ML20097C702

Best Estimate Steam Generator Single Double-Ended Tube Rupture Analysis

ML20097C702
Person / Time
Site:	Davis Besse
Issue date:	07/31/1984
From:	BABCOCK & WILCOX OPERATING PLANTS OWNERS GROUP
To:
Shared Package
ML20097C697	List: ML20097C690 ML20097C702
References
77-1152840, 77-1152840-00, TAC-49662, NUDOCS 8409170221
Download: ML20097C702 (32)

Text

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77-1152840-00 l

[ Best Estimate Steam Generator Single Double Ended '

Tube Rupture Analysis

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BEST-ESTIMATE STEAM GENERATOR SINGLE DOUBLE-ENDED TUBE RUPTURE ANALYSIS

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, B&W Document No. 77-1152840-00

, Prepared for Toledo Edison Company

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d by Babcock & Wilcox utility Power Generation Division P. O. Box 1260 Lynchburg, Virginia 24505 j

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i CONTENTS Page

1. INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . 1

2. CONCLUSION . . . . . . . . . . . . . . . . . . . . . . . . . . 2

3. BEST ESTIMATE ANALYSES of a SINGLE DOUBLE-ENDED SGTR . . . . . 3 3.1. SGTR General Characters ................ 3 3.2. Method of Analysis (Best Estimate) . . . . . . . . . . . 4

( 3.2.1 General Operator Actions ............ 4 3.2.2 Assumptions and Initial Conditions ....... 5 3.3. Results of Analysis .................. 6

(. 3.4 Conclusions ...................... 7

4. R EF E R E NC E S . . . . . . . . . . . . . . . . . . . . . . . . . . 28 List of Tables Table 3-1. HP I a nd M U Sy s tem Capa ci ti e s . . . . . . . . . . . . . . . . 8 3-2. REDBL5 Volume and Junction Description . . . . . . . . . . . 9 3-3. SGTR Sequence of Events .................. 11 List of Figures Figure

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3-1. REDBL5 Volume and Junction Schematic ........... 12 3-2. Detailed REDBL5 Component Diagram for SGTR Model ..... 13 3-3. Operator Actions F.c ' lowing SGTR Rupture . . . . . . . . . . 14

{- 3-4. Total Leak Flow Rate Vs Time After Rupture ........ 15 3-5. Total Reactor Power Vs Time Af ter Rutpure of a Single Double-Ended SG Tube ............... 16 3-6. MFW Flow rate Vs Time Af ter Rupture . . . . . . . . . . . . 17 3-7. RCS Averge Temperature Vs Time Af ter Rupture. . . . . . . . 18 3-8. Pressurizer Collapsed Liquid Level Vs Time Af ter Rupture . . . . . . . . . . . . . . . . . . . . . . . . . . 19

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( Page 3-9. Hot Leg Temperature Vs Time Af ter Rupture . . . . . . . . . 20 3-10. Cold Leg Temperature (Affected Loop) Vs Time Af te:-

f Rupture . . . . . . . . . . . . .. ,.......... 21 3-11. Cold Leg Temperature (Unaffected Loop) Vs Time After -

Rupture ......................... 22 -

3-12. Hot Leg Pressure Vs Time After Rupture ......... 23 3-13. Surge Line Flow Vs Time After Rupture .......... 24 3-14. Net Injection Flow Rate Vs Time After Rupture ...... 25 3-16 Top and Bottom SGTR Leak Flow Rate Vs Time After Rupture ...... ............... ... 26 3-16. Subcooling Margin Vs Time Af ter Rupture ......... 27 h

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1. INTRODUCTION j.f-[M . .

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This report is intended to supplement the information contained in the 0:.J(:-

repo rt, " Analytical Justification for the Treatment of RC Pumps Following  !

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M, Accident Conditions," B&W Document No. 77-1149091-00, February 1984. This ff.;

...' report presents the analysis of a steam generator tube rupture for the 177 d8* -

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fuel assembly (FA) raised-loop design in compliance with the criteria pre-  !, ,

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.A sented in Nuclear Regulatory Commission (NRC) Generic Letter 83-10, dated :f

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2. CONCLUSION An adequate subcooling margin is maintained during steam generator tube rup-( ture (SGTR) events for ruptures up to and including the double-ended rup-ture of a single tube. Thus forced circulation is ensured throughout the event if the operator follows procedures based on the Abnonnal Transient

( Operating Guidelines (AT0G).

