam generator pressure to assure that RCS pressure is increasing.

After depressurization is completed, an operator action time of

- 3 minutes was assumed prior to initiation of SI termination. Since the above requirements are satisfied. SI termination actions were performed at this time by closing off the SI flow path. After $1 termination,theRCSpressurebegins-todecreageasshownin g

Figure 11.2. The is also opened to dump steam to meintain the prescribed RCS temperature to engure that subcooling is maintained.

tfieincreased 2120v:10/111389 15

L i,

1 energy transfer from primary to secondary also aids in the

'depressurization of the RCS to the ruptured steam generator pressure.'

The primary to secondary leakage continues after the SI flow is terminated until the RCS and ruptured steam generator pressures equalize.

The primary to-secondary break flow rate throughout the recovery operations is presented in Figure 11.5. The water volume in the ruptured steam generator is presented as a function of time in Figure !!.6. It is noted that the water volume in the ruptured steam generator when the break flow is terminated is less than the total 3

steam generator volume of 5949 ft. Therefore, it is concluded that overfill of the ruptured steam generator will not occur for a design basis SGTR for Sheaton Harris.

I 2120v:1D/111389 16

v. :

TA8LE II.2 SHNPP SCTR ANALYSIS m:

SEQUENCE OF EVENTS MARGIN TO OVERFILL ANALYSIS M

Time 1sec)

, SG. Tube Rupture 0

Reactor Trip, 83 L.

Safety Injection-222 Ruptured SG Isolated 815 RCS Cooldown Initiated 1297 1

l atCS'Cooldown Terminated -

2338

RCS Depressurization. Initiated 2476 RCS_Depressurization Terminated 2582 L

SI Terminated 2762 Break Flow Terminated 3464 l'

l' 1

L 2120v:1D/111389 17

,e f :.

)--

84 an0N MhRRIS SOTR aNALytlS.

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TIMEtSCCI s

Figure II.1 Pressortaer Level - Stargin to Overft11 Analysts 2120v:10/092789 18

E t,

I M an0N MARRll SSTR ANALYS $

+

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.t Figure 11.1 ACS Pressure - Margin to Overf111 Analysis I

- 2120v:10/092789 19

c.,.

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n

$4 ARON MARRIS SGTR ANALYS1$

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l t

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TIEtKCl 1

Figure II.3 Secondary Pressure - Margin to Overft11 Analysis 1

i -

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4 9 4 an0N NAHRll SoTR ANALYS!$

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L TIEISCCI

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Figure II.4 Intact Loop Not and Cold Leg RCS Temperatures -

Margin to Overft11 Analysts I

- 2120v:10/092789 21

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. o gesee0N MARRI$ $$TR ANALY$16

98. <

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TitEtSCCI Figure 11.5 Primary to Secondary Break Flow Rate -

Margin to Overf111 Analysis 4

2120v:1D/092789 22

. =....

=.

_. ~

k l'

-1 4

i 98EARON MARR)$ SGTR ANALYS!$

Model 04 SG Secondary Volume sees.,,_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.

i-

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TltEtSCC) l Figure II.6 Ruptured SG Nater Volume - Margin to Overft11 Analysts 2120v:1Dl092189 23

\\

~. - -.

f

-III'.

ANALYSIS OF 0FFSITE RADIOLOGICAL CONSEQUENCES i

.An analysis was performed to determine the offatte radiological consequences.

~

ifor a design. basis SGTR for SHNPP. The thermal and hydraulle and the offsite-radiation dose analyses were performed'using the methodology developed in References 2 and 3 and the plant specific parameters for SHNPP.

A.. Thomal and Hydraulie Analysis -

2 The plant response, the integrated primary to secondary break flow and the i

mass releases _from the ruptured and intact steam generators to the j

condenser and to the atmosphere until break flow termination were calculated with the LOFTTR2 program for use in calculating the offsite radiation doses.. This section provides a discursion of the methods and assumptions used'to analyze the SGTR event and to calculate the mass releases.the sequence of events-during the recovery operations, and the calculated results.

~

1.---Desian Basis Accident The accident modeled is a double-ended break of one steam generator

~

tube located at the top of the tube sheet on the outlet (cold leg) side of the steam generator, L

]*ftwasalsoassumedthatlossofoffsite

-power occurs at the time of reactor trip and the highest worth control

. assembly was assumed to be. stuck in its fully withdrawn position at reactor trip.

Based on the information in Reference 3, the most limiting single

failure with respect to offsitt doses for SHNPP is a failed open PORV on the ruptured steam generator. Failure of this PORV will cause an uncontrolled depressurization of the ruptured steam generator which I

l 2120v:1D/111389.

24

... ~ -.. -...

'4 l

c 1

will increase primary to secondary leakage and the mass release to the

~

atmosphere. : Pressure in the ruptured steam generator will remain

{

below that in the primary system untti the failed PORV is isolated by l

locally closing the associated block valve, and the recovery actions are completed. Thus, for the offsite dose analysis, it was assumed-that the ruptured steam generator PORY fails open and must be locally i

isolated.

n

!~

2.

Conservative Ats - tions Most of the conservative conditions and assumptions used for the margin to cverf111 analysis are also conservative for the offsite dose analysis and thus most of the'same assumptions were used for both analyses. The major differences in the assumptions which were used

-for the LOFTTR2' analysis for offsite doses are discussed below.-

a.

Reactor Trin and Turbine Runback An earlier reactor trip is conservative for the offsite dose J

analysis, similar to the case for the overf111 analysis. Due to the assumed loss of offsite power, the condenser is not available for steam releases once the reactor is tripped. Consequently, after reactor trip, steam is released to the atmosphere through the steam generator PORVs (and safety valves if their setpoints are reached). Thus an earlier trip time leads to more steam released to the atmosphere from the ruptured and intact steam generators. Thus, the time of the reactor trip was calculated by modeling the SHNPP_ reactor protection system, and this time was also used for the offsite dose analysis.

]s c.Itisnotedthatamoreconservative overtemperature delta-T trip setpoint was used for the offsite dose analysis which results in an earlier reactor trip than for the margin to overfill analysis.

i 2120v:1D/092989 25

+ -. -,

,c.

,,-,.,-m-

,,,-.-,r--

.--,m

m b.

Steam Generator Recondarv Matt If steam generator overfill does,not occur, a results in a conservative.

prediction of offsite doses. Eus, for the offsite dose analysis, theinitialsecondarymasswasassumedtocor,rgspondtooperation at nominal steam generator mass minus a aflowancefor uncertainties. As noted above.

j

c.

AFW Systen Onoration

}a,c L

In Reference 3, it was determined that a L

results in an increase in the calculated offsite radiation doses

[

foraQGTR,whereasitwaspreviouslyconcludedthat

, is conservative for the margin to overfill analysis.

l However, it was also demonstrated in Reference 3 that a p

ince the single failure assumed for the offsite radiation dose analysis is a failed open PORY on the ruptured steam generator 'it is not necessary to assume an additional failure in l

the AFW system. Thut,, the turbine-driven pump and both motor-driven pumps were assumed to deliver flow to the three steam generators, but a conservative minimum AFM flow of 400 gpm per i

steam generator was assumed for the offsite radiation dose analysis. The delay time assumed for delivery of the AFN flow was n

conservatively b

] *s t-l' 1

2120v:1D/111389 26 u

,;i a

i l

d.

Flashina Fraction When calculating the amount of break flow that flashes to steam.

1100 percent of the break flow is assumed to come from the hot leg side of the breakI

~$Incethetube ruptureflowactuN1yconsistsofflowfromtfIehotlegandcold leg sides of the steam generator, the temperature of the combined flow will be less than the hot leg temperature and the flashing fraction.will be correspondingly lower. Thus the assumption that t

100 percent of the break flow comes from the hot leg is j.

conservative for the SGTR analysis.

