ML20072L204

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Draft DHR During Steam Generator Tube Rupture Event for C-E Sys 80 Plant
ML20072L204
Person / Time
Site: 05000470
Issue date: 07/31/1983
From: Kennedy M, Komoriya H
ARGONNE NATIONAL LABORATORY
To:
Office of Nuclear Reactor Regulation
References
ANL-LWR-NRC-83, ANL-LWR-NRC-83-7-DR1, NUDOCS 8307130094
Download: ML20072L204 (108)
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Ej ,:. .: reg Es-- d h% Il i 1 ,3 U_/ u idU 5 T) b4 d G Decay Heat Removal During a Steam Generator Tube Rupture Event for a C-E System 80 Plant M. F. Kennedy H. Komoriya Light Water Reactor Systems Analysis Section Reactor Analysis & Safety Division ARGONNE NATIONAL LABORATORY 9700 South Cass Avenue Argonne, Illinois 60439 Prepared for:

Division of Systems Integration 4

Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission

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Washington, D.C. 20555 NOTICE: This informal document contains preliminary information prepared primarily for interim unc by the Offica of Nucicar G NNE Reactor Regulation, Nuclear Ecgulatory y g Commission (NRC). Since it does not constitute a final report, it should be A RA&RY cited as a reference only in cpecial circumstances, such as requirements for regulatory needs. ~

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r TABLE OF CONTENTS Page 1.0 I NT R O D U CT I O N . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2.0 P LA NT I NP UT M0 D EL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3.0 DES C RI PT ION OF ACCI DENT S CE NA RI 0. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3.1 I ni ti a ti ng T ra n s i en t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3.2 S GT R R e c o v e ry G u i d el i n e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3.3 Ma t ri x o f Ca s e s A n al y ze d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4.0 CAL CU L AT I O NAL RE S ULT S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4.1 Doubled Ended Guillotine Rupture of a' Single T ube i n One S team Ge ne ra to r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4.1.1 Auxiliary Pressurizer Spray (APS) Case (Case 1) . . . . . . . . . . . .

4.1.2 PORY Case (Case 2) 4.1.3 APS Case with Stuck Open ADV on the Ruptured Steam Generator (Case 3)...................................

4.1.4 Continuous APS Due to Operator Error (Case 4) . . . . . . . . . . . . . .

4.1.5 Conti nuous APS wi th PORY (Case 5) . . . . . . . . . . . . . . . . . . . . . . . . . .

4.1.6 APS Case with ADV Stuck Open Until the End of the T ransient ( Case 6 ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4.2 Doubled Ended Guillotine Rupture of a Single Tube in Both Steam Generators.......................'.'...................

4.2.1 Auxili a ry Pressuri zer Spray Case (Case 7 ) . . . . . . . . . . . . . . . . . .

4.2.2 PORY Case (Case 8).........................................

4.2.3 PORY Feed and Bleed Case (Case 9)..........................

5.0 CONCLUSION

S.............................................................

A c k n o wl e d g e m e n t s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

References...................................................................

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LIST OF FIGURES No. Title Page 1 RELAP5/M001.5 Nodalization T6FCESSAR SGTR Calcul ations. . . . . . . . . . . .

2 Overall SGTR Recovery S trategy '( taken from Ref. 3) . . . . . . . . . . . . . . . . .

3 Case 1: Pressurizer Pressure vs Time..............................

4 Case 1: S team Generator P ressures vs Time . . . . . . . . . . . . . . . . . . . . . . . . .

5 Case 1: Pressure Drop Across Break Junction 878 vs Time. . . . .... . . .

6 Case 1: Break J unction 878 Fl owrate vs Time. . . . . . . . . . . . . . . . . . . . . . .

7 Case 1: Hot and Cold Leg Temperatures c' the Pressurizer Loop vs Time....................................................... ,

8 Case 1: Hot and Cold Leg Temperatures on the Non-Pressurizer Loop vs Time...........................................

9 Case 1: Flow Through Reactor Coolant Pumps on Loop 1 vs Time.....................................................

10 Case 1: Flow Through Reactor Cooiant Pumps on Loop 2vsTime.....................................................

11 Case 1: APS System Flowrate vs Time...............................

12 Case 1: Hot Leg Subcooling Margin vs Time.........................

13 Case 1: HPS I Fl ow i nto L oop 1 v s Time. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

14 Case 1: HPSI 'Fl ow i nto Loop 2 vs Time . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

15 Case 1: ADV Flow From the Loop 1 Steam Generator vs Time............................................................

16 Case 1: ADV Flow From the Loop 2 Steam Generator vs Time............................................................

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LIST OF TABLES No. Ti tle Page 1 CESSAR NSSS Component Thermal and Hydraulic Parameters. . . . .. . . . . . . .

2 Matri x of SGT R Ca s es A nalyzed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3 Event Sequences for Single SGTR Cases 1-3. . . . . . . . . . . . . . . . . . . . . . . . . .

