ML20235G677
| ML20235G677 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 02/28/1989 |
| From: | Coslow B, Cranford E, Swamy S WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP. |
| To: | |
| Shared Package | |
| ML20011C537 | List: |
| References | |
| WCAP-12087-S01, WCAP-12087-S01-R01, WCAP-12087-S1, WCAP-12087-S1-R1, NUDOCS 8902230331 | |
| Download: ML20235G677 (33) | |
Text
- _ _
WESTINGHOUSE CLASS 3 j
WCAP-12087 Rev. 1 Supplement 1
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i 99 ADDITIONAL INFORMATION IN SUPPORT OF THE EVALUATIONS FOR THERMAL STRATIFICATION OF THE PRESSURIZER SURGE LINES OF THE SOUTH TEXAS PROJECT UNITS 1 AND 2 NUCLEAR POWER PLANTS E. L. Cranford S. A. Swamy B. J. Coslow D. H. Roarty Y. S. Lee a
R. W. Carlson J
February 1989 Verified by:,Mgghk ,
t . d .' W i t t '
t Approved by: !/ !t/ M k G. A. Antakif/ Manager Approved by:
- 5. 5.'Palusamy, Manager
/[/M System Structtral Analysis Structural Materials Engineering Work Performed Under Shop Order HELP-90073 e
WESTINGHOUSE ELECTRIC CORPORATION l Nuclear and Advanced Technology Division P.O. Box 2728 Pittsburgh, Pennsylvania 15230-2728 ,
8902230331 890213 PDR ADOCK 05000498 *)
f P PDC jj
TABLE OF CONTENTS-i" 9"
Section ,
. Title .Page
1.0 INTRODUCTION AND BACKGROUND
1-1 2.0 LEAK BEFORE BREAK CONSIDERATIONS 2-l' 2.1 Background Information 2.2 Leak Rate Calculations 2.3 Conclusion 3.0 REACTOR COOLANT SYSTEM (RCS) C00LDOWN STRATIFICATION 3-1 TEMPERATURE 3.1 Reactor Coolant System Temperatures 3.2 Pipe Versus System Temperature Differences 3.3 Conclusion
4.0 REFERENCES
4-1 APPENDIX A Errata Sheets for Revision 1 of WCAP-12067 A ,1 l
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L LIST OF TABLES Table Title p;'~
2-1 Comoarison of Experimentally Determined Leak Rates and Analytical Predications
~2-2 Data from the 4-Point Bend Test 3-1 Significant Thermal Transients
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LIST OF FIGURES O
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l Figure Title 2-1 Comparison of Leak Rate Calculation Obtained by W-Computer Code with that Obtained by PICEP - Code 2-2 Comparison of Measured Leak Rate (Duane-Arnold) with that Obtained by W-Computer Code
. 2-3 Comparison of Measured Leak Rate (Duane-Arnold) with that Obtained by Using PICEP Code 2-4 Comparison of Measured Leak Rate (Duane-Arnold) with that Obtained by using PICEP Code (1000 u-in roughness)
~
2-5 Pipe Test Set-up in 400,000 lb Test Machine 2-6 Comparison of Crack Opening Area 2-7 Schematic of Crack Opening-2-8 Clip Gage Openings 3-1 Normal Cooldown i
3-2 [' Ja,c.e Actual Cooldown due to an RCS Leak 3-2 [ 3a,c e Actual Cooldown 3-4 [ Ja,c.e Location 1 Cooldown System AT and Pipe
,. AT vs. Time asess/naises to y
1.0 INTRODUCTION AND BACKGROUND
From January 30 to February 2, 1989, the NRC and its consultant conducted a detailed technical review of Westinghouse report WCAP-12067 revision 1 -
[ " Evaluation of Thermal Stratification for the South Texas Units 1 and 2 Pressurizer Surge Line."
During the technical-review, which was performed at the Westinghouse offi,ces in Pittsburgh and at the South Texas Site, Houston. Lighting and Power Co.
' committed to provide the staff with additional information on two areas related to the siirge line evaluation. These two area were:
9 o Clarification of leak rate c ..ulations in the evaluation of leak-before-break.
o Justification for using 250'F as the maximum differential (stratification) top-to-bottom pipe temperature, during a cooldown
~- following a leak in the reactor coolant system, as considered in one of.the-leak-before-break cases.
O The purpose of.this report is to provide the additional information, requested by the staff, on these two items.
In addit' ion, appendix A contains three errata sheets for chapter 1, of WCAP-12067 rev. 1.
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2.0 LEAK RATE ANALYSIS' 2.1 Background Information
,'_ The Westinghouse computer <; ode to calculate leak rates was developed in the latter part of the 1970's. The Code was verified by comparison with experimental data and the results were presented in WCAP-9558, Rev. 2 (reference 1).