3.

Onorator Action Times The major operator actions required for the recovery from an SGTR are discussed in Section II.C and the operator action times used for the overfill analysis are presented in Table 11.1. The operator action times assumed for the overfill analysis were also used for the offsite dose analysis. However, for the offsite doses analysis, the PORV on the ruptured steam generator was assumed to fall open at the time the ruptured steam generator is isolated. Before proceeding with the recovery operations, the failed open PORV on the ruptured steam generator is assumed to be isolated by locally closing the associated block valve. Carolina Power and Light Company has determined that an j.

operator can locally close the ruptured SHNPP steam generator PORV block valve within 20 minutes after the failure. Thus, it was assumed that the ruptured steam generator PORV is isolated at 20 minutes after the valve is assumed to fail open. After the ruptured steam generator PORV is isolated, the additional delay time of 8 minutes and 1.second (Table II.1) was assumed for the operator action time to initiate the RCS cooldown.

li l

h L

h

'2120v:10/092989 27 l

....c t 4.

Trantient Descrintion The L0rTTR2 analysis results for the offsite dose evaluation are described below. The sequence of events for the analysis of the-offsite radiation doses is presented in Table 111.1. It is noted that reactor trip occurs earlier for this case compared to the overfill analysis due to the more conservative overtemperature delta-T trip setpoint. The transient results for this case are similar to the transient results for the overfill analysis until-the ruptured steam generator is isolated. The transient behavior is different after this time since it is assumed that the ruptured steam generator PORV fails open at that time.

l Following the tube rupture the RCS pressure decreases as shown in L

Figure III.1 due to'the primary to secondary leakage. In response to i.

this depressurization, the reactor trips on overtemperature delta-T.

E After reactor trip, core power rapidly decreases to decay heat levels-and the RCS depressurization becomes more rapid. The-steam dump system is inoperable due to the assumed loss of offsite power, which results in the secondary pressure rising to the steam generator PORV setpoint as shown in Figure III.2. The decreasing pressurizer.

pressure leads to an automatic SI signal on low pressurizer pressure.

Pressurizer level also decreases more rapidly following reactor trip as shown in Figure III.3.

L L

MajorOperatorActions l

1.

Identify and Isolate the Ruptured Steam Generator

'The ruptured steam generator is assumed to be identified and 1solated at 13 minutes and 35 seconds after the initiation of the SGTR or when the narrow range level reaches 301, whichever time is j

greater. Since the time to reach 301 narrow range level is less L

than 13 minutes and 35 seconds, it was assumed that the ruptured L

steam generator is isolated at 13 minutes and 35 seconds. The

/

2120v:1D/111389 28 l

actuallisolation time used in the analysis is 13 minutes and 36 seconds be:ause of the compulcr program limitations for simulating operator actions. The ruptured steam generator PORV is'also assumed to fail open at this time, and the failure is simulated at 820 seconds because of the computer program limitations. The failure causes the ruptured steam generator'to rapidly depressurize, which results in an increase in primary to secondary leakage. The depressurization of the ruptured steam generator increases the break flow and energy transfer from primary to secondary which results in a decrease in the ruptured loop temperatures as shown in Figure 111.4. The intact steam generator loop temperatures ~also decrease, as shown in Figure III.5, until the AFM flow is controlled-to maintain the specified-level in the intact steam generators. As the intact steam generator loop hot leg temperature decreases below the steam generator water

]

L

' temperature, reverse heat transfer takes place for a short time period as shown in Figure 111.5.

It is assumed that the time required for the operator to identify that the ruptured steam generator PORV is open and to locally close the associated block valve is 20 minutes. However, the actual time used in the analysis is 2' seconds longer because of the computer program limitations. Thus, at 2022 seconds the depressurization of ruptured steam generator is terminated.

2.

Cool Down the RCS to establish Subcooling Margin After the ruptured steam generator PORY block valve is closed, there is a 8 minute and I second operator action time imposed prior to initiation of cooldown. However, the actual time used in the analysis is 8 minutes and 2 seconds because of the computer program limitations for simulating operator actions. The depressurization of the ruptured steam generator affects ths RCS cooldown target temperature since the temperature is dependent upon the pressure in the ruptured steam generator. Since offsite power is lost, the RCS is cooled by dumping steam to the atmosphere using the intact steam generator PORVs. The cooldown

.2120v:1D/111389 29

'*-w k

nv-v

<--,e,-no,e-mms.,m,s.,-en,-

1 i

is continued until RCS subcooling at the ruptured steam generator pressure is 20*F plusLan allowance for instrument uncertainty.

'Because of.the lower pressure in the ruptured steam generator the associated temperature the RCS must be cooled to is also lower, l

.which has.the not effect of extending the time for cooldown. The cooWown is initiated at 2504 seconds and is completed at 3540 seconds.

j The reduction in the intact steam generator pressures required to accomplish the cooldown is shown in Figure III.2, and the effect -

1 of the cooldown on the RCS temperature is shown in Figure III.5.

The RCS pressure.and pressurizer level also decrease during this cooldown process due to shrinkage of the reactor coolant as shown in Figures III.1 and III.3.

L L

3.

Depressurize RCS to Restore Inventory L

After the RCS cooldown, a 2 minute and 16 second operator action time is included prior to the RCS depressurization. However, the actual time used in the analysis is 2 minutes and 20 seconds because of the computer program limitations for simulating operator actions. ' The RCS is depressurized to assure adequate

=

coolant inventory prior to terminating SI flow. With the RCPs l-stopped, normal. pressurizer spray is not available and thus the RCS is depressurized by opening a pressurizer PORV. The RCS depressurization is initiated at 3680 seconds and continued until any of the following conditions are satisfied:. RCS pressure is U

less than the ruptured steam generator pressure and pressurizer level is greater than 101, or pressurizer level is greater than 7$%, or RCS subcooling is less than 20*F. For this case, the RCS depressurization is terminated because the RCS pressure is reduced to less than the ruptured steam generator pressure and the pressurizer level is above 101. The RCS depressurization reduces the break flow as shown in Figure III.7 and increases SI flow to refill the pressurizer as shown in Figure III.3.

L 2120v:1D/111489 30

4.

Terminate $1 to Stop Primary to Secondary Leakage The previous actions establish adequate RCS subcooling, a i

secondary side heat sink, and sufficient reactor coolant inventory to ensure that SI flow is no longer needed. When these actions have been completed, the $1-flow must be stopped to prevent repressuri s tion of the RCS and to terminate primary to secondary leakage. The SI flow is terminated at this time if RCS subcooling is greater than 20'F, minimum AFM flow is available or at least L

one intact ' steam generator. level is in the narrow range, the RCS i:

. pressure is stable or increasing, and the pressurizer level is greater than 101. For the SHNPP analysis, SI was not terminated.

q until the RCS pressure increased to 50 psi above the ruptured.

l steam generator pressure to assure that RCS pressura is increasing.

.q

After depressurization is completed, an operator action time of 3 minutes was assumed prior to initiation of SI termination.

j Since the above requirements are satisfied. SI termination actions

'were performed at this time by closing off the SI flow path'.

After SI termination the RCS pressure begins to decrease as shown in Figure III.1. The intact steam generator PORVs are also opened to dump steam to maintain the prescribed RCS temperature to ensure that subcooling is maintained. When the PORVs are opened, the increased energy transfer from primary to secondary also aids in the depressurization of the RCS to the ruptured steam generator pressure. The differential pressure between the RCS and the ruptured steam generator is shown in Figure III.6. Figure III.7 shows that the primary to secondary leakage continues after the SI flow is stopped until the RCS and ruptured steam generator pressures equalize.