4 Event Sequences for Singl e SGT R Cases 4-5. . . . . . . . . . . . . . . . . . . . . . . . . .

5 Summary of Integrated System Flowrates for the Single Tube Rupture Case...........................................

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1. INTRODUCTION This report documents the results of a series of calculations which were  !

performed to investigate the relative effectiveness of the auxiliary pressur-izer spray system when compared to the proposed addition of pilot operated relief valves (PORVs) on the pressurizer in mitigating the consequences of a steam generator tube rupture accident. The auxiliary pressurizer spray (APS) system is currently incorporated in the Combustion Engineering (C-E) pressur-ized water reactor nuclear steam supply system designs to allow for pressur-izer spray flow in the event that the normal spray system is not available --

because the reactor coolant system pumps are not running. However, the cur-rent C-E System 80 plant designs do not have any PORVs on the primary reactor coolant system. The U.S. Nuclear Regulatory Commission (NRC) has asked C-E to provide justification as to why PORVs should not be required on the System 80 pl ants . Argonne National Laboratory, under contract to the Reactor Systems Branch of the NRC, performed the calculations discussed in this report to support the NRC evaluation of the C-E response. This report focuses on the steam generator tube rupture transient; a companion report [1] investigated the relative merits of the APS system versus the addition of PORVs in miti-gating the potential consequences of a total loss of feedwater (both main and auxiliary) flow transient.

The initiating transient in this study is a single double ended guillo-tine rupture of a steam generator tube in either one (single SGTR event) or both (dual SGTR event) steam generators. The accident scenario for the initi-ating transient is the steam generator tube rupture accident discussed in Section 15.6.3 of the CESSAR Final Safety Analysis Report [2]. Unlike the

FSAR case, the initial conditions for the calculations performed for this study were consistent with the 100% power nominal design conditions provided in the FSAR. Following a 10 minute delay af ter reactor trip, the operator was

! assumed to take control of the plant; the operator actions which were assumed are consistent with the steam generator tube rupture recovery guidelines presented in Reference [3].

The calculations were performed with RELAP5/M001.5 (ZELAP); the cycle 31 1

version was used for all of the calculations.  !

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A description of the plant model for the RELAP5 calculations is presented l in Chapter 2. This chapter 'also includes a discussion of the resulting steady i state solution which was obtained with RELAPS for the 100% power nominal design conditions. The accident scenario assumptions and expected operator recovery actions are discussed in Chapter 3; this chapter also includes a discussion of the matrix of cases considered in this study. Chapter 4 con-tains the results of the transient calculations, and the overall conclusions for the study are presented in Chapter 5.

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2. PLANT INPUT MODEL The RELAP5/M001 (cycle 18) input deck developed for the CESSAR feedwater line break audit calculation [4] was modified and reinitialized to run on RELAP5/ MOD 1.5 (cycle 31). The plant nodalization is shown in Fig.1. A few changes from the feedwater line break audit calculation input model were made to increase the minimum Courant number and thereby increase the minimum time step which decreased the computing time for the transient calculations.

Thennal hydraulic volumes which were not needed for the SGTR calculations were eliminated from the original feedwater line break accident calculation input -

model and some of the noding detail was reduced.

The computer code RELAP5/M001.5 was used in the analysis. One signifi-cant change between RELAP5/M001.5 (cy=31) and RELAP5/M001 (cy=18) which was used for the feedwater line break audit calculation is that the RELAP5/1.5 (cycle 31) has an option which can be utilized to adjust the junction void factor of the flow recirculated to the downcomer by the separator. By speci-fying the void limit of separator junction flow (0 to 1.0), the user can select the quality and flowrate of recirculation flow and tube sheet flow.

A steady-state initial solution was achieved with RELAP5 for nominal 100%

rated power plant conditions. The major thermal-hydraulic plant parameters achieved from the steady-state calculation are compared to the plant nominal values in Table 1 (data taken from the CESSAR FSAR). A stable solution was established within 40 seconds af ter the initiation of the null transient calculation. All of the SGTR accident calculations were initiated following a

, 100 second null transient.

During sor, preliminary calculations, the RELAP5 results exhibited some significant mass error accumulation once the primary system reached saturation conditions. Init'ially the mass error was reduced by decreasing the maximum time step to 0.01 s when the hot legs begin to void. However, since the calculations were intended to be carried out for at least I hour of transient time, this time step would be very restrictive. The RELAP5 code developers provided some code updates which drastically reduced the mass error [5].

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Table 1. CESSAR NSSS Component Thennal and Ilydraulic Parameters Plant Steady State Nominal Initial Component Conditions Conditions l Reactor Vessel Rated core thennal power, MWt 3,800 3,800 Operating pressure, lb/in.2a 2,250 2,250 Coolant outlet temperature s *F 621.2 621.8 Coolant inlet temperature, 'F 564.5 565.9 Coolant outlet state Subcooled Subcooled-Total coolant flow,106 lb/hr 164 164 .

Core average coolant enthalpy' Inlet, Btu /lb 565 565 Outlet, Btu /lb 645 645 Average coolant density Inlet, lb/ft3 45.9 45.8 Outlet, lb/f t3 41.2 41.1 Upper head recirc. path flowrate, lb/s 319.4 315 Steam Generators Number of units 2 2 Primary Side (tube side)

Inlet temperature, 'F 621.2 621.8 Outlet temperature, 'F 564.5 565.4 Secondary (shell side)

Steam pressure / temperature, psia /"F 1070/552.8 1070/552.8 Steam flow per gen., Ib/hr 8.59 x 10 6 8.59 x 106 Exit steam quality, ". 99.75 99.43 -

Feedwater temperature, 'F 450 450 Recirc. Ratio 3.25 3.28 Pressurizer Operating pressure, psia 2,250 2,250 Operating temperature, *F 653 653 Net internal fluid volume, ft3 1,800- 1,800 Installed heater capacity, kW 1,800 1,800 5

Using these updates a maximum time step of 0.05 s was used when the primary system was voiding and the mass error did not exceed 0.2%. These updates were subsequently incorporated by the code developers into Cycle 31 of RELAP5/

M001.5 which was used for all the final calculations performed for this study.

