ML20215M109
| ML20215M109 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 05/31/1987 |
| From: | Nalezny C, Yuan C EG&G IDAHO, INC., IDAHO NATIONAL ENGINEERING & ENVIRONMENTAL LABORATORY |
| To: | NRC |
| Shared Package | |
| ML20215M101 | List: |
| References | |
| CON-FIN-D-6005, RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM EGG-NTA-7721, NUDOCS 8706260278 | |
| Download: ML20215M109 (33) | |
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INFORMAL REPORT
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TMI' ACTION--NUREG-0737 (II.D.1)
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RELIEF AND SAFETY VALVE TESTING g
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DISCLAIMER i
This report was prepared as an account of work sponsored by an-
. agency of the United States Government. Neither the United States Government nor any agency thereof, or any of their
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employees, makes any warranty, expressed or_ implied,'or assumes
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any. legal liability or responsibility for any third party's use.
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EGG-NTA-7721 TECHNICAL EVALUATION REPORT TMI ACTION--NUREG-0737 (II.D.1)
SOUTH TEXAS, UNITS 1 AND 2 Docket Nos. 50-498 and 50-499 i
C. Yuan C. L. Nalezny May 1987 IDAHO NATIONAL ENGINEERING LABORATORY EG&G Idaho, Inc.
Idaho Falls, ID 83415 Prepared for the the U. S. Regulatory Commission Washington, DC 20555 Under DOE Contract No. DE-AC06-761001570 FIN No. D6005 t
ABSTRACT 1
4 Light water reactors have experienced a number of occurrences of i
improper performance of safety and relief valves installed in the primary cooiant system. As a result, the authors of NUREG-0578 (TMI-2 Lessons Learned Task Force Status Report and Short-Term Recommendations) and
)
subsequently NUREG-0737 (Clarification of TMI Action Plan Requirements) recommended that programs be developed and completed which would reevaluate the functional performance capabilities of Pressurized Water Reactor (PWR).
safety, relief, and block valves and which would verify the integrity of the piping systems for normal, transient, and accident conditions. This report documents the review of these programs by the Nuclear Regulatory Commission l
(NRC) and their consultant, EG&G Idaho, Inc.
Specifically, this review examined the submittals-of the applicant for the South Texas Project,.
Units 1 and 2, to the requirements of NUREG-0578 and NUREG-0737 and finds j
that the applicant has provided acceptable submittals and responses-to requests for additional 'information, thereby reconfirming that the General Design Criteria 14, 15, and 30 of Appendix A to 10 CFR 50 have been met.
FIN No. D6005--Evaluation of CW Licens,ing Actions-NUREG-0737, II.D.1 ii
CONTENTS ABSTRACT..............................................................
ii 1.
INTRODUCTION.....................................................
1 1.1 Background.................................................
1 1.2 General Design Criteria and NUREG Requirements.............
1 2.
PWR OWNERS' GROUP RELIEF AND SAFETY VALVE PROGRAM................
4 o
3.
PLANT SPECIFIC SUBMITTAL.........................................
6 4.
REVIEW AND EVALUATION...........................................
7 4.1 Valves Tested..............................................
7 4.2 Test Conditions............................................
8 4.2.1 FSAR Steam Transients..............................
8 4.2.2 FSAR Liquid Transients.............................
11 4.2.3 Extended High Pressure Injection Event.............
11 4.2.4 Low Temperature Overpressure Transient.............
12 4.2.5 PORV Block Valve Fl uid Conditions..................
12 4.3 Operability................................................
13 4.3.1 Safety Valves......................................
13 4.3.2 Power Operated Relief Valves.......................
15 4.3.3 El ectri c Control Ci rcuitry.........................
16 4.3.4 PORV Block Valves..................................
17 4.4 Piping and Support Evaluation..............................
18 4.4.1 Thermal Hydraul i c Analysi s.........................
18 4.4.2 Stress Analysis....................................
20 5.
EVALUATION
SUMMARY
24 6.
REFERENCES.......................................................
26 iii
TECHNICAL EVALUATION REPORT TMI ACTION--NUREG-0737 (II.D.1)
SOUTH TEXAS PROJECT, UNITS 1 AND 2 DOCKET NO. 50-498 and 50-499 1.
INTRODUCTION
1.1 Background
Light water reactor experience has included a number of instances of improper performance of relief and safety vab cs installed in the primary coolant system. There have been instances of valves opening below set pressure, valves opening above set pressure, and valves failing to open or reseat. From these past instances of improper valve performance, it is not known whether they occurred because of a limited qualification of the valve or because of a basic unreliability of the valve design.