The ruptured steam generator water volume is shown in Figure III.8.

For this case, the water volume in the ruptured steam generator when the break flow is terminated is less than the volume for the margin to overfill case and significantly less than the total steam generator 3

volume of 5949 ft. The mass of water in the ruptured steam generator is also shown as a function of time in Figure III.9.

2120v:1D/111389 31

.a

l TABLE.III.1, SNNPP SGTR ANALYSIS SEQUENCE OF EVENTS OFFSITE RADIATION DDSE ANALYSIS TIME (toc) l DEMI SG Tube Ruptrre 0

e l

Reactor Trip 39 t

Safety Injection 230 Ruptured SG Isolated 816 Ruptured SG PORV Fails Open 820-Ruptured SG PORV'81ock Valve Closed 2022 RCS Cooldown Initiated

.2504 RCS Cooldown Terminated 3540 RCS Depressurization Initiated 3680 RCS Depressurization Terminated 3746 SI Terminated 3926 Break Flow Terminated 4848

.2120v:1D/092989.

32

~

'. ' I _

-:-.s

_j a

SHEARON MARRIS STEAM GENERATOR TURE PUPTURE i

f '-

3500.<

'3300.'

y 3100.<

J 2000.'

4 E 18l00.<

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b!

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1-1980.'

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1000.-

2000.

3000.

4000.

5000.

TIfE ISCC) t L

L:

l Figure III.1 RCS Pressure - Offsite Radiation Dose Analysts 1.

J s

1.

j.-;

1120v:10/092789 33

... ~.

3

'k, w

i

, e -.

.SHEARON MARR15 STEAM DENERATOR TUBE RUFTURE a

a.

s z

idee <

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INTACT SG

.isete..

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.see.<

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.g W '498.<

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Figure 111.1 Secondary Pressure - Offsite Radiation Dose Analysis-1

(.

li i

t.

2120v:10/092789 34

i 40

'l t

1 SHEARON' HARRIS STEAf1 GENERATOR TUBE RUPTURE t

I k

4 J

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.n.

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0.

1000.

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4000.

5000.

-E TIfE IKCl Figure III.3 Pressortaer Level - Offstte Radiation Dose Analysts 2120v:10/092789 35 r

a

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

.~

.-. -.. ~

cc-f l

i

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s,

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1

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SHEAR 0N MARRIS STEAN GENERATOR TUBE RUPTURE 1.

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ses.'

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4000.

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l i

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Figure III.4 tuptured Loop Not and Cold Leg RCS Temperatures -

I O Ms1to Radtation Dose Analys1s 4

4 i

212Cv:10/092789 36

i I

r SHEAR 0N MARRIS STEnti OENERATOR TUBE RUPTURE t

?

ess '

,; 1 f.;

480.<

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e.

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L 400,-

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8000.

4000.

0000.

TIE tKCl Figure !!!.5 Intact Loop Not and Cold Les RCS Temperatures -

Offsite Radiation Dose Analysis 1'

i l

o

.2120v:10/092789 37 a.

i l

1 i

)

SHEARON MARRIS STEAM GENERATOR TUBE RUPTURE l

1 i

8480.<

l Itte.'

l i

180D.<

.f900.'

1 400.<

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i l

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5000.

, TIE IKCl i

Figure !!!.6 Differential Pressure between RCS and Ruptured SG -

Offstte Radiation Dose Analysis t

2120v:10/092789 38

L r

i

't SHEARON MARR15 STEAM GENERATOR TURE RUFTURE i

l 70.'

i St.<

l l

80.<

1 u

$'40.'

l i

SS.'

g g 29.<

l 30.'

O.<

+ 30 *0.

4000.

8000.

0000.

4000.

8000.

TIfE tatC) 1 Figure !!!.7 Primary to Secondary treak Flow Rate -

Offs 1to Radtat1on Dose Analysis 1120v:10/09t?89 39

i l

SHEARON MARRIS STEAM GENERATOP TUSE RUPTURE i

i i

SCOS.'

l ef00.'

T 4000.<

Sf00.'

i gSpec.<

f af00.<

8088.'

f i

4500*0.

4000.

8000.

3000, 4000.

5000.

TIE lEcl F1 pure III.8 Ruptured SG Mater Volume - Offsite Radiation Dose Analysis l

l 2120v:10/092789 40 1

I+.

. ~.. _ ~ -,

. - ~..

_.~......,_,..-..~,__._....__....,..m-e

~

s 4

i h ::

. i SHEARON HARRIS STEAM GENERATOR TUBE RUPTURE i

i

'349003.<

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i i

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S t

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4000.

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0000.

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I 1

Ftture III.9 Ruptured SG letter plass - Offstte Radiation 00se Analysts e

t tit 0v:10/092789 41

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

w...

,,,.__,_,.,____._..._,-.~.,v...%,,..,,

. c,2 5.

iku Enlaatet

[

I The mass releases were determined for use in evaluating the exclusion l

area boundary and low population zone radiation exposure. The steam releases from the ruptured and intact steam generators, the feedwater l

flows to the ruptured and intact steam generators, and primary to l

secondary break flow into the ruptured steam generator were determined l

for the period from accident initiation untti 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after the accident and from 2 to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the accident.- The releases for 0-2 hours are used to calculate the radiation doses at the exclusion

{

area boundary for a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months exposure, and the releases for 0-8 hours are used to calculate the radiation doses at the low population zone i

for the duration of the accident.

(

l.

In the LOFTTR2 analysis, the SGTR recovery actions in SHNPP E0P -

l Path 2 (ERG E-3) were simulated until the termination of primary to f

l secondary leakage. After the primary to secondary leakage is l

terminated, the operators util continue the SGTR recovery actions to prepare the plant for cooldown to cold shutdown conditions. When these recovery actions are completed, the plant should be cooled and i

depressurtred to cold shutdown conditions.

]Ngwas assumed that the cooldown is performed using SHNPP E0P-EPP-019 (ERG ES-3.3), POST-SGTR C00LDOWN USING STEAM DUMP, since this method results in a conservative evaluation of the long term mass releases for the offsite dose analysis.

The high level actions for the post-SGTR cooldown method using steam dump in SHNPP E0P-EPP-019 (ERG ES-3.3) are discussed below.

l 1.

Prepare for Cooldown to Cold shutdown The initial steps to prepare for cooldown to cold shutdown will be continued if they have not already been completed. A few additional steps are also performed prior to initiating cooldown.

l 2120v:1D/092989 42

.i l

i These include isolating the cold leg SI accumulators to prevent unnecessary injection, energizing pressurtzer heaters as necessary to saturate the pressurtzer water and to provide for better pressure control, and assuring adequate shutdown margin in the l

event of potential boron dilution due to in-leakage from the l

[

ruptured steam generator; 2.

Cooldown RCS to Residual Heat Removal (RNR) System Temperature i

The RCS 1s cooled by steaming and feeding the intact steam generators sistlar to a normal cooldown. Since all tamediate l

s'afety concerns have been resolved, the cooldown rate should be maintained less than the m'ximum allowable rate of 100'F/hr. The a

preferred means for cooling the RCS is steam dump to the condenser since this minimizes the radiological releases and conserves feedwater supply. The PORVs for the intact steam generators can also be used if steam dump to the condenser is unavailable. Since a loss of offsite power is assumed for the SNNPP analysts, it was l

assumed that the cooldown is performed using steam dump to the atmosphere via the intact steam generator PORVs. When the RNR system operating temperature is reached, the cooldown is stopped untti RCS pressure can also be decreased. This ensures that pressure / temperature Itatts will not be exceeded.