In 1986 the NRC staff requested that the code be benchmarked against newer data. Specifically, benchmark calculations were performed in WCAP-11256,-
. supplement 1 (reference 2) and compared with the leakage observed in the recirculation pipe at Duane Arnold Nuclear Power Plant. Also the predication using the PICEP code (reference 3) were compared in that WCAP.
In recent application to the pressurizer surge line the staff calculated, using the PICEP code, the flaw size for a 10 gpm leakage to be about 7 inches while the flaw size predicted by the Westinghouse computer codes was [
Ja,c.e long. The staff requested explanation to justify the difference.
2.2 Leak Rate Calculation The objective of the leak rate calculations can be summarized briefly as follows:
Calculate best estimate leak rs.tes from postulated through wall flaws.
o o Demonstrate leak detection by comparing calculated leak rates with the leak detection capability
( ,
o A margin of a factor of 10 between the calculated leak rates and the plant leak detection capability is recommended.
For a given geometry and loading the calculated leak rates depend on the assumption pertaining to the crack shape and crack surface roughness. In t = ' "
- 2-2
[
figure 2-1, the Westinghouse computer code results are based on a crack surface roughness value of [ Ja,c.e The validity of this assump-
$ tion was justified in WCAP-9558 (reference 1). In addition, the Westinghouse
. code uses the [ Ja c.e crack shape assumption. As seen in figure
- c. 2-1, the PICEP Code provides several options for the user and depending on the severity of the assumptions, very conservative to conservative leak rate results are obtained. The assumption of [ Ja,c.e roughness with elliptic shape gives extremely conservative results (7.2 inches long flaw for 10 gpm leak rate.) The severity of the [ Ja,c.e assumption is seen by comparing figure 2-2, 2-3, and 2-4. Specifically figure 2-4 demonstrates that the observed leakage data are grossly under-estimated by the PICEP Code with [ la,c.e roughness. Note that the PICEP Code predictions were validated in figure 2-3 using a roughness of 200 u-in.
From figure 2-1 it is also clear that for comparable assumptions of
[ la,c.e roughness, the PICEP prediction of
[ la,c.e and the Westinghouse prediction of [ Ja,c.e differ by about 20%. This difference could be expected because the crack opening area models are different between the PICEP Code and the Westinghouse code. In addition, the two phase flow models are also different.
A comparison of the experimental data (reference 2) with predicted leak rates using both the Westinghouse Code and the PICEP Code is provided in table 2-1.
As seen from this table the Westinghouse prediction is about 98% of the measured leak rate, and therefore should be considered as the conservative best estimate prediction. The PICEP cod; aith [ Ja,c.e roughness and elliptic section assumption sig?ificantly underpredicts the leakage (calculated leakage being only about 40% of the measured value.) The PICEP code with [ Ja,c.e roughness and rectangular section assumption predicts the leakage to be about 80% of the measured value. '
A four point bend test was conducted on a 4-inch schedule 80 pipe (see figure 2-5.) The crack opening area comparison is shown in figure 2-6. The predictions using the Westinghouse code shows good correlation. The PICEP predictions are more conservative especially in higher load levels. The clip am. ewe 2-3
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gage readings and the crack shape are schematically shown in figure'2-7. .The clip gauge readings are plotted in figure 2-8. Relevant details on.theitest'
-- are provided in table 2-2..
2'. 3 Conclusion The 7.2 inches-long leakage size flaw for the STP surgeline calculated using the PICEP code is extremely conservative. Westinghouse prediction of (
Ja,c.e long leakage size flaw provides a best estimate yet
' conservative prediction.
. Westinghouse predictions and the PICEP Code predications were compared with.
experimental data. _ Westinghouse codes appear to produce conservative yet best estimate results. The PICEP results are seen to be more conservative. The
. degree of conservatism depends on the options and assumptions employed in the PICEP computer runs.
Since a factor of 10 is applied with respect to the calculated leak rates, the Westinghouse leak rate calculation (conservative yet best estimate) presented in WCAP-12067 are considered to be applicable.
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DATA FROM THE 4 POINT BEND TEST I
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I 3.0 REACTOR COOLANT SYSTEM (RCS) C00LDOWN STRATIFICATION TEMPERATURE CONSIDERATIONS This section provides additional.information for the postulated leak-before-
. break (LBB) case B/F, as described in section 5 of WCAP-12067,-Rev.:1. This '
is a case in which a leak rate of 1 gpm (Tech Spec Limit)'is assumed during normal power conditions. The plant is then cooled down to locate and repair the leak. The specific area of interest is the maximum pipe AT (Pipe Top-Bottom Temp) that is postulated to occur during the cooldown. Two factors are used to predict the pipe AT; the system AT (pressurizer temp - hot leg temp), and the ratio of pipe AT to_ system AT (measured during testing).