It is known that j
the failure of a power-operated relief valve (PORV) to reseat was a significant contributor to the Three Mile Island (TMI-2) sequence of events. These facts led the task force which prepared UUREG-0578 (Reference 1) and, subsequently, NUREG-0737 (Reference 2) to recommend that programs be developed and executed which would reexamine the functional j
performance capabilities of Pressurized Water Reactor (PWR) safety, relief, and block valves and which would verify the integrity of tne piping systems for normal, transient, and accident conditions. These programs were deemed necessary to reconfirm that the General Design Criteria 14, 15, and 30 of Appendix A to Part 50 of the Code of Federal Regulations, 10 CFR, are indeed satisfied.
1.2 General Design Criteria and NUREG Reauirements General Design Criteria 14, 15, and 30 require that (a) the reactor primary coolant pressure boundary be designed, fabricated, and tested so as to have an extremely low probability of abnormal leakage, (b) the reactor coolant system and associated auxiliary, control, and protection systems be designed with sufficient margin to assure that the design conditions are 1
1
i not exceeded during normal operation or anticipated transient events, and (c) the ccmponents which are part of the reactor coolant pressure boundary shall be constructed to the highest quality standards practical.
4 To reconfirm the integrity of overpressure protection systems and thereby assure that the General Design Criteria are met, the NUREG-0578 position was issued as a requirement in a letter dated September 13, 1979 by the Division of Licensing (DL), Office of Nuclear Reactor Regulation (NRR),
to ALL OPERATING NUCLEAR POWER PLANTS.
This requirement has since been incorporated as Item II.D.1 of NUREG-0737, Clarification of TMI Action Plan Requirements (Reference 2), which was issued for implementation on October 31, 1980.
As stated in the NUREG reports, each pressurized water reactor Licensee or Applicant shall:
1.
Conduct testing to qualify reactor coolant system relief and safety valves under expected operating conditions for design basis transients and accidents.
I 2.
Determira valve expected operating conditions through the use of analyses of accidents and anticipated operational occurrences referenced in Regulatory Guide 1.70, Rev. 2.
3.
Choose the iingle failures such that the dynamic forces on the safety and rilief valves are maximized.
4.
Use the highest test pressures predicted by conventional safety l
analysis procedures.
l 5.
Include in the relief and safety valve qualification program the qualification of the associated control circuitry.
6.
Provide test data for Nuclear Regulatory Commission (NRC) staff review and evaluation, including criteria for success or failure of valves tested.
2
7.
Submit a correlation or other evidence t6 substantiate that the valves tested in a generic test program demonstrate the functionability of as-installed primary relief and safety valves.
This correlation must show that the test conditions used are equivalent to expected operating ~and accident conditions as prescribed in the Final Safety' Analysis Report (FSAR). The effect of as-built relief and safety valve discharge piping on valve operability must.be considered.
8.
Qualify the plant specific safety and relief valve piping and supports by comparing to test data and/or performing appropriate analysis.
3
2.
PWR OWNERS' GROUP RELIEF AND SAFETY VALVE PROGRAM-l In response to the NUREG requirements previously listed, a group of
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1 utilities with PWRs requested the assistance of the Electric Power Research Institute (EPRI) in developing and implementing a generic test program for l
pressurizer power operated relief valves, safety valves, block valves, and associated piping systems.
The Houston Light and Power (HL&P), owner of the South Texas Project, Units 1 and 2, was one of the utilities sponsoring the EPRI Valve Test Program. The results of the program are contained in a group of reports which were transmitted to the NRC by Reference 3.
The applicability of these reports is discussed below.
EPRI developed a plan (Reference 4) for testing PWR. safety, rel.ief, and block valves under. conditions which bound actual plant operating conditions.
EPRI, through the valve manufacturers, identified the valves used in the overpressure protection systems of the participating utilities.
Representative valves were selected for testing with a sufficient number of the variable characteristics that their testing would adequately demonstrate -
the performance of the valves used by utilities (Reference 5).
of the participating utilities and arrived at a test matrix which bounded the plant transients for which overpressure protection would be required (Reference 6).
EPRI contracted with Westinghouse Electric Corp. to produce a report on the inlet fluid conditions for pressurizer safety and relief valves in Westinghouse designed plants (Reference 7).
Since South Texas, Units 1 and 2, were designed by Westinghouse this report is relevant to this evaluation.