L 3.

Depressurtre RCS to RHR System Pressure When the cooldown to RHR system temperature is completed, the t

pressure in the ruptured steam generator is decreased by releasing steam from the ruptured steam generator. Steam release to the condenser is preferred since this minimizes radiological releases, but steam can be released to the atmosphere using the PORV on the ruptured steam generator if the condenser is not available.

Consistent with the assumption of a loss of offstte power, it was assumed that the ruptured steam generator is depressurtred by l-l 2120v:10/092989 43

releasing steam via the PORV. As the ruptured steam generator pressure is reduced, the RCS pressure is maintained equal to the pressure in the ruptured steam generator in order to prevent in-leakage of secondary side water or additional primary to secondary leakage. Although normal pressurizer spray is the preferred means of RCS pressure control, auxiliary spray or a pressurizer PORV can be used to control RCS pressure if 3

pressuriser spray is not available.

)

4.

Cooldown to Cold Shutdown i

Mhen RCS temperature and pressure have been reduced to the RHR I

system in-service values, RHR system cooling is initiated to l

complete the cooldown to cold shutdown. Mhen cold shutdown conditions are achieved, the pressuriser can be cooled to j

terminate the event.

The methodology in Reference 3 was used to calculate the mass releases for the SHNPP analysis. The methodology and the results of the calculations are discussed below, s.

Methodology for Calculation of Mass Releases The operator actions for the SGTR recovery up to the termination

'of primary to secondary leakage are simulated in the LOFTTR2 l

analyses. Thus, the steam releases from the ruptured and intact steam generators, the feedwater flows to the ruptured and intact steam generators, and the primary to secondary leakage into the l

ruptured steam generator were determined from the LOFTTR2 results for the period from the initiation of the accident until the i

leakage is terminated.

i l

l-Following the termination of leakage, it was assumed that the RCS l

and intact steam g'e,nerator conditions are maintained stable for a

]untilthecooldowntocoldshutdownis

_initiated. The PORVs for the intact steam generators were then 2120v:1D/111389 44 L

f assumed to be used to cool down the RCS to the RHR system l

I operating temperature of 350'F, at the maximum allowable cooldown rate of 100'F/hr. The RCS and the intact steam generator i

temperaturesat2hourswerethendetermined{

l

]'desteamreieasesandthe feedwater flows for the intact steam generator for the period from leakage termination ~until 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months were determined from

- e,e.

l Since the ruptured steam generator is isolated, no change in the f

~

ruptured steam generator conditions is assumed to occur untti subsequent depressurization.

i l

The RCS cooldown was assumed to be continued after 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months untti L

the RHR system in-service temperature of 350'F is reached.

Depressurization of the ruptured steam generator was then assumed to be performed immediately following the completion of the RCS cooldown. The ruptured steam generator was assumed to be der.tnssurized to the RNR in-service pressure of 375 psia via steam reluase from the ruptured steam generator PORV, since this maximites the steam release from the ruptured steam generator to the atmosphere which is conservative for the evaluation of the offsite radiation doses. The RCS pressure is also assumed to be reduced concurrently as the ruptured steam generator is depressurtred. It is assumed that the continuation of the RCS cooldown and depressurization to RHR operating conditions are completed within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the accident since there is ample I

time to complete the operations during this time period. The steamreleasesandfeedvaterflowsfrom3to8purswere determined for the intact steam generator from

~*desteamreleased

~

from the ruptured steam generator from 2 to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months was determined based on

- a6 2120v:1D/111389 45

i After 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , it is assumed that further plant cooldown to cold shutdown as well as long-term cooling 15 provided by the RHR j

system. Therefore, the steam releases to.the atmosphere are terminated after RNR in-service conditions are assumed to be reached at 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

b.

Mass Release Results j

The mass release calculations were performed using the methodology j

discussed above. For the time period frau initiation of the

)

accident untti leakage termination, the releases were determined j

from the LOFTTR2 results for the time prior to reactor trip and I

following reactor trip. S'ince the condenser is in service untti reactor trip, any radioactivity released to the atmosphere prior to reactor trip will be through the condenser vacuum pump j

exhaust. After reactor trip, the releases to the atmosphere are j

assumed to be via the steam generator PORVs. The mass release rates to the atmosphere from the LOFTTR2 analysis are presented in Figures-111.10 and III.11 for the ruptured and intact steam j-generators, respectively, for the time period untti leakage termination.

The mass releases calculated from the time of leakage termination untti 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and from 2-8 hours are also assumed to be released to the atmosphere via the steam generator PORVs. The mass releases for the SGTR event for each of the time intervals considered are presented in Table !!!.2. The mass releases prior to break flow termination, from break flow termination untti 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , and from 2 to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months are summartred in Table III.3. The results indicate that approximately 111,000 1he of steam are released from the ruptured steam generator to the atmosphere in the first 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . A total of 202.800 1he of primary water is transferred to the secondary side of the ruptured steam generator before the break flow is terminated.

]

1 2120v:10/0g2g89 46

4 m

i~

TA8LE !!!.2 SMNPP SGTR ANALYS15 b6 Ass RELEAsts OFFsITE RADIATION Dott ANALYEls TOTAL MASS FLOW (POUNDS)

TIME PERIOD 0-TRIP TRIP -

TMSEP -

TTBRK -

T2HR$ -

TMSEP TTBRK T2HR$

TRHR Ruptured SG Condenser 45,500 0

0 0

0 Atmosphere 0

110,500 500 0

37,800 Feedwater 43,400 50,400 0

0 0

Intact SG Condenser 90,300 0

0 0

0 Atmosphere 0

155,400 31,300 150,000 775,000 Feedwater 90,300 281,900 21,500 156,600 783,000 Break Flow 2,100 188,200 12,500 0

0

. TRIP

= Time of reactor trip = 39 sec.

TMSEP = Time when water reaches the moisture separators = 3953 sec.

TTBRK Time when break flow is terminated 4848 sec.

T2HR$ = Time at 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months 7200 sec.

TRHR

= Time to reach RHR in-service conditions, 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months = 28,800 sec.

2120v:10/092989 47

i i

TABLE 111.3 i

ENNPP EGTR ANALYSIS SUMARIZED Matt RELEASES DFF11TE RADIATION D01E ANALYSIS TOTAL MASS FLON (POUNDS) f O-TTBRK --

2HR$ -

TTBRK 2 HRS SMRS i

Ruptured SG Condenser 45,500 0

0 Atmosphere 111,000 0

37,800 Feedwater 93,800 0

0 Intact.SGs l

l Condenser 90,300 0

0 Atmosphere 186,700 150,000 775,000 Feedwater 393,700 156,600 783,000 l--

Break Flow 202,800 0

0 i

n 2120v:1D/092989-48

~.

) %

l l

i l

i t

$MEARON MARRIS STEAti GENEPATOR TUBE RUPTURE l

2 I

700.<

f u 480.<

Y i

t s

g180..

5.e..

i e

k!

500.-

a 280.<

S I100.'

\\

hk

. e '8.

8000.

3088.

8084.

ette.

5888.

Taft 19tti Figure !!!.10 Ruptured SG Nass Release Rate to the Atmosphere -

Offstte Radiation Dose Analysts l

2120v:10/092789 49

SHEARON MARR15 STEAM OENERATOR TUDE RUPTURE 4.

tatt.

U Q ta:o. I

-$1000.'

b t

e30.'

u i

890.<

480.<

h il888.<

g L

0*g. A i

tese.

8088.

8000.

4808.

6099.