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e 3. BEST-ESTIMATE ANALYSIS OF A SINGLE DOUBLE-ENDED STEAM GENERATOR TUBE RUPTURE A single double-ended SGTR was simulated for the Davis-Besse raised-loop

plant design. The analysis is intended to demonstrate that sufficient loss of subcooling margin will not occur resulting in a need to trip the reactor coolant (RC) pumps if an operator follows the ATOG for the event. The results of this analysis wil' support the bases for utilizing manual trip-ping of the RC pumps en the criterion of the loss of subcooling margin.

3.1. SGTR General Characteristics

An SGTR is a loss-of-coolant accident (LOCA) that allows reactor coolant to leak into the secondary side of the steam generator (SG) where it is released into the steam plant and can lead to significant offsite doses if 5

this steam is released to the environment. For a complete severance of one SG tube, a leak rate of approximately 400 gpm at nonnal system pressure and a temperature would be expected.

The leak from a failed tube cannot be isolated and reactor coolant will con-

- tinue to be lost until the plant is completely cooled and depressurized and the primary loops have been drained.

' Since a tube rupture can exhibi t the same general characteristics as a small break LOC A, the general procedures for LOCA mitigation must be fol-lowed. A continuous cooldown and depressurization of the reactor coolant system (RCS) is essential to avoid the opening of the SG safety valves thus i minimizing the risk of releasing radiation. Forced circulation by the RC pumps will provide a continuous uninterrupted cooldown and depressurization

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s The following best-estimate analysis of a single double-ended SGTR for the Davis-Besse rai sed-loop plant was performed to demonstrate that operator actions as per ATOG, to control RCS inventory, perfom plant runback, and initiate low power reactor trip preclude the loss of subcooling margin and hence RCP trip, during a single double-ended SGTR event.

3.2. Method of Analysis (Best Estimate)

The analysis was perfomed with the REDBLSI computer code. A description of the REDBL5 model simulating the RCS and the SG secondary system is shown in Figures 3-1 and 3-2 and Table 3-2. Tne model has been developed to pre-dict the system behavior during an SGTR event and simulate important opera-tor actions as described in the AT0G. In addition, the model utilizes a non-equilibrium pressurizer model capable of predicting two-phase pressuriz-er inventory and mixture level.

Operator actions leading to a cold shutdown, system initial conditions, and other input assumptions are described in the following subsection.

M.1. General Operator Actions Th operator actions for the SGTR event are summarized in Figure 3-3. The SGTR event can be divided into four bistinct categories. Each of the cate-gories is addressed below.

Event Identification The first stage for mitigation of an SGTR is prompt recognition of the event and determination of the affected steam generator. The occurrance of secondary radiation al ams (steam line monitor or condenser air ejector) almost simultaneous with decreasing RCS pressure and pressurizer level are unique indicators that an SGTR has occurred. This analysis assumed that the operator diagnoses the SGTR following the radiation alam and pressur-izer low level alam and begins to take prescribed action.

Plant Control at Power In the second stage of the event, the RCS pressure and prenurizer level must be stabilized so that the plant may be run back without tripping. A i

l trip at high core power may result in venting radioactive steam to the envi-ronment through the secondary safety valves. Normally, the makeup (MU) sys-tem will automa tically increase MU flow to stabilize pressurizer level. .

For a double-ended rupture (DER) of a single tube, the leak flow (%400 gpm) is greater than the MU flow. The operator is instructed to take action to increase MU flow and tenninate letdown in order to stabilize the RCS. Once

( the RCS pressure and pressurizer level are stable, plant runback to 25%

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full power should begin.

This analysis assumes that the operator starts a second MU pump and isolates letdown in order to stabilize RCS pressure. Analysis 2 has shown that for a DER of a single tube, the operator has approximately 11 minutes to stabilize RCS pressure before the reactor trips automatically. Once the system is stabilized, the operator is assumed to run back the power.

Plant Runback to 25% Full Power Operator action should be initiated to stabilize RCS pressure and pressuri-zer level while conducting a plant runback to low power without tripping.

RCS inventory should be monitored during the plant runback. This analysis assumed integrated control system (ICS) action to reduce the main feedwater (MFW) demand to match a manual 20% per minute runback in core power level.

Upon reaching 25% full power, where the available turoine bypass (TB) capacity is sufficient to avoid lifting the steam safeties, the plant is tripped.