Several test series were sponsored by EPRI.
PORVs and block valves
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I were tested at the Duke Power Company Marshall Steam Station. located in Terrell, North Carolina. Additional PORV tests were conducted'at the Wyle Laboratories Test Facility located in Norco, California.
Safety valves were tested at the Combustion Engineering Company, Kressinger Development 4
J Laboratory, located in Windsor, Connecticut.
The results for the relief and safety valve tests are reported in Reference 8.
The results for the block i
valves tests are reported in Reference 9.
l The primary objective of the EPRI/C-E Valve Test Program was to test each of the various types of primary system safety valves used in PWRs for i
the full range of fluid conditions under which they may be required to operated.
The conditions selected for testi (based on analysis) were limited to steam, subcooled water, and steam to water transition. Additional objectives were to (a) obtain valve capacity data, (b) assess hydraulic and j
structural effects of associated piping on valve operability, and (c) obtain piping response data that could ultimately be used for verifying analytical piping models.
Transmittal of the test results meets the requirement of Item 6 of Section 1.2 to provide test data to the NRC.
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3.
PLANT SPECIFIC SUBMITTAL j
l A plant specific evaluation of the adequacy of the overpressure protection system for South Texas, Units 1 and 2, was submitted by HL&P to l
the NRC on October 31, 1985 (Reference 10).
A request for additional information was sent to HL&P on January 2, 1987 (Reference 11) to which the applicant responded on March 2, 1987 (Reference 12), and May 8, 1987 (Reference 13).
The response of the overpressure protection system to Anticipated 4
Transients Without Scram (ATWS) and the operation of the system during feed 1
i and bleed decay heat removal are not considered in this review.
Neither the
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Licensee nor the NRC have evaluated the performance of the system for these f
events.
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4.
REVIEW AND EVALUATION i
4.1 Valves Tested South Texas, Units 1 and 2, are four-loop PWRs designed by the Westinghouse Electric Co.
Each unit.is equipped with three (3) safety valves, two (2) PORVs, and two (2) PORV block valves in its overpressure protection system. The safety valves are 6-in. Crosby Model HB-BP-86, 6N8, spring loaded valves with loop seal internals. The design set pressure is 2485 psig and the rated steam flow capacity is 502,000.1bm/h.
The PORVs are 3-in. Garrett power operated relief valves Model 3750014 of the straight through design. The PORV opening set pressure is 2335 psig and the rated steam flow capacity is 210,000 lbm/h.
The PORV block valves are 3-in.
Westinghouse Model 3GM88 gate valves with Limitorque SB-00-15 motor operators. The inlet pipes to the safety valve and PORVs include cold loop seals.
A Crosby Model HB-BP-86, 6N8, safety valve was tested by EPRI. The test valve is identical to the safety valves installed at South Texas in every respect except the valve internals and the inlet piping configuration. The test valve used steam internals and was tested in the j
long pipe configuration without a loop seal.
The in plant valves have loop I
seal internals and are mounted on inlet piping with loop seals. The difference between steam and loop seal internals is only in the material used; it is not expected to affect valve operability. However, unlike the valve internals, the water seal in the inlet piping is known to have significant effects on the valve performance.
The test results of the 6N8 safety valve without loop seals is not completely applicable to the South Texas valves. Another Crosby safety valve, the 6M6, which is of the same model and design as the South Texas safety valves but different in size was also tested by EPRI. The 6M6 valve has a smaller orifice than the 6N8 (2.154 in. ver.as 2,362 in. in nozzle bore diameter) and a lower flow rate (420,000 lbm/h versus 502,000 lbm/h in rated flow). The difference in orifice size only affects the flow rate but not the valve behavior. Other j
minor variations such as the disk holder type and material of construction i
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do not have a significant effect on operability.
The 6M6 valve was tested in loop seal piping configuration similar to the in-plant valves. The j
results of the EPRI tests on the Crosby 6M6 and 6N8 valves are, therefore, j
adequate to demonstrate the operability of the South Texas safety valves.
l The Garrett power operated relief valve and the Westinghouse j
Model 3GM88 gate valve (with Limitorque SB-00-15 operator) tested by EPRI l
are identical to the PORVs and PORV block valves installed at the plant.
1 The test results for these valves are directly applicable to the plant specific valves. Therefore, those parts of the criteria of Items 1 and 7 as identified in Section 1.2 of this report regarding applicability of the test valves are fulfilled.
i 4.2 Test Conditions I
1 The valve inlet fluid conditions that bound the overpressure transients for Westinghouse designed PWR Plants are identified in Reference 7.