THE 19CCI Figure !!!.11 Intact SGs Hans Release Rate to the Atmosphere -

Offsite Radiation Dose Analysis i

2120v:10/092789 50 nim i

l L

B.

Offsite Radiation Dose Analysis The evaluation of the radiological consequences of a steam generator tube rupture, assumes that the reactor has been operating at the Technical Specification limit for primary coolant activity and primary to secondary leakage for sufficient time to establish equilibrium concentrations of radionuclides in the reactor coolant and in the secondary coolant.

Radionuelldes from the primary coolant enter the steam generator, via the ruptured tube, and are released to the atmosphere through the steam generator safety or power operated reitef-valves and via the condenser vacuum pump exhaust.

The quantity of radioactivity released to the environment, due to a SGTR, depends upon primary and secondary coolant activity, todine spiking effects, primary to secondary break flow, break flow flashing fractions, attenuation of todine carried by the flashed portion of the break flow, partitioning of todine between the liquid and steam phases, the mass of fluid released from the generator and liquid-vapor partitioning in the turbine condenser hot well. All of these parameters were conservatively evaluated for a design basis double ended rupture of a single tube.

1.

botton Batit Analvtical Attin=ations The major assumptions and parameters used in the analysis are itemized in Table 111.4.

2.

Source Tara calculations The radionuclide concentrations in the SHNPP primary and secondary system, prior to and following the SGTR are determined as follows:

a.

The iodine concentrations in the reactor coolant will be based upon preaccident and accident initiated lodine spikes.

i

-2120v:10/092989 51

1.

Accident Initiated Spike - The initial primary coolant todine concentration is 1 pct /gm of Dose Equivalent (D.E.) 1-131.

Following the primary system depressurization associated with the SGTR, an todine spike is inttlated in the primary system which increases the todine release rate from the fuel to the coolant to a value 500 times greater than the release rate corresponding to the initial primary system iodine Thedurationofthespike,{

is concentration.

suffletent to increase the initial RCS 1-131 inventor [by a factorof{

it. Preaccident Spike - A reactor transient has occurred prior to the SGTR and has raised the primary coolant todine contantration from I to 60 pC1/ gram of D.E.1-131.

b.

The initial secondary coolant todine concentration is 0.1 pC1/ gram of 0.E.1-131.

The chemical form of iodine in the primary and secondary coolant c.

is assumed to be elemental.

d.

The initial noble gas concentrations in the reactor coolant are based on 11 fuel defects.

3.

Date Calculattant The iodine transport model ut111 red in this analysis was proposed by postma and Tam (Reference 6). The model considers break flow flashing, droplet size, bubble scrubbing, steaming, and partitioning.

The model assumes that a fraction of the todine carried by the break flow becomes airborne immediately due to flashing and atomiziation.

Removal credit is taken for scrubbing 0f iodine contained in the atcaired coolant droplets when the rupture site is below the secondary water level. The fraction of primary coolant todine which is not assumed to become airborne immediately mixes with the secondary water i

2120v:10/092989 52

/

j and is assumed to become airborne at a rate proportional to the steaming rate and the iodine partition coefficient. This analysis conservatively assumes an todine partition coefficient of 100 between the steam generator liquid and steam phases. The model takes no e

scrubbing or mixing credit when the rupture site is above the secondary water level. Droplet removal by the dryers is conservatively assumed to be negligible. The iodine transport model is illustrated in Figure III.12.

The following assumptions and parameters were used to calculate the activity released'to the atmosphere and the offsite doses fo11owing a SGTR.

a.

The mass of reactor coolant discharged into the secondary system through the rupture and the mass of steam released from the ruptured and intact steam generators to the atmosphere are presented in Table III.2.

1 b.

The time dependent fraction of rupture flow that flashes to steam and is immediately released to the environment is presented in Figure III.13. The break flow flashing fraction was conservatively calculated assuming that 100 percent of the break flow comes from the hot leg side of the steam generator, whereas the break flow actually comes from both the hot leg and cold leg sides of the steam generator.

c.

In the iodine transport model, the time dependent todine removal J

efficiency for scrubbing of steam bubbles as they rise from the rupture site to the water surface conservatively assumes that the rupture is located at the intersection of the outer tube row and the upper anti-vibration bar. However, the tube rupture break flow was conservatively calculated assuming that the break is at the top of the tube sheet. The water level relative to the top of the tubes in the ruptured and intact steam generators is shown J

l.

2120v:1D/101189 53

-~

l

.i i

i In Figure !!!.14. The lodine scrubbing efficiency is determined i

by the method suggested by Postma and Tan (Ref. 6). The iodine scrubbing efficiencies are shown in Figure !!!.15.

The activity released to the environment by the flashed rupture flow can be written as follows:

]

A*

IA II ~ 'II )

r j

j

[

where:

total todine released to the environment by flashed A

=

r primary coolant j

(integrated activity in rupture flow during time IA)

=

intervalj)(flashingfractionfortimeintervalj) l lodine scrubbing efficiency during time interval j eff)

=

b d.

The rupture site is considered to be uncovered when the secondary water level is less than approximately 12 inches over the rupture site, which, as stated above, is assumed to be at the intersection of the outer tube row and the upper anti-vibration bar (approximately 3 inches below the apex of the tube bundle).

7 During the time that the rupture site is uncovered (from approximately 80 to 140 seconds), all of the activity carried by the break flow is assumed to be directly released to the environment, i.e., the activity carried by the break flow will neither six with the secondary nor partition.

[

1 2120v:10/092989 54

l s-I e.

The total primary to secondary leak rate 1s assumed to be 1.0 ppm l

as allowed by the SHNPP Technical Specifications. The leak rate is assumed to be 0.35 gpm for each of the intact steam generators and 0.3 gpa for the ruptured steam generator.

T'he leakage to the l

intact steam generators is assumed to persist for the duration of 4

the accident.

i f.

The lodine partition factor between the liquid and steam of the ruptured and intact steam generators is assumed to be 100.

l g.

No credit was taken for radioactive decay during release and i

transport, or for cloud depletion by ground deposition during transport to the site boun'dary or outer boundary of the low population zone, i

h.

Short-term atmospheric dispersion factors (m/Qs) and breathing rates are provided in Table III.8. The breathing rates were j

obtained from NRC Regulatory Guide 1.4, (Ref. 7).

i 4.

Offsite Thyroid Date Calculation Model 9

Offsite thyroid doses are calculated using the equation:

1 IIA")1)

(E bh j

j

.,e,e integrated activity of isotope i released during the (IAR)g)

=

time interval j in Cl*

l I No credit is taken for cloud depletion by ground deposition or by t

radioactive decay during transport :o the exclusion area boundary or to the outer boundary of the low-population zone.

1

(

i 2120v:1D/092989 55

a breathing rate during time interval j in (BR))

=

3 meter /second (Table III.8)

)

atmospheric dispersion factor during time interval j (x/Q))

=

in second/ meter 3 (Table III.8) thyroid dose conversion factor via inhalation for

]

(DCF)g

=

tsotope t in res/C1 (Table !!!.g)

{

i i

thyroid dose via inhalation in rem j

D

=

Th 4

Offsite whole-body gamma doses are calculated using the equation:

I i

i y

,g

(!AR)q) (x/Q)3 D. 0.25 o

where:

]

integrated activity of noble gas nuclide i (IAR)g)

=

released during time interval j in C1

atmospheric dispersion factor dusing time (x/Q))

=

3 interval j in seconds /m E

average gamma energy for noble gas nuclide 1 in

=

7g Nev/dls (Table III.10)

D whole body gamma dose due to immersion in res y

=

l No credit is taken for cloud depletion by ground deposition or by l

radioactive decay during transport to the exclusion area boundary or to the outer boundary of the low-population zone.