Cooldown and Depressurization The initial obh ctive of the cooldown is to bring the RCS hot leg tempera-ture to a value (520F) that corresponds to a saturation pressure which is

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below the steam safety valve setpoint. This action will limit radiation releases to the atmosphere. Below 520F, the SG with the tube rupture can be isolated. The cooldown should be continued to cold shutdown conditions

( at a rate of 100F/h using both generators and the decay heat removal system L (DHRS), while maintaining a subcooled RCS.

3.2.2. Assumptions and Initial Conditions The following assumptions and initial conditions were used in this analy-sis.

t Core power is 2772 MWt.

Offsite power is available throughout the transient.

RC pumps operate throughout the transient. ,

Initial pressurizer level is 195 inches (indicated).

High pressure injection (HPI) and MU flow citaracteristics are as shown in Table 3-1.

The primary-to-secondary leak flow is conservatively modeled as subcooled discharge, with a discharge coefficient of 1.0.

Initial plant condition --

Power level 2772 MWt Hot leg temperature 607.12F Hot leg pressure 2169.0 psia Tavg 583.14F RC system flow rate 39746 lbm/s Pressurizer level (as measured from the lower tap) 195 in.

Total steam flow rate 3264.5 lbm/s Subcooling margin 40.28F 3.3. Results of Analysis h The primary-to-secondary leak fl ow rate which resulted from the DER was approximately 39 lbm/s (see Figure 3-4). Operator action was modeled tc manually start a second MU pump and isolate letdown at 3 minutes and 3.5 minutes 'af ter rupture, respectively. The charging flow of two MU pumps was not sufficient to match the leak fl ow. Subsequently, pressurizer level continued to decrease (see Figure 3-8).

A runback in reactor power of 20% per minute was manually initiated immedi-ately after letdown was isolated (see Figure 3-5). MFW was automatically ramped by the ICS to match core power (Figure 3-6), and maintain a constant Tavg (Figure 3-7).

When reactor power and steam load were within the tarbine bypass capacity, 25%, .the ' reactor and turbine were tripped. The turbine bypass system con-trolled secondary pressure while the loss of heat source on the primary side caused the RCS to contract. The RCS contraction caused a pressurizer outsurge and the pressurizer level decreased. Pressurizer sprays were initiated to reduce system pressure to s1700 psia, at which time the pres-surizer level began to increase due to MU and HPI (Figure 3-8).

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The minimum indicated post-trip pressurizer level was 23 inches. Once pres-surizer level began increasing, the analysis was terminated because it was assumed the operator would cooldown and depressurize the RCS while maintain- ,

ing a minimum subcooled margin. The subcooled margin at the termination of the analysis was 52F. Figures 3-4 through 3-16 show the transient respons-es of pertinent parameters.

Plant Condition at Termination of Analysis -- Table 3-3 lists the sequence of events for this analysis.

Power level 82 MWt Hot leg temperature 558.73F Hot leg pressure 1674.0 psia Tavg 558.5F System flow rate 39,858 lbm/s Pressurizer level (indicated) 30.8 in.

Bypass steam flow rate 113.26 lbm/s Subcooling margin 52.28F 3.4. Conclusions Operator action, in accordance with the ATOG, to stabilize RCS pressure and pressurizer level, run back the plant, and trip the reactor does preclude sufficient loss-of-subcooling margin to result in the indication for a need N to trip the RC pumps.

[l Table 3-1. HPI and MU System Capacities

1. MU Flow Rate Vs Pressure ,

Pressure, psig Flow Rate, gpm 1300 1525 1920 2090 2235 2370 2480 2640 2720 1 Pump (vwo) 307 282 232 207 182 157 132 82 32 2 Pumps (vwo) 454 416 346 309 274 237 194 127 50

2. HPI(a) Flow Rate Vs Pressure (two pumps)

Pressure, psig 185 395 745 1025 1375 1555 1755 1820

( Flow Ratr, gpm 1825 1715 1500 1310 1000 805 400 0.0 (a) Coupled with low pressure injection (LP?) in " piggyback" operation.

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L Table 3-2. REDBL5 Volume and Junction Description Component No.