The 1
transients considered in this report include FSAR, extended high pressure l
injection, and low temperature overpressurization events. The conditions
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applicable to South Texas are those identified in Reference 7 for a four
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loop reference plant.
The expected fluid conditions for each of these events and the applicable EPRI tests are discussed in this section.
4.2.1 FSAR Steam Transients For the South Texas PWRs, the limiting FSAR transients resulting in steam discharge through the safety valves alone and in steam discharge through both the safety and relief valves are the loss of load event (for i
maximum pressurizer pressure) and the locked rotor event (for the maximum pressurization rate).
In the case when the safety valves actuate alone, the maximum pressurizer pressure and maximum pressurization rate are predicted to be 2555 psia and 144 psi /s, respectively.
The loop seal temperature upstream of the safety valve is 2000F and the maximum developed backpressure in the outlet piping is 500 psig (Reference 10).
t 8
l EPRI tests representative of the valve inlet fluid conditions for the limiting transients were selected for the plant specific evaluation.
In selecting the EPRI tests, the safety valve ring settings, the pressure drop through the inlet pipe and the loop seal temperature were also considered.
The licensee provided the ring settings used at South Texas 1 and 2 in Reference 13. The upper ring settings ranged from -140 to -240 relative to the highest locked position, and the lower rings were set at -18.
The ring settings were established by the manufacturer and are comperable to the typical factory ring settings used in the EPRI/CE tests. The test conditions for the 6N8 and 6M6 safety valves are discussed individually in the following paragraphs.
The 6N8 valve was tested in long inlet piping configuration without loop seal.
Five steam tests were performed with three sets of different ring positions among which two tests were performed using the manufacturer recommended ring settings (Test No. 1202, 1203, 1205, 1207, and 1208). The peak pressurizer (tank 1) pressure ranged from 2487 to 2680 psia and the' pressurization rates were 2 to 325 psi /s.
The backpressures developed in the tests were between 200 and 560 psia. The pressure drop calculated for the South Texas inlet piping (Reference 10) are comparable to those of the EPRI test configuration (Appendix B of Reference 14). The above data show that the inlet fluid conditions and backpressures developed in the EPRI tests envelope the predicted conditions of the South Texas safety valves.
Among the steam discharge tests performed on the 6M6 safety valve, there were four tests that used cold loop seals similar to those used at South Texas. The loop seal temperature at South Texas is approximately 0
200 F; the loop seal temperatures and ring positions for the selected 6M6 tests are shown below.
9
Loop Seal Ring Position Temperature Test Number (OF)
Upper Lower 929 90.
-71
-18 Factory ring settings 931a 117
-71
-18 Factory ring settings 1406 147
-77
-18 Factory ring settings
)
1415 290
-77
-18 Factory ring settings 1
Note: Above ring positions are in' notches measured from the level position.
The maximum pressurizer (tank 1) pressures were in the range of 2703 to:
2760 psia and the pressurizer rates were 2.5 to 360 psi /s. The maximum backpressures developed in the downstream piping were from 255 to 725 psia.
For the 6M6 test valve, the inlet piping pressure drop and rise during valve opening and closing were calculated to be 263 and 181 psi respectively. The corresponding pressure differences for the South Texas valves are 300.7 and 174.7 psi. The opening pressure drop for the Test 6N8 vlave is 309 psi,-and j
the closing pressure drop is 165 psi.
The test inlet fluid conditions for.
the steam discharge conditions are, therefore, representative of the expected conditions for the FSAR transient resulting in safety valve steam discharge at the plant.
For FSAR transients resulting in steam discharge through both the safety valve and PORV, the maximum pressure predicted;for the in-plant valve is 2532 psia and the maximum pressurization rate is 130 psi /s. -These fluid parameters represent the limiting condition for steam discharge through the.
PORVs at this plant.
The Garrett PORV was subjected to thirteen steam tests in the EPRI testing program.
In these tests, the maximum pressure at the valve inlet was 2760 psia which bounded the predicted maximum pressure of 2532 psia. The highest backpressure developed at the discharge pipe was 825 psia in the full pressure steam. tests performed at the_ Marshall Facility. The backpressures developed during the two steam tests conducted at Wyle Laboratories were 580 and 623 psia. These test values are higher than the maximum backpressure of 500 psia predicted for the-South Texas 1 and 2 PORVs.