J l

l l

2120v:1D/092989 56

4 L

offsite beta-skin doses are calculated using the equation:

0 = 0.23 g

(Wgg (W3 8

where:

integrated activity of noble gas nuclide 1 (IAR)q

=

released during time interval j in C1

atmospheric dispersion actor during time (x/Q))

=

interval j in seconds /m 5

average beta energy for noble gas nuclide 1 in

=

61 Mev/ dis (Table !!!.10) beta-skin dose due to immersion in rem 0

=

6 No credit is taken for cloud depletion by ground deposition or by radioactive decay during transport to the exclusion area boundary or to the outer boundary of the low-population zone.

5.

Results Thyroid, whole-body gamma, and beta-skin doses at the Exclusion Area Boundary and Low Population Zone are presented in Table !!!.11. All doses are well within the allowable guidelines as specified by Standard Review Plan 15.6.3 and 10CFR100.

2120v:1D/092989 57

-4 TABLE 111.4 EMMPP 1CTR ANALYS11 PARAMETERS USED IN EVALUATING RADIOLOGICAL CDNSEQUENCES 1.

Source Data A.

Core power level. Seit 2785 B.

Total steam generator tube 1.0 leakage, prior to accident, spo C. ' Reactor coolant iodine activity:

1.

Accident Initiated Spike The initial RC iodine activities based on 1 pCi/ gram of 0.E. 1-131 are presented in Table 111.5. The iodine appearance rates assumed for the accident initiated spike are presented in Table !!!.6.

2.

Pre-Accident Spike Primary coolant iodine activities based on 60 pC1/ gram of 0.E. I-131 are presented in Table 111.5.

3.

Iloble Gas Activity The initial RC noble gas activities based on 1%

fuel defects are presented in Table 111.7.

2120v:1D/101189 58

=- -

l i

TABLE !!!.4 (Sheet 2) l D.

Secondary system initial activity Dose equivalent of 0.1 i

pCi/gm of I-131 presented in Table !!!.$.

E.

Reactor coolant mass, grams 1.8 x 108 7

F.

Initial steam generator water mass 3.64 x 10 (each). grams I

G.

Offsite power Lost at time of reactor trip

.i j

N.

Primary-to-secondary leakage 8

l duration for intact SG, hrs.

l 1.

Species of iodine 100 percent elemental II.

Activity Release Data l

L 1

l A.

Ruptured steam generator

)

1.

Rupture flow See Table III.2 2.

Rupture flow flashing fraction See Figure III.13 I

1 3.

Iodine scrubbing efficiency See Figure III.15 4.

Total steam release, Ibs See Table III.2 L

5.

Iodine partition factor 100 2120v:1D/101189 59

TABLE !!!.4 ($heet 3) 6.

Location of tube rupture Intersection of outer tube row and upper

. anti-vibration bar

8.. Intact steam generators 1.

Total primary-to-secondary 0.7 leakage, gpa 2.

Total-steam release, Ib,s See Table !!!.2 3.

Iodine partition factor 100 C.

Condenser 1.

Iodine partition factor, 100 D.

Atmospheric Dispersion Factors See Table 111.8 2120v:1D/092989 60

TABLE III.5 ENNPP ECTR ANALY111 IODINE SPtt1FIC ACTIVITIES 6

IN THE Pk1 MARY AND ttrmnARY NLANT MARED DN 1. AD AND D.1 mC1/aram DF D.E.1 111 Eneelfte Activity fucil.p)

Primary relant tarandarv emlant flutlide 1 metlam 60Mlp D.1 mCilon I-131 0.77 45.9 0.077 I-132 0.79 47.5 0.079 I-133 1.14 68.1 0.114 I-134 0.16 9.5 0.016 I-135 0.61 36.4 0.061 2120v:1D/092989 61

I.

i TABLE III.6 EMNPP SGTR ANALYSIS 10 DINE SPIKE APPEARANCE RATES (CURIES /SECOND)

L-131 1.131 l=133 l=13A 1:135 1.36 7.35 2.87 3.39 2.62 1

2120v:10/092989 62 umii.-----w

TABLE 111.7 1HNPP SGTR ANALYSIS unalt GAS SPECIFIC ACTIVITIES IN THE REACTOR rnnLANT RATED ON 11 Furt DEFECTS e

gualida tascifte Aettwitv fact /na)

Xe-131m 2.3 Xe-133m 18.0 Xe-133 280.0 Xe-135m 0.5 Xe-135 7.7 Xe-138 0.67 Kr-85m 2.1 Kr-85 7.7 Kr-87 1.3 Kr-88 3.8 i

4 2120v:1D/092989 63

l TABLE 111.8 SHNPP $GTR ANALYSIS ATMDSPHERIC DISPERSJON FACTQRS AND BREATHING RATES l

1.13e Exclusion Area Boundary Low Population Breathing 3

3 3

-(hours) g/Q (Sec/m )

Zone g/Q (Sec/m )

Rate (m /Sec) (7) 0-2 6.17 x 10'4 1.4 x 10'4 3.47 x 10'4 i

s 2-8 1.4 x 10'4 3.47 x 10~4 f

i I

e t

2 I

l i

?

1' l

l 1

2120v:10/092989 64

. ~....

@? ' '

u

]

o y,

y _

TABLE III.9-j SHNPP SGTR ANALYSIS THYRDID DOSE Com'FR$10N FACTORS

+

-(Rem /Curte) [Ref;'83 I'

Mutlige s

i 6

I-131 1.49 x 10 ac

)

4 I-132' 1.43 x.10 ~

{

1 f

5 I-133 2.69 x 10 3

1-134 3.73 x 10 '

4 I-135 5.60 x 10 L

~' ).

F l

L l-l' L

l-L-

1,'

. 2120v:1D/092989 65

,w

,. +,,...., -,

..,..w,,

-v--

n

..p.

..t TABLE III.10 SHNPP SGTR ANALYSIS AVERAGE f.^.".".'. AND BETA ENERGY FOR NOBLE GASES (Nev/ dis) [Ref. 93

':Y Nuclide.

ly E3 Xe-131m 0.0029 0.165 Xe-133m 0.02 0.212 Xe-133-0.03 0.153 Xe-135m 0.43 0.099 Xe-135

'O.246 0.325 Xe-138 1,2-0.66

'Kr-85m 0.156 0.253 Kr 0.0023 0.251 Kr-87 0.793 1.33 Kr-88 2.21 0.248 l

1 l

l l,

2120v:1D/092989 66

TA8LE III.11

+

SHNPP SGTR ANALYSIS QFFSITE RADIATION DOSES Thyroid Dates (Rem) t Calculated Allowable Value Guideline Value [Ref 101

.[

-1.

Accident Initiated Indine Snike Exclusion Area Boundary (0-2 hr.)

Thyroid 16.6 30 Low Population Zone (0-8 hr.)

Thyroid 3.9 30

' 2.

Pre-Accident Iodine Snike Exclusion Area Bo'undary (0-2 hr.)

Thyroid 79.2 300 L

'Los Population Zone (0-8 hr.)

Thyroid 18.2 300-

3. Whole-Body ca-and Beta-Skin Dose L

Exclusion-Area Boundary (0-2 hr.)

ll Mhole-Body camma Dose 0.2-2.5*

Beta-Skin Dose 0.5-2.5*

h Low Population Zone (0-8 hr.)

Nhole-Body camma Dose 0.1 2.5*

Beta-Skin Dose 0.1 2.5*

Assumed to apply to the sum of the whole-body gamma and beta-skin doses.

2120v:1D/101189 67

,,7

s.