A number of plant features were incorporated into the RELAPS plant model '

for this study. These plant features include plant component subsystems such as the auxiliary pressurizer spray, high pressure safety injection, charging, main feedwater and auxiliary feedwater systems. Also various primary and secondary side valves were modeled, including the proposed power operated relief valve on the pressurizer, the pressurizer and steam generator safety valves, main steam isolation valves, and the st'eam generator atmospheric dump valves. Plant trip functions to scram the reactor on low pressurizer pressure and to close the turbine stop valves were also modeled. All of these models are discussed in more detail in this succeeding paragraphs, including where necessary a discussion of how they were implemented in the RELAPS plant model.

For the high pressure safety injection system (HPSI), only one delivery train was assumed to be available. The HPSI flow was obtained from Reference

[6] and was implemented in the code as a flow versus pressure fill table.

Injection of HPSI flow was actuated on a low pressurizer pressure signal at 1600 psia; there was a 30 s delay before safety injection flow was provided to the cold legs to account for the time delay to load the HPSI pumps onto the emergency diesel generators. This action occurs automatically; however, once the operator has taken control of the plant the HPSI flow can be throttled to control inventory and subcooling margin. In these calculations, the HPSI flow was assumed to be on (delivering flow as a function of downstream pressure) or off depending on the following criteria: off, if the subcooling is greater than 20*F in the hot legs and the pressurizer collapsed liquid level is great-er than 100 inches and increasing; or, on otherwise.

The charging (makeup) system was assumed to deliver the full three charg-ing pump capacity to the system which is 18.27 lb/s. In this study, tne charging system was assumed to begin delivering full flow at the initiation of the break and continued until the calculations were terminated. The flow is

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I split equally between the two loops. When the auxiliary pressurizer spray  !

system is activated, the full charging system flowrate is diverted to the top of the pressurizer and is sprayed inta the pressurizer steam space'. The APS system is also turned off (and the flow diverted back to the cold legs) if the

-pressurizer collapsed liquid level exceeds 90% of the full range level. The charging system water was assumed to be at 120*F.

Both the main and auxiliary feedwater systems were modeled in the calcu-lations as fill tables; the main feedwater was injected directly into the

! lower tube bundle region, and the auxiliary feedwater was injected into the

Main steam line safety valves and atmospheric dump valves were modeled for each steam generator. The main steam line safety valves were modeled as trip valves in RELAPS with a flow versus pressure table. There are 3 banks of valves (2, 2, and 6 valves in each bank) on each loop. The banks of valves open sequentially at 1270,1305 and 1333 psia with a total minimum relief capacity for the 20 valves of 19 x 106 lb/hr.

The atmospheric dump valves are used to relieve steam from the steam generators when the condenser is not available. These valves are used to reduce the primary system temperature following a reactor trip with a loss of offsite power and can be controlled by the operator to limit the cooldown rate to within prescribed limits. In the RELAPS calculations, these valves were modeled as motor valves, and the valve area was sized to provide the design flow of 950,000 lb/hr at 1000 psia. The motor valves were controlled by a 7 {

signal based on the rate of change of the werage temperature on the primary system. When the average temperature was changing faster than 75*F/hr, the valves began to close. The valves were given a signal to open if the cooldown rate was less than 75'F/hr. One.of the two atmospheric dump valves on each steam generator was modeled. When the operator isolates the ruptured steam generator, the atmospheric dump valves is closed.

Main steam isolation valves were modeled for each steam generator. These

. valves were closed either when the pressure in either of the steam generators decreased below 810 psia or if the steam generator was isolated by the oper-ator at some point during the calculation.

Either the auxiliary pressurizer spray (APS) system or the PORY on the pressurizer is to be used to depressurizer the primary system during the transient. The APS system was modeled by diverting the charging system flow from the cold legs to the upper region of the pressurizer, if the activation criteria are met. The APS is used once the operator takes control of the plant and manually operates the plant systems. Auxiliary pressurizer spray flow is delivered to the pressurizer if the hot leg subcooling margin is greater than 25'F and continues until the subcooling decr. eases to below 20"F. When the APS system is not on, the charging system flow is delivered to the cold legs.

The PORY is used in some of the calculations instead of the APS system to depressurize the plant. In the RELAP5 calculation, the PORY is modeled as a trip valve which is either full open or closed depending on the same subcool-ing criteria as the APS system. The valve area was sized to discharge 119.7 lb/s (113 lb/hr/MWt) of steam at a pressure of 2500 psia. This is based on having two valves of the Calvert Cliffs (BG&E) type on the pressurizer.

A reactor trip on low. pressurizer pressure was included in the model.