100,105,110-1 to 110-5 Hot leg 200,205,210-1 to 210-5 130,230 SG 1niet plenum 140-1 to 140-10, 240-1 to 240-10 S3 primary tube region 145,148,245,248 SG outlet plenum 150,180,250,280 Cold leg (pump suction) 191,181,261,281 RC pump 170,175,190,195 Cold leg (pump discharge)

(- 270,275,290,295 301,305,310-1 to 310-3 RV downcomer 315,320 RV lower plenum 325 Core bypass i

330-1,330-2,330-3 Core 345,350,355,360,365 RV upper plenum and head region 370,371 Vent valves (not used) 407 Pressurizer 408 Surge line 411 Spray valve 415,503 Pressurizer safety valves (not used) 501,502,651,751 Main steam safety valve and sink 551,552 Turbine 600,610,700,710 MFW piping h

601,701 MFW isolation valve s 615,620-1 to 620-4 SG downcomer 715,720-1 to 720-4

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Table 3-2. (Cont'd)

Component ,

625-1 to 625-5,630,635,640,645,648 SG secondary tube region 725-1 to 725-5,730,735,740,745,748 f 650,750 Steam risers 655,755 Steam piping 656,756 Main steam isolation valve 675,775 Steam chest 676,776 TSV 680 Main steam crossover 690,790,940,945 Auxiliary feedwater 800,801' Turbine bypass 802,803 Turbine bypass valves 904,911 MU system 905,906,907,908 HPI 915,920,925,930 909,910 Low pressure injection (not used)

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t Table 3-3. SGTR Sequence of Events Time after rupture, .

Event min:sec SGTR at full power 0:00  ;

( MSL radiation monitors and/or condenser air ejector 0:00 radiation monitors trip high secondary activity alarms Low pressuriter level alann 1:03 Operator starts second MU pump 3:00 Operator isolates letdown 3:30 Operator initiates reactor runback 4:00 Operator aligns HPI and LPI pumps in " piggyback" mode 4:00 to 7:45 Operator trips reactor and turbine 9:15 Minimum indicated pressurizer level of 23 inches 12:02 h Analysis terminated 12:45

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130 7 48 4 140-1 i n 745 140-2 740 -3 735 -4 7 15 730 -5 811

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COMPONENT DESCRIPTION 130 SG UPPER PLENUM 140-1 T0 140-10 SG PRIMARY TUBE REGION

( 145 715, 720-1 TO 720-4 SG LOWER PLENUM SG DMelCOMER

, 725-1 T0 725-5, 730 $6 SECONDARY TUBE REGION 735, 7W, 745, 748 810 UPPER END OF RUPTURED OTSG TUBE 81l L,0WER END OF RUPTURED OTSG TUBE f - - - - - - ___ -- --- - - -

t Figure 3-3.- Operator Actions Following SGTR SGTR AT FULL POWER 1 P e

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( PRESSURIZER LEVEL OPERATOR AllGNS HPI

( DECREASES. MAKEUP AND LPI IN Pl6GY-CONTROL VALVES OPEN 8AM DE TO MAINTAIN RCS

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OPERATOR TRIPS LOW PRESSURIZER LEVEL TUR81ME AND REACTOR OCCURS AT 180" (IMDI CATED)

/T rw v P OPERATOR INITI ATES OPERATOR STARTS 2ND PRESSURIZER SPRAYS MAKEUP PUNP TO DEPRESSURPE TO l ~ 1700 P SI G AN D ALLOWS HPl T0

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OPERATOR ISOLATES L ETDOWN

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( U OPERATOR INITI ATES MAIIUAL RUIIBACK OF

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? .; . . x % M p ,.,..c._.,. .. ; g.: t +.e a m y. w S;,.,..e;:/.;, x ; . o n . .:rt,:ca.:. - yA , .. e z. G;.',*V-s. y p. . / ,:y ,# ( 2., q, ..,n .p. f.~ .[ ly.; ~ ... t , . . .; ~ .g .A ..si '3.. -. .,. 71.:dn - L .; ,, 4. REFERENCES ,+ >. . Je ? . .M' *. ' f. yc . , t s .p .NJ. . LOCA and . ; -n . K ".h :J. - m 1. REDBL5 -- An Advanced Computer Program for Light-Water f RELAP 5, Reactor :x

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. .. Non-LOCA Transient Analysis -- Babcock & Wilcox 984. Versioa o n ~.::; k

1. i 5 UPGD-TM-7_, Rev E, Babcock & Wilcox, Lynchburg, d lines, Virginia, May -

1 ,/v <?ki 2. Arkansas Nuclear One -- Unit 1 Abnormal Transient 74-1122058-00, Babcock & Wilcox, Ooerating

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