3.1 Reactor Coolant System Temperatures The postulated leak rate for case B/F would not be expected to cause the activation of any safety injection systems. Therefore, the generic Westinghouse procedure " Plant Shutdown from Minimum Load to Cold Shutdown" would apply. This procedure is the basis for the discussion which follows.
Information from South Texas Project Unit 2 (STP-2) procedures will be inserted as appropriate.
A plot of the pressurizer water temperature and the reactor coolant water temperature during a typical normal cooldown is illustrated in figure 3-1.
The curves shown depict the band of temperatures possible per STP-2 procedures (representative of both Units 1 & 2) and the temperatures expected for the cooldown following discovery of a leak in the RCS. Initially, the pressurizer centains a steam bubble with the water level at 25% of level span (no load conditions). Early during the cooldown procedure, all but one (two pumps for STP-2) of the reactor coolant pumps are stopped. The operating pump is in the loop to which the pressurizer surge line and a spray line are connected.
In general, the process can be divided into three phases; first from 0 to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the pressurizer water and reactor coolant system water are cooled down together with the reactor coolant temperature maintained approximately 50 to newon=e,o 33
- _ _ - _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ - _ = - - _ - - - - _ _ _ - _ _ _ _ _ --___- - _ _ , _
100*F below the pressurizer saturation temperature. This temperature difference is mandated by subcooling requirements of the RCS. At 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />,
',. when the reactor coolant pressure and temperature have decreased to
. approximately 400 psig (350 to 425 psig range for STP-2) and 350*F, the
. residual heat removal system is placed in operation. From approximately 4 to a 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />, the pressurizer pressure remains constant at the pressure required to operate the reactor coolant pumps while the reactor coolant temperature continues to decrease to 160'F. When the reactor coolant system temperature has deceased to 160*F (100*F for STP-2), the operating reactor coolant pump is stopped. From 16 to 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />, the rystem is depressurized using auxiliary spray. The steam bubble in the pressurizer is collapsed when the pressure has been decreased to 25 psig.
Based on'the above discussion, the maximum temperature difference between pressurizer water and hot leg water is 354*F, that is, the difference between the saturation temperature of 454'F corresponding to 425 psig and the reactor coolant system temperature of 100'F. This temperature difference is the maximum potential temperature difference and is considered (when corrected to pipe versus system AT, section 3.2) in the stress and fatigue analysis and
., the LBB case C/G.
The case under question is the postulated scenario of a 1 gpm leak being detected at full power and the subsequent cooldown to locate and repair the lenk(caseB/F). For this case a more realistic postulation of RCS conditions is assumed.
Per STP-2 procedures, the leak will be located while the plant is in mode 3, or time 0-4 hours on figure 3-1. Per discussions with STP operation personnel, if a leak in the RCS was detected the first priority would be to depressurize the system. This depressuri::ation would most likely occur when
.the RCS is at approximately 180*F as illustrated in figure 3-1 at time 12
- hours. Therefore, the maximum expected system temperature difference would be between 274*F (454'-180*F) and 256*F (436*-180*F). For the analysis of case B/F the system temperature difference is assumed to be 274*F.
sin.mm io 3-2
3.2 Pipe Versus System Temperature Difference I
The maximum expected pipe AT (Pipe T Top - Pipe TBottom) is a function of
. the system AT.
4
- Thermal hydraulic considerations and actual monitoring data indicate that, for I
the phase of the cooldown considered herein, the pipe AT will always be less than the system AT. The phase of cooldown under investigation occurs after the reactor has achieved cold shutdown status. Data from the entire plant cycle (as available) was considered even though there was significantly less thermal activity observed during plant cooldowns. This investigation is based on monitored thermal transient information from [ la,c.e plants (including South Texas). The number of thermal transients considered signifi-cant in this investigation was [ la,c.e These transients are provided in table 3-1.
The mean (x) of the ratio of pipe AT to system AT was determined to be
, [ Ja,c,e The maximum range of the data showed that the ratio of pipe AT to system AT varied from [
Ja,c.e It should be noted that a significant number of. thermal transients were observed with pipe AT to system AT ratios much lower than
[ Ja,c.e These transients were excluded from consideration for conservatism.