Therefore the EPRI test inlet fluid conditions for the PORV in steam discharge are representative of the plant specific transient conditions.
10
F I
4.2.2 FSAR Liquid Transients The limiting FSAR transient resulting in liquid discharge through the PORVs and safety valves is the main feedline break accident (Reference 7).
The submittal (Reference 10) stated that South Texas was providing a feedline break reanalysis using the new (1979) ANS 5.1 decay heat curves j
with a 2 x sigma uncertainty allowance which showed that the pressurizer would not fill completely during the feedline break transient.
Therefore, the safety valves and PROVs will not be challenged by liquid.
Accordingly, liquid discharge through the safety valves and PORVs in a FSAR liquid transient needs not to be considered.
4.2.3 Extended High Pressure Injection Event The limiting extended high pressure injection transient is a spurious actuation of the safety injection system at power.
Both the safety valves and the PORVs may be challenged by steam and liquid discharges. When the safety valve actuates, the maximum pressure is predicted to be 2507 psia and the liquid temperature ranges from 5670F to 572 F.
When the PORV 0
discharges, the maximum pressure is predicted to be 2353 psia at 0
temperatures between 565 F and 5690F (Reference 7). The pressurization rate in both cases is within 4 psi /s.
The steam discharge conditions for the safety valve and PORV are bounded by the FSAR steam transient condition discussed in Section 4.2.1.
Liquid discharge will not take place until the pressurizer becomes water solid. According to Reference 7, this would not occur until at least 20 minutes into the event which allows ample time for the operator to take appropriate action to terminate the water injection.
Therefore the potential for liquid discharge in an extended HPI can be disregarded.
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- 4. 2.' 4 Low Temperature Overpressurization Transient.
The PORV is used for low temperature overpressure protection during reactor startup and shutdown operations. The possible fluid states at the PORV inlet include steam, water, and water to steam transition conditions.
The licensee indicated in Reference 10 that the maximum range of potential low temperature overpressure fluid conditions at the PORV inlet were enveloped by the pressure versus temperature plot presented in Figure 5-1 in Section 5.4 of Reference 7, which applies to a number of the PWR plants l
analyzed by Westinghouse.
The steam discharge conditions are bounded by the high pressure set point of.2350 psia at 6500F, The full pressure j
(2350 psia) liquid discharges cover the range of temperatures from 2500F i
to 6500F. The reduced pressure (300 psig) liquid discharges are expected over a temperature range of 1000F to 4000F.
For steam discharge through the PORV, the high pressure steam tests discussed in Section 4.2.1 would cover the low pressure steam conditions predicted for the cold overpressure transient.
For liquid discharge, full.
pressure (over 2350 psia) tests were performed with liquid temperatures 4
ranging from 2490F to 6480F.
Reduced temperature tests were performed at temperatures of 1040F and 4470F and at pressure of approximately 685 psia. There was one steam to water transition test performed at 2760 psia and 6820F.
In addition, two full pressure. loop seal. simulation tests at 1300F and 2930F were included to verify the performance of the PORVs with loop seals (such as South Texas).
The above tests provide adequate data for. the evaluation of the South Texas PORVs in low temperature overpressurization events.
4.2.5 PORV Block Valve Fluid Conditions The block valves are required to operate over the same range of inlet fluid conditions as the PORVs. The Westinghouse 3MG88 block valve was only tested for full steam pressures up to 2500 psia in the EPRI test series.
Since no tests were performed for water discharge conditions, the operability of the block valve in water flow condition was not directly demonstrated by the tests.
However, Westinghouse has conducted an 12
)
investigation on the opening and closing performances of the Westinghouse block valve using a valve of similar type (Attachmenc B to Reference 9).
These tests showed that the required torque to open or close the valve depended almost entirely on the differential pressure across the valve disk and was rather insensitive to the momentum load.
Thus, the required force for opening and closing the valve is nearly independent of the type of flow (i.e., water or steam).
Furthermore, according to the friction tests performed by Westinghouse on a stellite coated specimen, the friction coefficient between the stellite surfaces was approximately the same in
)
either steam or water tests.
In some instances, the friction force in water i
was lower than that in steam.
Hence, it would take equal, or even less, force to overcome the disk friction in water when compared to steam.
It can, therefore, be concluded that the full pressure steam tests are adequate to demonstrate the operability of the valve for the expected water conditions.