4 j

i l

L l'

I t-

-h i;

]

L g

g N

i i.

ensam T

E covensee o

ein e se a

t-noy SseoNoMEY d

y phAgMso g

!e,l tunTER u

l-m

P O

.a l

s c

P d

E M

E nasw a

e' ono E

tapen e SusMATB genAv -

ensmur esor PhasMso ano enops l

L l

e suunnen t'

l l

1 1'

l Figure III.12 Iodine Transport Model - Offsite Rcdiation Dose Analysis 1

\\

l 2120v:10/092909

,~ - i i

y

]

t

,P

'SHEARON HARRIS STEAM GENERATOR TUBE RUPTU#E f

i

. 10'

.;i?

~

.34<

5'

.it<

E 1<

q gl.06<

g:

.84-

j )_

.St<

08.

4000.

3000.

Bete.

4000.

5000.

-T!fE tKCli l!

Figure III.13 Break Flow Flashing Fraction - Offsite Radiation Dose Analysis 2120v:10/092789 69 i

w v-w w w -, e es, a----s v

.--~,w,-

,.,-er

cr g

.w p.

4 l "'

n.

c l

l y

s a

1 4

t,,,

l l~

SHEAR 0N HARRIS STEAf1 GENERATOR TUBE RUPTURE' o

b 27E.<

aso,<

E..

1

- 225.'

.i e

g...

Is17s..

-RUPTURED SG 154..

3 125.<

INTACT SG N isob x

75.<

.g-58..

al.'

'O.

8000.

3000.

M.

.4000.

8000.

TIE IEcl l

1:

1 Figure !!!.14 SG Mater Level Above Top of Tubes -

Mfsite Radiation Dose Analysis 4

-2120vi10/092789 70

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

e 4

r p:..

p L

0.08 lh SHERRQN mRRIS STERM GENERRTOR TLBE RUPTURE L

0.06 U

m

0.04 E

I.02 0

1 l

0.00 L

0 500 1000 1500 2000 2500 3000 t

TIME (SECONDS)

Ftgere III.15 Iodine scrubbing Effletency - Offstte Radiation Dose Analysts 2120v:10/092789 71

J IV. CONCLUSION.

An evaluation has been performed for a design basis SGTR for the Shearon Harris nuclear power plant to demonstrate that the potential consequences are acceptable. An analysis was performed to demonstrate margin to steam generator overfill with the limiting single failure relative to overf111.- The limiting single failure is the failure of T'he results of this analysis

~

indicate that the recovery actions can be completed to terminate the primary to secondary break flow before overfill of the ruptured steam generator would occur.

Since it is concluded that steam gener'ator overfill will not occur for a design basis SGTR, an analysis was also performed to determine the offsite radiation doses assuming the limiting single failure for offsite doses. For this analysis, it was assumed that the ruptured steam generator PORV fails open atLthe time the ruptured steam generator is isolated, and that the failed open PORV must be isolated by locally closing the associated block valve. The primary to secondary break flow and the mass releases to the atmosphere were determined for this case, and the offsite radiation doses were calculated using this information. The resulting doses at the exclusion area boundary

.and low population zone are within-the allowable guidelines as specified by Standard Review Plan 15.6.3 and 10CFR100. Thus, it is concluded that the consequences of a design basis steam generator tube rupture at the Shearon Harris plant would be acceptable.

i i

2120v:1D/092989 72

.e tV.

REFERENCES

-1.

Holderbaum, Lewis, Rubin, "LOFTTR2 Analysis For a Steam Generator Tube Rupture for'Shearon Harris Nuclear Power Plant," WCAP-11703

[ PROPRIETARY 3/NCAP-11704 [NON-PROPRIETARY), January 1988.

2.

Lewis, Nuang Behnke, Fittante, Gelman, "SGTR Analysis Methodology to Determine the Margin to Steam Generator Overf111," WCAP-10698-P-A

[ PROPRIETARY)/NCAP-10750-A [NON-PROPRIETARY), August 1987..

3.

Lewis, Nuang, Rubin, " Evaluation of Offsite Radiation Doses for a Steam Generator Tube Rupture Accident," Supplement 1 to NCAP-10698-P-A (PROPRIETARY]/ Supplement 1 of WCAP-10750-A [NON-PROPRIETARY), March 1986.

4.

Vantage 5 Reload Transition Safety Report for the Shearon Harris Nuclear

~ Power Plant. February 1989.

5.

NRC letter on Docket 50-400 from Bart C. Buckley (NRC) to E. E. Utley (Carolina. Power and Light Company), "Shearon Harris Nuclear Power Plant, Unit 1 - Steam Generator Tube Rupture Analysis," September 30, 1988.

6.

Postaa. A. K., Tam, P. S., " Iodine Behavior in a PMR Cooling System Following a Postulated Steam Generator Tube Rupture". NUREG-0409.

7.

NRC Regulatory Guide 1.4, Rev. 2. " Assumptions Used for Evaluating the potential Radiological Consequences of a LOCA for Pressurized Nater Reactors", June 1974.

8.

81RC Regulatory Guide 1.109, Rev.1. " Calculation of Annual Doses to Man From Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR Part 50 Appendix I", October 1977.

I 2120v:1D/092989 73

j e{+i'

+

^

9.'

Bell', M. J., "0RIGEN - The ORNL !sotope Generation and Depletion Code,"

l

0RNL-4628, 1973..

10. Standard Review Plan, Section'15.6-3, " Radiological Consequences of Steam.

Generator Tube Failure," NUREG-0800, July 1981.

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ATTACHMENT'3 SHNPP SGTR ANALYSIS a~

OPERATOR ACTION TIMES MARGIN TO OVERFILL ANALYSIS Action Times (Min: Secs) l

. Identify and isolate ~'

13:35'

. ruptured SG Operator. action time.to 8:01

. initiate cooldown 1

Cooldown*'

17:21 Operator action time to 2:16 initiate depressurization Depressurization*

1:46 i

Operator action-time to 3:00 terminate SI (is

. of SI flow path)g}ation L

SI termination and 11:42 i

e' pressure equalization *

[

l'i These values are calculated by LOFTTR2

- This operator action time was based on five simulator demonstration runs and due to the limited sample size, the bounding time was established by conservatively j

using the longest measured time.

'l f,

-37 w4 i

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w-w i

w ATTACHMENT NO. 4 e

PRESSURIZER PORV CAPABILITY FOR THE SGTR EVENT-

[?

1.

Introduction The Steam Generator Tube Rupture (SGTR) analysis for the Shearon Harris s

Nuclear Power Plant (SHNPP) takes power-operated relief valve (PORV). credit for the operation of one pressurizer during the event, its purpose is to 4

depressurize the Reactor Coolant System (RCS) and restore reactor coolant inventory af ter cooldown. The RCS depressurization reduces the break flow and y

increases Si flow to refill the pressurizer. Refer to WCAP 12403 for additional I

information. This is accomplished with one PORV which is required to open on remote manual command well into the event (af ter cooldown) for a brief duration.

L The SHNPP PORVs are air-operated valves (AOVs) controlled by instrument solenoid-operated valves (SOVs) in the pneumatic supply line. Actuation is either -

automatic or manual. The isolation block valves are motor-operated valves (MOVs) whien are upstream and in series with each PORV Block valve actuation -

is remote manual only. ' Although PORV and block valve actuation is currently classified as nonsafety related, it is extremely reliable. Their existing functions -

comprise of

_ (1)

Automatically relieves the RCS from overpreisure during transients at power.

(ii).

Automatically relieves the RCS from low temperature overpressure l

transients during cooldown and heatup operations.

(iii)

PORVs are normally closed, fait close AOVs.

l (iv)

PORVs in conjunction with the isolation block valves maintain the RCS pressure boundary.