3.3 Conclusions The pipe AT is detsrmined from the system AT (3.1) and the ratio of the pipe to system AT (3.2). The maximum rystem AT is 274*F based on the arguments of section 3-1. The ratios of pipe to system AT were between [
3a,c.e Therefore, the magnitude of pipe AT's expected for case B/F are between
[ Ja,c.e and [ Ja,c.e with a mean of [ Ja,c e The pipe AT used in the analysis of case B/F was [ la c,e sm.mim io 3-3
Additional data obtained to date from actual plant cooldown supports the above position. Figure 3-2 (reference [ Ja,c.e shows the pressurizer and RCS hot leg t' temperatures vs. time for two consecutive cooldowns. The maximum system AT was [' la,c.e; the pipe AT was not monitored during this cooldown. The first cooldown was due to a weld leak on the seal injection l line and is typical of the type of response expected for a small leak that did not require a safety injection. The second cooldown was for repairs on the secondary side of a steam generator manway gasket (also detected as a leak in containment).
Figure 3-3 (reference [ ]a c.e illustrates the system temperatures from another cetual plant cooldown. The maximum system AT obtained was
[ ]a,c.e Pipe AT's were also obtained for this period and are shown in figure 3-4 along with the system AT. The maximum pipe AT's for this cooldown was less than [ ' ]a,c.e S
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TABLE 3-1 ,
i' SIGNIFICANT THERHAL TRANSIENTS SOUTH TEXAS Pipe AT System AT %
a,c.e
, [. Ja,c.e Pipe AT System AT %
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TABLE 3-1 (cont.)
SIGNIFICANT THERMAL TRANSIENTS
[ ]a,c.e Pipe AT System AT %
a,c.e
[ 3a,c.e Pipe AT System AT %
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4.0 REFERENCES
., 1. Palusamy, S.S. and Hartmann,-A.J., " Mechanistic Fracture Evaluation of Reactor Coolant Pipe Containing a Postulated Circumferential Through-Wall
~ Crack", WCAP-9558 Rev 2, Class 2, 1982 (Westinghouse Proprietary Class 2).
4
- 2. Swamy, S.A., Witt, F.J. and Bamford, W.H., " Technical Bases for Eliminating Pressurizer Surge Line Ruptures as the Structural Design Basis for South Texas Project Units 1 and 2," WCAP-11256 Supplement.1, November 1986 (Westinghouse Proprietary Class 2).
- 3. Norris, D.M. and Chexal, B., "PICEP: Pipe Crack Evaluation Program (Revision 1)," EPRI NP-3596-SR, Revision 1, Special Report, December 1987.
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APPENDIX A.
ERRATA ~FOR REVISION 1 0F WCAP-12087 o.
[ :,. Three errata sheets are contained herein; one for page 1-12, one for figure
< 1-24, and one for table 1-8.
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(b) Full stratification cycles are assumed fer all transients, except for steady state fluctuations, unit loading and unloading, and reduced temperature return to power, where level fluctuations are ,
< sufficiently conservative based on flow rate and observations.
- (c) The temperature of stratification was based on the minimum hot leg temperature at any time during the transient (for bottom of pipe) and the maximum pressurizer temperature (for top of pipe). Figure 1-20 shows a case where this resulted in a very conservative 260*F stratification transient although the maximum temperature difference at any point in time was about 50'F.
(d) The current number of design cycles of each event is unchanged.
The normal and upset transients modified to account for the stratification phenomena are listed in tables 1-3 and 1-4.
1.2.7 Temperature Limitations During Heatup and Cooldown (table 1-8)
., The maximum top to bottom pressurizer surge line temperatures are limited by the system temperature difference between the pressurizer and the RCS hot leg. For South Texas Units 1 and 2 the maximum system temperature AT during heatup is limited to 314 F as a result of administrative procedures. During cooldowns the maximum system temperature difference is limited to 354'F again as a result of administrative procedures. For design purposes the maximum possible top to bottom stratification temperature is limited to 320 F (although none of this measured top to bottom pipe temperatures, in any plant, exceeded AT = [ 3a,c.e in the pipe even when the system AT was close to 320'F between the pressurizer and RCS hot leg.)
With the RCL cold, the pressurizer pressure (and therefore temperature) is limited by the cold overpressure mitigation system (COMS).
c.
Practically, plants operate to minimize downtime and heatup-cooldown time, when power is not being generated. The times at large AT are therefore reasonably limited, as discussed later.
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y TABLE 1-8 PLANT OPERATIONAL CONSTRAINTS 4
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. o Administrative Limits Result in Approximately [ Ja,c.e Between Pressurizer and Spray Temperatures During Heatup and [ Ja,c.e t
During Cooldowns o Reactor Coolant System Pressure of [ Ja,c.e required for RCP operation [ Ja.c.e o Cold Overpressure Mitigation Requires - Minimize Pressure at Low RCS Temperatures (Appendix G Curves) - Steam Bubble Beneficial for Minimizing LTOP.
o Overall Goal to Maximize Time at Power
~*
o Recent Administrative Limits on Minimum RCS Temperature Prior to
{ Pressurizer Heatup l
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