The test sequences and analyses described above, demonstrating that the test conditions bounded the conditions for the plant valves, verify that Items 2 and 4 of Section 1.2 have been met, in that conditions for the operational occurrences have been determined and the highest predicted pressures were chosen for the test. The'part of Item 7, which requires showing that the test conditions are equivalent to conditions prescribed in the FSAR, is also met.
4.3 Operability 4.3.1 Safety Valves As discussed in Section 4.2, the South Texas safety valves are not expected to discharge liquid in any of the FSAR, HPI, and low temperature overpressurization events, therefore, the following discussion of safety valve operability is limited to steam discharge conditions only. The EPRI tests used to represent the South Texas safety valves are the steam tests on the Crosby 6N8 and 6M6 valves.
The 6N8 test valve is identical to the safety valves installed at South Texas but was tested without loop seal.
The 6M6 valve which is smaller than the in plant valves was tested in the loop seal configuration.
13
In the stean, tests on the 6N8 safety valve (Tests 1202, 1203, 1205, 1207, and 1208), the valve opened within 13% of the design set pressure and performed stably during the tests. The test results showed that two of the tests achieved a lift position which was 97% of the rated lift at 6%
accumulation. The lift positions for the rest of the tests were not recorded.
Also the steam flow rates in percents of the rated flow were not recorded for all the tests.
Excessive blowdown in the range of 15.1 to 16.6% was observed in the tests with the manufacturer recommended ring settings.
For the lowered ring settings, the blowdown was between 9.6% and q
9.8%.
1 In the cold loop seal tests on the 6M6 safety valve (Tests 929, 931a, 1406, 1415), the valve opened at pressures between 1% and 6% above the set pressure.
With the exception of Test 1415, in which stable performance was observed, the valve fluttered or chattered during loop seal discharge and stabilized when steam flow started. The valve opened within 12% of the I
design set pressure and closed with 5.1 to 9.4% blowdown.
Up to 111% of rated flow was achieved at 3% accumulation with valve lift positions at 92 to 94% of rated lift. Thase tests demonstrated that the valve performed its function in spite of the initial chatter during loop seal discharge.
The above observation is based on the results of the four applicable tests out of a total of seventeen tests performed in the loop seal test series on the 6M6 valve.
During the course of the seventeen tests, the valve was inspected nine times because difficulties in valve closing were encountered from time to time.
In most cases, galled guiding surfaces and I
damaged internal parts were discovered and the damaged parts were refurbished or replaced before the next test.
A pattern emerged that the valve performanced well after each repair; it then chattered on closing in j
the subsequent test and the test had to be terminated by manually opening the valve to stop the chatter. This suggests that proper inspection and maintenance are important to the continued operability of the valves. The applicant has recognized the potential effects of valve chatter on valve operability and has committed to adopt formal procedures for inspection and maintenance of the safety valves following each valve actuation involving discharge of the loop seal or water (Reference 13).
14
i The blowdown in these tests were in excess of the 5% value specified by the valve manufacturer and the ASME Code.
Westinghouse performed an q
analysis, " Safety Valve Contingency Analysis in Support of the EPRI Safety / Relief Valve Testing Program--Volume 3:
Westinghouse Systems," EPRI NP-2047-LD, October 1981, on the effects of increased blowdown and concluded that no adverse effects on plant safety occurred in that the reactor core remained covered. Therefore, the amount of increased blowdown occurred in the Crosby 6M6 steam tests is considered acceptable.
The maximum bending moment induced at the discharge flange of the safety valve during the EPRI tests on the 6N8 valve was 682,500 in-lb and the valve performance was unimpaired.
In Reference 12, the applicant stated that the maximum bending moment due to dead load, thermal expansion, SSE and valve actuation is 516,182 in-lb.
Therefore, operability of the safety valve under the maximum anticipated bending moment is ensured.
4.3.2 Power Operated Relief Valves The EPRI tests applicable to the South Texas, 1 and 2, PORVs indicated that the test valve opened and closed on demand.
For the steam tests, the maximum inlet pressure was 2760 psi at 6830F which exceeded the predicted maximum inlet pressure of 2532 psia for the in-plant valve. The test valve closed at 2310 and 2240 psia (for Tests 97 and 98 respectively) which were slightly lower than the required minimum closing pressure of 2320 psia. The lowest steam flow rate observed in the EPRI tests was 372,600 lbm/h which exceeded the rated flow of 210,000 lbm/h for the South Texas PORVs.
Although water discharge through the PORVs is not expected during the FSAR and HPI transients, it may occur during the low temperature overpressurization event.