1 I

(v)

Allow'RCS depressurization on manual actuation.

j The reliability of the PORV and block valve actuation system was dramatically l

improved based on increased NRC and industry attention, most notably:

Low Temperature Overpressure Protection Criteria Appendix R High/ Low Pressure Interface l

TMI NUREG 0737 Issues:

II.D.1 Performance testing of relief and safety relief valves, block valves, and discharge piping II. D.3 Direct indication of relief cnd safety relief valve position 1

(4711NED/rIj)

i#

1 II.G.1 Power supplies for pressurizer relief and block valves II.K.3.2 Report on PORV failures

~ II.K.3.3 Report on safety and relief valve challenges -

li.K.3.9 PID Controller II.

SGTR Function For the SGTR event, one PORV is required to open and close on remote manual command. Because the tube rupture is contained within the steam generator, the conditions for which the PORVs are required to open are similar to those for normal plant operation:-

No harsh environment

.No jet impingement effects, missiles, pipe whip, flooding, fires, etc.

No natural phenomena such as tornadoes, hurricanes However consistent with the SHNPP commitments to GDC-2 as documented in FSAR Section 3.1.2, the SGTR event will be considered concurrent with safe shutdown earthquake (SSE) loads.

The PORVs and block valves capability to perform the necessary function for the SGTR are demonstrated by their performance, design, reliability, and testing.

(i)

Performance The PORVs and block valves operability are consistent with the fluid process conditions expected during a SGTR event. The fluid process conditions are less severe than those of a reactor trip from power transient. Since the pressurizer level decreases due to loss of inventory through the tube rupture, the p(rocess fluid through the PORVs and block valves is saturated steam preceded by a loop seal waterslug) whose pressure and temperature also decrease during this event and are less limiting than the normal design conditions.

Since the pressurizer level is not expected to recover beyond 75%,

the process fluid remains saturated steam for the duration of PORV actuation. These valves have been extensively evaluated by Electric Power Research Institute (EPRI) with conditions more severe that those expected from an SGTR event as part of the resolution to TMI NUREG-0737 Item II.D.I. The applicability to SHNPP is documented in FSAR Section 3.9.3.3.2 and in the NRC's Technical Evaluation report to CP&L dated May 31,1989.

The mass flow rate through the PORVs for the SGTR event is well within the PORVs design capacity. Because the duration of PORV actuation is relatively short, the mass and energy release of steam to the pressurizer relief tank (PRT)is significantly less than that 2

(4711NED/r i j )

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i for which the PRT was designed. Since the RCS fluid is 7

L

" contained" within the RCS components, no _" harsh" environment within containment is expected and therefore the PORVs and block valves will operate in the same manner as they would for a normal

. W environment.

(11)

. Design, Reliability, and Testing

!p The flowpath for remote manual depressurization has the following i

features:

Reliable Open Flowpath 3 parallel flowpaths, each with one PORV (only I required)

[

Reliable Closed Flowpath Each flowpath has a PORV whir.h falls close on loss of electrical or pneumatic power.

Each PORV has two DC SOVs to assure PORY venting and closure.

Each PORV and flowpath has a normally open AC MOV (block valve) for isolation purposes.

a.

PORVs and block valves and position indication (limit switches) are:

Seismically qualified a

Environmentally qualified (PORV diaphragm qualifiable but needs documentation.)

Operable for process conditions These valves are included in the plant's In-Service Inspection (ISI)-

program and subject to surveillance inspection / testing for plant Technical Specification 3/4.4.4 and 3/4.9.4.

Note:

Backup valve position / status can also be inferred by temperature elements downstream of the PORVs.

Pressurizer PORV Discharge Piping and PRT are:

Operable for process conditions 1-Can accommodate RCS mass release of steam for SGTR

+

event.

The PRT has two rupture discs. Although these are expected to remain intact af ter the PORVs have opened, any release to l

Containment would have minimal impact on the PORV's ability to close. The block valves can also be relied upon to close as they are environmentally qualified to do this.

l 3

(471INED/r!J) y-l.

7...

c, a

m fy i-F Pneumatic Power n

are air operated talves (AOVs), power supply for the PORVs, wh The nonsafety grade pneumatic

[

is provided by compressed nitrogen accumulator tanks. These are capable of being charged by diverse nitrogen and instrument air supply lines from outside of containment. The design for the pneumatic system to the PORVs includes:

Accumulator tanks of stored compressed nitrogen (seismically qualified). Although ASME Section Vill, they are very similar to ASME Section til criteria, in cadition, their design pressure is much larger than the operating pressure. These tanks store suf ficient compressed nitrogen to accomplish the function required.

' Pneumatic tubing is seismically supported. Pneumatic piping is not seismically supported.

' Pneumatic components such as check valves and root valves can be justified for operability, environmental and seismic conditions. Root valves and check valves meet many of the -

same requirements. (design material, testing, etc.) as for safety grade components and some were purchased to the same specifications, but are not in the same QA program.

The control solenoid-operated valves (SOVs) in the pneumatic supply lines to the PORVs are not qualified environmentally or seismically. However, SOVs were designed similar to those for safety grade applications.

Note: the SOVs are normally deenergized,(adds margin to -

their life) and need only to be energized once in a " normal" containment environment for the SGTR.

Six low pressure alarms (2 per PORV)

Note:

In the event of containment isolation, emergency restoration procedures direct that the backup instrument air and nitrogen supply lines be established to Containment very early into the event (before cooldown and RCS depressurization).

Electric Power General The nonsafety grade electrical power supply has the following attributes:

- Class IE procured station service transformers and 480V power centers.

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' 480V MCC,125V DC ' bus,125V battery chargers and-

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125V battery are designed to the same industry and E

manufacturing standards as for safety-related

[,

equipment. The 480V MCC is seismically qualified.'

p, t

Double circuit protection for PORY and block valve circuits through containment penetrations. The circuit K

breakers are periodically tested.

V i

Cable procured as Class'lE.

H Cable tray and conduit are seismically supported.

Class lE containment penetrations.

Non-lE DC bus system, breakers, fuses, etc., are sized using the same industry standards as would be for safety-related components.

PORVs

- Valve " train" cable separation.

- DC power via dual battery chargers and backup battery supply. (125V DC).

Battery chargers are connectable to the emergency AC power supply.

1

- Battery is designed for two hours duty and its

[

environment is provided by one of the safety-related HVAC trains.

- Battery inspection and surveillance.

i Block Valve Valve train separation (also separated from PORVs for Hi/Lo pressure interface protection).

Voltage level separation (480V AC vs. -125V DC).

Note that the block valves are required to be connected to the emerg(ency electrical bus by restoration procedures early in the event prior to cooldown and RCS depressurization).

Instrumentation and Control

'Although classified as nonsafety grade, I&C has the following features:

5 (4711NED/cn )

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Qualifiable main control board (MCB) switches (although not I

designated as safety grade).

Main termination cabinets (passive devices) are p

designed / constructed to safety grade requirements.

Auxiliary transfer panels are safety grade and components

. inside for PORV/ block valve use are either qualified or use switches which are identical to the IE qualified models.

Pressure switches (function not required) are not qualified,-

but are mounted in a seismically qualified instrument rack.

c Note that the manual control logic overrides any automatic signal. _ Also inadvertent PORY actuation has already been-addressed in the plants' original design. The block valves provide a -

diverse means of isolating the RCS flowpath.

III.

Conclusion The PORV and block valve and actuation system is currently designed such that it is capable of operating and performing satisfactorily to allow remote manual operation during the SGTR event. In addition through component and system redundancy, diversity and testing, reliability is established to adequately ensure -

that its function can be achieved.

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