The setpoint was 1785 psia which corresponds to the core protection calculator low pressure boundary trip setpoint. This signal caused the reactor scram rods to begin inserting negative reactivity into the core with a combined signal delay time of 0.89 s (0.55 s for signal delay and 0.34 s for coil release). The turbine stop valves and reactor coolant system pumps were 8

tripped following a 0.5 s delay. The loss of offsite power was assumed to occur 0.5 s following the reactor trip signal, t

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3. DESCRIPTION OF ACCIDENT SCENARIO The accident scenario adopted in this analysis is comprised of two dis-tinct phases: an initiating event and a transient recovery phase. For the initiating event phase, the accident scenario was taken from the sequence of events for the steam generator tube rupture (SGTR) analysis performed by C-E and reported in Chapter 15 of the CESSAR FSAR. This phase of the accident encompasses the period of time from the initiation of the break up until 600 s

. following the activation of the reactor trip signal. At 600 s af ter reactor trip, the operator is assumed to take control of the plant and implement the "

transient recovery guidelines; this period of time up until the break flow is terminated by the equilibrium of the pressures across the break opening is referred to in this report as the recovery phase of the accident. The oper-ator guidelines for the SGTR accident which are discussed in CEN-152 [3] were implemented in this study. A more detailed discussion of both the initiation and recovery phases is provided in the remainder of this chapter.

The steam generator tube rupture accident is caused by the failure of one or more of the primary coolant tubes in the steam generators allowing a direct flow path between the primary and secondary coolant system.s. Because of the large pressure difference between the primary and the secondary system, criti-cal flow is developed initially at the leak opening. A significant amount of primary reactor coolant system (RCS) inventory can be transferred to the secondary system even for a small break area. This primary coolant provides a potential source of radioactive liquid which will mix with the secondary system liquid inventory and could eventually be transported to the environment through the condenser hotwell air ejectors or through the steam discharge valves on the secondary system. The loss of the RCS mass inventory through the break causes a drop in the pressurizer level and consequently in the pressurizer pressure. If the charging system is operating in the automatic mode, the system will respond upon sensing the deviation in pressurizer water level from the programmed normal pressurizer level. Without any operator intervention, the RCS pressure will continue to.decrase and eventually cause a reactor trip on low pressurizer pressure.

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Once the reactor trips, the turbine stop valves close and the safety valves on the steam lines will open automatically to mitigate the pressure buildup on the secondary system.

l 3.1 Initiating Phase The general response of the plant to a postulated SGTR transient is discussed in the preceding paragraphs. This section focuses on the specific details of the initiating phase of the accident which were utilized in this study. The SGTR transient which was analyzed for Chapter 15 of the CESSAR FSAR was adopted for this phase of the analysis. The major assumptions which directly impact these calculations are outlined in the succeeding para-graphs. Although some of the calculations involved multiple tube ruptures (i'.e, one tube ruptured in each steam generator), the assumptions regarding the plant response which were taken from the FSAR single SGTR analysis are applicable to both the single and multiple tube rupture transients.

Because of differences in the break flow models between RELAP5 and the vendor's code, the critical discharge flowrate through the ruptured tube will be different. The transient is assumed to be initiated by the double-ended guillotine rupture of a single steam generator tube which results in a I p maximum break flow area o{0.00486 ftz. however, the break flow area in the 2

Q p./ RELAPS calculation was reduced top 2'l2.f t {so that the initial break flowrate X

[ b. computed by RELAPS was equal to the initial break flowrate reported in the

( y# '? Ij - (CESSAR FSAR.

As the pressurizer level decreased, the FSAR case assumed that the third charging pump was started and the letdown flow was throttled back to a minimum flow. In the ANL calculations, the letdown flow was assumed to be zero; also'in order to simplify the control systems modeling, the charging ,

system was assumed to deliver the full' three charging system flowrate (18.27 lb/s) from the time the break was initiated. The FSAR calculation assumed the third charging pump came on and the letdown flow terminated at 30 s after initiation of the break. In both the FSAR calculation and the ANL calcula-tion, the heaters in the pressurizer were de-energized when the pressure level decreased below 100 inches.

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l The reactor protection system tripped the reactor when the pressur-izer pressure decreased below the core protection calculator low pressure boundary trip setpoint of 1785 psia. Upon reactor trip, the turbine stop valves were closed and the system was assumed to' experience a total loss of offsite power. Energy was removed from the steam generators by steam dis-charge through the safety valves on the main steam lines; no credit was taken for any action of the main steam dump and bypass valves. Because of the loss of offsite power and the closure of the turbine stop valves, the main reactor coolant pumps began to coastdown and the main feedwater flow was ramped to zero. The auxiliary feedwater system was assumed to be available if the downcomer level decreased below the low level setpoint value of 19.76 f t. A 45 s delay was assumed between the receipt of the signal and the delivery of feedwater to the steam generator to allow time for the auxiliary feedwater pumps to be loaded onto the emergency diesel generators. The auxiliary feed-water pumps could deliver up to 121 lb/s to each steam generator. Prior to reactor trip the main feedwater system was assumed to be in the automatic mode so that the feedwater flow to the ruptured steam generator would decrease as the level measuring system sensed the increasing level due to the leakage into the steam generator through the ruptured tube. In the ANL calculations, the main feedwater flowrate to the ruptured steam generator es decreased by the amount of leakage flow into the steam generator to simulate the feedwater control system.

When the pressurizer pressure decreased below 1600 psia, a safety injection actuation signal (SIAS) was generated and safety injection flow was assumed to be available for delivery to the primary system following a 50 s delay to allow for loading the safety injection pumps onto the emergency diesel generators.

The plant was assumed to respond only to automatically actuated safety systems until[10 minuteg following reactor trip. Af ter this 10 minute delay, the operator was assumed to take control of the plant and implement the SGTR recovery guidelines as discussed in Reference [3]. The important recov-ery guidelines are summarized in Section 3.2.