In the full pressure (2760 psia) water discharge tests, there were two tests, Tests 99 and 102, in which the PORV closed at pressures well below the required closure pressure of 2330 psia. This valve had a relatively high flow capacity and depressurized the test system rapidly. The minimum test duration required to reach quasi-steady flow 15
condition was approximately four seconds.
The longer discharge time coupled with the rapid depressurization of the test facility resulted in closure pressure below the required closing pressure.
Another test, Test 103, under similar conditions did close at 2480 psia above the required closure pressure.
In the reduced pressure water tests, Tests 100 and 101, which simulated the cold overpressurization transients, the test valve opened on demand and closed at pressures above the minimum predicted pressure of 300 psia. The valve stroke times during the EPRI tests ranged from 0.24 to 1.80 s during the opening cycles and 0.58 to 1.95 s during the closing cycles which were within the required opening and closing times of 2.00 s.
The maximum bending moment induced on the discharge flange of the Garrett PORV during the EPRI tests was 33.200 in-lb. The operability of the test valve was not affected. The maximum bending moment applied to a South Texas PORV as a result of dead load, thermal expansion, SSE and valve actuation is predicted to be 84,414 in-lb.
This is in excess of the moment applied to the test valve.
However, in Reference 12, the applicant stated
]
that the maximum moment that the valve was designed to operate with is 103,500 in-lb. Therefore, operability of the valve under maximum in-plant bending moment is confirmed by analysis.
4.3.3 Electric Control Circuitry NUREG-0737 Item II.D.1 states that, in addition to the PORVs, their associated control circuitry shall be qualified for design basis accidents and transients. The Nuclear Regulatory Commission staff has agreed that meeting the licensing requirements of 10 CFR 50.49 for electrical equipment is satisfactory and that specific testing per the NUREG-0737 requirements is not necessary. The applicant, has included the PORV controls in the South Texas 1 and 2 environmental qualification program (Reference 12), thereby ensuring that the control circuitry will function properly.
16
4.3.4 PORV Block Valves The Westinghouse 3GM88 block valve was cycled 21 times against full steam flow at pressures from 2280 to 2420 psig nominal line pressure. These y
pressures bound the predicted opening pressure for the South Texas PORVs of 2350 psia. The test valve fully opened and closed on demand. The stroke time ranged from 6.2 to 12.9 s.
4 4
During the initial testing of the Westinghouse 3GM88 block valve, va7ve J
1 leakage resulting from the incomplete closure of the block valve was J
observed. The torque switch setting of the actuator was increased and the valve closed fully on the subsequent tests.
Later study and tests conducted by Westinghouse (Attachment B to Reference 9) concluded that the closure problem as a result of under-predicting the stem thrust required for full valve closure.
Since then, Westinghouse has revised their method of estimating the required valve thrust based on the results of their investigation. The plant block valves have been modified by Westinghouse to provide sufficient closing torque as determined in their testing program, therefore, the tests are considered to adequately demonstrate. acceptable valve operation.
Tests for water flow with the Westinghouse block valves were not performed in the EPRI test program.
As explained in Section 4.2 of this report, the valve behavior under the water flow condition is expected to be similar to that of the full pressure steam tests. Therefore, the.
operability of the valves for liquid flow condition has been indirectly demonstrated.
l r
The above discussion, demonstrating that the valves operated satisfactorily, verifies that the part of Item 1 Section 1.2 which requires conducting tests to qualify the valves and that part of Item 7 which requires the effect of discharge piping on operability be considered have I
been met.
1 17
4.4 Piping and Support Evaluation This evaluation covers the piping and supports upstream and downstream of the safety valves and PORVs extending from the pressurizer nozzles to the pressurizer relief tank.
The piping was designed for dead weight, internal pressure, thermal expansion, earthquake, and safety and relief valve j
discharge conditions.
The calculation of the time histories of the j
hydraulic forces due to valve discharge, th'e method of structural analysis, and the load combinations and stress evaluation are discussed below.
4.4.1 Thermal Hydraulic Analysis Pressurizer fluid conditions were selected for use in the thermal hydraulic analysis such that the calculated pipe discharge forces would l
bound the forces for any of the FSAR, HPI, and cold pressurization events, including the single failure that would maximize the forces on the valve.
Various fluid transient analyses were performed for the pressurizer safety and relief valve piping system.
Operation of the safety valves during power operation, operation of the relief valves at power operation and actuation of the relief valves to mitigate cold overpressurization were cases evaluated by the licensee.