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3.2 SGTR Recovery Guidelines The SGTR recovery guidelines were used as the source for information on what actions the operator would take during the transient recovery phase of the calculations. This phase was assumed to begin 10 minutes after reactor trip and end wnen the pressure drop across the break became zero or nega-tive. The calculations were, in fact, beyond the first instance of negative break flow to insure that the primary to secondary leakage was capable of being terminated. .

The overall SGTR recovery stra'tegy is depicted in Fig. 2. The steps pertinent to the modeling required for the calculations discussed in this report are steps 1-4 and 6. Step 5 was not considered because the assumed loss of offsite power precluded the restarting of the main reactor coolant pumps.

The first recovery action which the operator was assumed to take was to reduce the reactor coolant system hot leg temperature to below 565'F to insure that the steam generator safety valves would not be lifted due to the primary system heat inventory. The temperature of 565"F is less than the saturation temperature corresonding to the pressure of the lowest opening setpoint of the steam generator safety valves. This is accomplished by feed-ing the steam generator with auxiliary feedwater and removing energy from the steam generators by discharging steam through the atmospheric dump valves 816H T ,

(ADVs).Qothsteamgeneratorsareusedtoremoveenergyduring this cooldo3 one ADV on each steam generator was' utilized to discharge steam. The ADV system was used because the condenser was not available. In order to control the rate of RCS cooldown, the ADVs were throttled; the cooldown rate was limited to less than 75'F/hr based on the average primary system tempera-ture. For these calculations, the primary system average temperature was taken to be the average of. the two hot legs and the two combined cold leg temperatures.

When the tenperature on the hot leg is less than 565 F, the ADV on the ruptured steam generator is closed and the auxiliary feedwater flow is tenninated. Also, if the main steam isolation valve on the ruptured had not 13

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been closed by this time, the MSIV valve is closed. The ruptured steam gener-ator is isolated with the only potential paths for stedin release being the main steam line safety valves and the ADV, if the operator chooses to reopen it.

Once the ruptured steam generator is isolated, the operator con-tinues to cool the primary system down with the ADV on the intact steam gener-ator. Again the cooldown rate is limited to less than 75'F/hr by controlling  ;

the ADV flow depending on the deviation of the cooldown rate from the maximum allowed value of 75'F/hr. Make-up flow to the unaffected steam generator is provided by the auxiliary feedwater pumps which are programmed.to maintain the downcomer water level at 19.76 f t.

The high pressure safety injection system (HPSI) which was automati-cally initiated when the pressurizer pressure decreased below 1600 psia will be placed in a manual mode once the operator takes control of the plant. The HPSI flow will be throttled by the operator depending on a set of criteria related to the hot leg subcooling margin and the pressurizer collapsed liquid level. In the RELAP5 calculations, the HPSI flow was assumed to be either on or off depending on the following criteria. The HPSI flow is terminated if the hot leg subcooling margin is greater than 20*F and the pressurizer level is greater than 100 inches and increasing. If any of these criteria are not met, the HPSI flow is re-established. Only one train of HPSI flow was assumed to be available in the calculations.

The only other operator,ac' tion which was implemented in the RELAPS calculations related to the actions taken by the operator to decrease the primary system pressure in an effort to equilibrate the pressures across the break and thus terminate the primary to secondary leakage'. Although on the current C-E System 80 design only the pressurizer spray systems (either the normal or auxiliary pressurizer sprays) would be available for depressurizaing ,

the primary system, a power operated relieve valve (PORV) on top of the pres-surizer was modeled to provide an alternative means of depressurization so l that the objective of this study which is to investigate the need for adding a PORV to the System 80 design could be achieved. Because the reactor coolant system pumps are unavailable, only the auxiliary pressurizer spray (APS) 15 W

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system is used to decrease the primary system pressure in these calcula-tions. Whether or not the APS system or the PORY is being used, the same controlling .. logic was assumed for governing the operation of either system.

The hot leg subcooling margin was used to determine the operator's activation ,

of the depressurization system. The following criteria were utilized to govern the operator's actions. If the hot leg subcooling margin exceeded 25*F, the APS system was turned on; or the PORY was fully opened. If the subcooling decreased below 20*F, the APS system was turned off; or, the PORY was closed. .The assumed 5*F of hysteresis in the control logic is to prevent the system from cycling too much.

  • The control criteria for the depressurization systems are not pro-vided in the SGTR recovery guideline; the specific criteria used in this study were obtained from NRC [5]. -

3.3 Matix of Cases Analyzed In order to make a detennination on the need for a PORV oYi the System 80 plant, the ma'trix of cases outlined in Table 2 were analyzed. These calculations are intended to provide information on the relative usefulness of a PORV in mitigating the consequences of a SGTR accident. Cases 1-6 assume a single double ended guillotine rupture of one tube in only one steam gener-ator; Cases 7-9 assume a single tube rupture in both steam generators.

The relative effectiveness of either system in allowing the operator to depressurize the primary system is investigated in cases 1, 2, 7 and 8.

Cases 3 and 6 were included to investigate the impact on the operator's abil-ity to tenninate the primary to secondary leak if the ADV on the ruptured steam fails close when the operator attempts to isolate the ruptured steam generator. Case 3 assumed that the operator identified and corrected the stuck open valve after 20 minutes; in case 6, the ADV was lef t open until the end of the transient. In both Case 3 and 6, the ADY was assumed to stick open at the maximum area to which it had opened during the cooldown. This amounted to an effective flow area of -307, of the full open area.

16

Cases 4, 5 and 9 were included to address other issues than merely the relative depressurization capability of the two systems which may influ-ence the decision to require a PORY on the primary system. If the operator Table 2. Matrix of SGTR Cases Analyzed.

Case Number Comment 1 Single with APS 2 Single with PORY -

3 Single with APS stuck open ADV for 20 min.

4 Single with continuous APS 5 Single with continuous APS 6 Single with APS stuck open on ruptured SG for the duration of the calculations l 7 Dual with APS 8 Dual with PORY 9 Dual with PORY -- feed and bleed inadvertently fails to tenninate the APS flow when the subcooling criterion is reached, the pressurizer could go solid. Cases 4 and 5 investigate the poten- '

tial for recovering control of the plant and continuing to depressurize the plant if the APS system is unable to spray into the liquid solid pressur-izer. The PORV could possibly be utilized at that point to remove liquid from the pressurizer to allow for some volume into which the operator could inject the APS flow. The pressurizer code ' safety valves would probably lift if the pressurizer went solid; however, the PORY would provide the operator with a controllable system for discharging mass from the primary and also on which could operate at pressure below the pressurizer safety valve pressure set-point.

Finally Case 9 was analyzed to provide some information on whether the PORY would be useful in mitigating the consequences of tube rupture acci-dents in which at least one tube is broken in each steam generator. With the PORV, the operator could isolate both steam generators and then remove energy from the system by using a feed and bleed operation. The feed and bleed logic 17

employed in Case 9 is the same as the logic employed in the total loss of feedwater flow analysis which is reported in Reference 1. The PORV is fully opened and the HPSI system delivers flow based on the downstream pressure conditions.

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4.0 CALCULATIONAL RESULTS The calculations were subdivided into two categories. The first category contains all of the cases in which a single steam generator tube was ruptured in only one steam generator. The second category contains the cases in which there is a single ruptured tube in each steam generator. In each category, the cases are all identical until the operator actions are initiated. So, for each category, there is a base case calculation which includes the time period from the initiation of the break (s) until one of the steam generators is isolated and the long tenn cooldown of the plant begins. The individual cases discussed in this chapter were all restarted from either one of the base cases.

4.1 Doubled Ended Guillotine Rupture of a Single Tube in One Steam Generator The base case for the single tube rupture cases was begun with a 100 s null transient to insure that steady state conditions had been achieved.

The break was initiated at 100 s by opening the break valve junction 878 which is on the non-pressurizer loop. The break is at the tube sheet on the cold leg side of the U-tube region. The break location is the same as in the FSAR case. When the break was initiated, the charging system was assumed to begin injecting the full three pump flowrate into the cold legs. Also the main feedwater flowrate was decreased by an amount equivalent to the break flow to simulate the automatic operation of the feedwater level control system.

The results of the single tube rupture base case are discussed in Section 4.1.1 in conjunction with the results of the calculation in which the APS system was used to depressurize the primary system, 4.1.1 Auxiliary Pressurizer Spray Case Af ter the steam generator tube is ruptured, the primary reactor coolant system inventory continues to decrease because the charging l i

system cannot replenish the liquid being lost through the break. As the inventory decreases, the pressurizer pressure and level decrease. The pres-19

surizer pressure transient is depicted in Fig. 3. When the level in the pressurizer falls below 100 inches, the pressurizer heaters are de-energized which causes the pressure to decrease faster. During this time period, the reactor power and primary systen temperatures are holding relatively con-stant. Eventually, the pressurizer pressure decreases below the setpoint for the core protection calculator low pressure boundary trip (1785 psia). The turbine stop valves are closed instantaneously following the delay for the trip signal. Closing the turbine stop valves temporarily terminates the energy removal from the steam generators and reduces the primary to secondary heat transfer rate, causing a rapid increase in the pressurizer pressure. The pressurizer pressure then decreases rapidly as the control rods, which are inserted into the reactor core drastically reduce the energy input to the primary system. Following closure of the turbine stop valves, the secondary system pressure rises rapidly and the opening setpoints for the first two banks of safety valves are reached. Steam is discharged through the secondary safety valves decreasing the secondary system pressure and increasing the energy removal rate from the primary system. The primary system pressure begins to decrease slowly due to the energy removal through the st"m gener-ators when the safety valves are open. The safety valves eventually close when the atmospheric dump valves are opened to decrease the hot leg tempera-tures below 565*F. Opening of the ADVs marks the end of the initiation phase of the transient. The safety valves remain closed for the remainder of the transient. When the ADVs are opened, the pressurizer pressure decreases steadily. The ADVs are throttled to limit the primary system cooldown rate to

< 75'/hr. Both steam generators are being used during this initial cooldown period to insure that the loops respond symmetrically and the natural circula-tion flows in each loop remain stable. The ADVs were opened 10 minutes fol-lowing reactor at s( + 600 s = s) when the operator was assumed to take control of the plant and remain open until the hot leg temperature decreases below 565'F. If the hot leg temperature decreases below 565'F, the ruptured steam generator is isolated by closing the main steam and feedwater isolation valves, and the ADV. This signals the end of the base case and occurs at s. From this point on, the single tube rupture cases will differ depending on the assumed operator actions and/or assumed failures. All of the remaining calculations which assumed a single tube rupture in only one steam generator were initiated from this point. The remainder of this section

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A table summarizing the major event sequences for all of the single tube rupture cases is provided in Tables 3 and 4.

Once the ruptured steam generator has been isolated the HPSI flow and APS flow are controlled by the criteria outlined in Section 3.2. The charging system fluid will be spraying into the pressurizer (through the APS system, if the hot leg subcooling is > 25*F and injecting into the cold legs if the subcooling is < 20*F. The HPSI flow will be tenninated only if the hot leg subcooling is > 20*F and the pressurizer collapsed liquid levels exceeds 100" and is rising; otherwise the HPSI flow is delivered to 'the cold legs, assuming the safety injection actuation signal had been received.

The transient response of the steam generator pressures is plotted in Fig. 4. Initially, the steam generator pressure is not affected by the influx of primary fluid through the ruptured tube; the pressure rise at -

1100 s is due to closure of the turbine stop valves. The secondary safety valves mitigate the pressure rise and the secondary pressure oscillates as the safety valves are cycled. Eventuaily the ADVs are opened and the pressure in both steam generators declines steadily. There is some oscillating in the secondary pressure response which is due to the cyclic throttling of the ADVs

' to limit the cooldown rate. At s, the ruptured steam generator (on loop

2) is isolated and the pressure rises in response to the closure of the ADV to isolate the ruptured steam generator. The pressure in the steam generator on loop 1 continues to decrease as the ADV on this loop is used to continue to cooldown the plant until the leak can be terminated or the residual heat removal system can be initiated. (The initiation criteria for the residual heat removal system for Systen 80 are 400 psia and 350*F.)

The resulting pressure drop across the break (see Fig. 5) responds to the changes in.the primary and secondary system pressures. The 22 # '

( r o r$ E Pro v t DED)

Table 3. Event Sequences for Single SGTR Cases 1-3 (Time in sec.).

Events Aux. Spray PORY Stuck Open ADV

-(Case 1) (Case 2) (Case 3)

Tube rupture begins '

lefhe PORY pressurizer heater turned off 6Sh6 (Pzr water level 6 100")

RCS starts to boil BGhD Reactor trip 107-h6 -

(Pzr pressure < 1785 psi,a)

Turbine stop valve close 1476 0 RCP trip 19760 Steam generator safety valves open 10 E 0 HPSI flow signal (SIAS) 16267 ADV flow actuated 1&7ih5 Aux. feed to intact SG 160h3 Aux. feed to affected SG 17 G0.8 Hot leg temp. < 565*F TT2SM -

All single SGTR cases are the same up to here ----------

Manual cooldown begins 19 & 5 1925.5 142L5 ADV stuck open --- ---

1925-5 Isolate broken SG -1025.5, 19 Ebb ---

Aux. spray . initiated 1925.5 ---

1925-t PORY operated ---

1925:5- ---

Close stuck open ADV (20 min. af ter SG isolation) l Negative break flow 351674 33 4 5 _5916,8 23'

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(To BE PRov>DED )

Table 4. Event Sequences for Single SGTR Cases 4-6 (Time in sec.).

Events Aux. Spray PORY Stuck Open ADV

-(Case 3) (Case 4) (Case 5)

Tube rupture begins 100.0 PORY pressurizer heater turned off 634 6 (Pzr water level < 100")

RCS starts to boil B5't.t Reactor trip 19P3-5 -

(Pzr pressure < 1785 psia)

Turbine stop valve close 1974.0 RCP trip 1074.0 Steam generator safety valves open 1079 0 HPSI flow signal (SIAS) M2427 ADV flow actuated 1623.5 Aux. feed to intact SG 16 h 3 Aux, feed to affected SG 176fn8 ,,

Hot leg temp. < 565'F L925.5

All single SGTR cases are the same up to here ----------

Manual cooldown begins 1925.5 1925d 1925-5 ADV stuck open --- ---

1925.5 Isolate broken S5 1925.5 1925.5 ---

Aux. spray initiated 4925.5 ---

1M5.5 PORY operated ---

1921 5 ---

Close stuck open ADV 3t25.5 (20 min. after SG isolation)

Negative break flow 3518.4 3391.5 5976.8 9

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system. The cooldown continues on loop 1 (with the pressurizer) because this loop is not isolated and is used to cool the system down once the ruptured steam generator is isolated. The temperature response on loop 2 behaves similarly except after 4600 s, the hot and cold leg temperature peaks are no longer synchronized after the natural circulation flow pattern on the isolated loop is disrupted because there is no more thermal driving fcrce to support the flow once the ruptured steam generator is isolated. The flows through the pumps on loop 1 and 2 are displayed in Figs. 9 and 10, respectively.

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leg subcooling criteria ' discussed previously. The hot leg subcooling margin is displayed in Fig.12.

The HPSI flows being injected into the cold legs of loop 1 and 2 are depicted in Figs.13 and 14, respectively. Initially, before the recovery phase of the transient, the HPSI system responds automatically once the safety . injection actuation signal is activated at when the pressure drops below 1600 psia. After the recovery phase is initiated the HPSI flow is governed by the criteria discussed in Section 3.2.

The ADV flowrates for both steam generators are depicted in -

Figs. 15 and 16. As per the discussion in Section 3.2, the ADVs are being throttled to limt the cooldown rate. If the cooldown rate based on a primary average temperature is increasing too fast, the valves begin to close. Then, if the cooldown rate is too slow, the valves begin to open. Eventually the ADV on the ruptured steam generator is completely closed when the hot leg temprature decreases below 565 F at s.

A summary of the important integrated flows into and out of the primary and secondary systems is presented at the end of Section 4.1 in Table 5.

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Table 5. Sunnary of Integrated System Flowrates for the Single Tube Rupture Cases.

Parameter / Case 1 2 3 4 5 6 Break APS PORY ADY SG1 ADV SG2 Safety Valves SG1 Safety Valves SG2 l HPSI Loop 1 HPSI Loop 2 Pressurizer safety valve .

4.1.2 PORY Case (Case 2)

(To be written.) C AGvR.ES TAlcLupED) 4.1.3 APS Case with Stuck Open ADV on the Ruptured Steam Generator (Case 3)

(To be written.) [ FIGURE S .%vcluoED) 4.1.4 Continuous APS Due to Operator Error (Case 4)

(To be written.)

40 c . . .. .. .. . .. ..

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(To be written.) -

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4.2 Double Ended Guillotine Rupture of a Single Tube in Both Steam 1

Generators-As in the single tube rupture cases discussed in Section 4.1, the cases with a single SGTR in both steam generators were all continuations from l a base case calculation which ended when the ADV was closed on one of the steam generatoars. The base case was initiated, following a 100 s null tran-sient, by opening the leak flow paths from the primary to secondary systems in both steam generators. The discussion of the base case is included in the discussion of the results of Case 7 in which the APS system is used to depres-surize the primary system. For the remainder of the dual-SGTR calculations, only the recovery phase of the transient will be discussed.

4.2.1 Auxiliary Pressurizer Spray Case (Case 7)

The overall plant response for the dual SGTR base case is very similar to the base case for the single SGTR cases. However, the time-

-scale for the dual SGTR cases is more compressed than for the single SGTR cases because the increased break flow causes the primary system inventory and consequently the pressurizer pressure to decrease much faster. Because the primary system depressurization (Fig. 21) was so rapid, a reactor trip was

[

generated very early at s when the pressurizer pressure decreased below I the core protection calculator low pressure boundary trip setpoint of 1785 psia. Again the post-trip response of the pressurizer pressure is qualita-tively similar to the single SGTR base case. The depressurization of the primary system continues for another 600 s as primary system liquid inventory is discharged -through the break and energy is removed from the steam .gener-

'41

ators through the steam generator safety valves. At 600 s following the reactor trip,, the ADVs are opened to reduce the hot leg temperatures to below 565*F. When the hot leg tenperature decreases below 565'F, the ADV on loop 2 (the non-pressurizer loop) is closed and 'the steam generator on this loop is isolated by closing the main steam and feedwater isolation valves. This marks the termination of the base case and begins the recovery phase of the acci-dent.

C REH ritND ER OF TEXT- To r3r_ u)R.tTTEN) 4.2.2 PORY Case (Case 8)

(To b'a written.') [F G uturs TMc L.uoco]

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5.0 C0tlCLUS!0tlS For the single tube rupture cases, the PORY was more effective in depressurizing the primary system ~ and terminating the primary to secondary leakage. The PORY case (case 2) results indicated that the leak could be terminated about 5 minutes earlier than the APS case. This is out of a total transient time of approximately 75-80 minutes. The calculations would have displayed a much wider margin between the APS and PORY cases if the PORY would

. have been controlled using a less restrictive logic. The APS system cannot

~

effectively depressurize the system once the subcooling margin is lost because it cannot remove energy from the system. However, the PORY is able to remove energy from the system, so it is capable of depressurizing the primary system even though the subcooling margin is lost. The additi'on of a PORV would provide the operator with an additional degree of flexibility to deal with potential accident scenarios. The effectiveness of the PORY to remove energy from the primary system will be demonstrated in Case 9 which is currently underway.

With the criteria for operating the PORV as implemented in this study, there is no advantage, as far as the SGTR event is concerned, in installing a large PORV (versus the smaller BG8E size valve used. in this study), because the larger PORY will only result in an earlier closure of the valve once it is opened when the subcooling margine decreases below 20 F.

Once the results from Cases 4, 5, 6 and 9 are obtained, the conclusions will be expanded to reflect the new results.

43 l

.P

ACKNOWLEDGMENTS This report was prepared by ANL staff in partial fulfillment of a project under the direction of the U.S. NRC Division of Systems Integration, R. J.

Mattson, Director; B. Sheron, Branch Chief for Reactor Systems; N. Lauben, Section Leader; J. Guttmann, Project Manager. L. B. Marsh of the NRC Reactor Systems Branch provided direct technical guidance during the performance of this task.

ANL staff who provided input to this report, in addition to the authors, were P. B. Abramson who provided general :echnical assistance and guidance and K. S. Chung who developed the initial input deck and ran some of the prelimi-nary calculations; K. Rank. and J. Bracken, report preparation; and R. D.

Wright, Jr. , draf ting services.

9 P

44 u _ _ _ _ .

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' REFE RENCES l

1. H. K. report.
2. CESSAR SGTR
3. CEN-152 4.- ANL/ LWR /NRC 83-2 5.- Private communication with Vic Ransom ( j mass error updates.
6. Responses to Question 440.40 on CESSAR docket. .
7. Telecon from Tad Marsh, NRC, Jan. 83.

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