In general, the three safety valves opening simultaneously and discharging without PORV flow and the two PORVs opening simultaneously without safety valve flow are the limiting design cases. A combination of the cold overpressurization water solid case and relief valve slug discharge at power case is limiting for the piping section near the relief valve. Typically, the worst valve discharge case (SOTp) is the triple safety valve slug discharge transient for the safety valve piping, including the inlet, outlet, and common region piping and the double relief valve slug discharge transient for the relief valve inlet and outlet piping.
The initial conditions for the safety valve water slug discharge case included:
P (upstream)
- 2575 psia h (steam, upstream) - 1130 Btu /lb 18
T (water, upstream) - 1500F P (downstream)
- 14.7 psia The pressurizer conditions were held constant for the transient at 2575 psia and 1130 Btu /lb.
The initial conditions for the relief valve slug discharge caso included:
P (upstream)
- 2350 psia h (steam, upstream) - 1162.4 Btu /lb 0
T (water, upstream) - 150 F P (downstream)
- 14.7 psia The pressurizer conditions were held constant for the entire transient at 2350 psia and 1162.4 Btu /lb.
The valve setpoints for the low temperature overpressurization mitigation system are below 800 psia.
Consequently, the applicant states that the PORV system will not be armed without a steam bubble in the pressurizer at pressures above 800 psia.
The initial conditions utilized for the water discharge case included:
P (upstream)
- 800 psia T (water, upstream) - 1200F P (downstream)
- 14.7 psia The pressurizer conditions were held constant for the transient at 800 psia and 1200F.
The effective linear valve opening time used was 0.07 seconds.
The thermal hydraulic analysis was performed using the Westinghouse computer code, ITCHVALVE.
ITCHVALVE calculates the fluid parameters as a function of time.
The unbalanced forces or wave forces in the piping segments are calculated from the fluid properties obtained from the 19 I
ITCHVALVE analysis using another Westinghouse program, FORFUN. The forcing functions on the piping system resulting from the fluid transients are obtained from these calculations.
The adequacy of the ITCHVALVE/FORFUN programs for the thermal-hydraulic analysis was verified by comparing the analytical and test results for thermal hydraulic loadings in safety valve discharge piping for two EPRI tests (Test Nos. 908 and 917).
The detail 6d comparisons of the ITCHVALVE predicted force time-histories and the EPRI test results are presented in the submittal (Reference 10) and results of these comparisons are considered satisfactory.
The thermal hydraulic and stress analysis of the South Texas 1 and 2 safety valve and PORV piping and supports were performed by the Westinghouse Electric Co. as a consultant to the Licensee.
The typical Westinghouse analysis for such piping systems has been fully reviewed in previous submittals for similar PWR plants such as the Diablo Canyon Units 1 and 2 (References 15). The method of analysis used by Westinghouse including the analysis assumptions, the structural modeling as well as the key parameters used in the computer inputs such as the node spacing, calculation time interval, valve opening time, etc. has been examined and found to be acceptable. The South Texas 1 and 2 piping analysis followed the same method and procedure used in previous Westinghouse analyses. Therefore the South Texas 1 and 2 analysis method is considered acceptable. The flow rate of the safety valve assumed in the analysis was 120% of the rated flow for the Crosby, 6N8, safety valves. The conservative factor included in the assumed flow rate is in excess of the 10% derating for the safety valve required by the ASME Code and the allowance for uncertainties or errors.
4.4.2 Stress Analysis The structural responses of the piping system due to safety valve /PORV discharge transients were calculated using the modal superposition method.
The fluid force time histories generated from the FORFUN program in the 20
I
)
i i
thermal hydraulic analysis were used as forcing functions on the structural model.
The Westinghouse series of structural analysis programs, namely WESTDYN7, FIXFM3 and WESTDYN2 were used to calculate the piping natural frequencies and mode shapes, the nodal displacements and the internal forces and support reactions. The FIXFM3 code calculates the displacements at the structural node points, using the forcing functions generated by FORFUN and the modal data from WESTDYN7.
The structural displacements were then used by WESTDYN2 to compute the piping internal loads and support reactions.
The WESTDYN series of structural programs mentioned above was previously reviewed and approved by the NRC (Reference 16). The adequacy of these programs for piping discharge analysis was further verified by comparing the solutions generated by these programs with the EPRI safety valve test results (Reference 17).
The stress analysis for the piping upstream of the safety and relief valves was performed in accordance with the requirements of the ASME Boiler and Pressure Vessel Code,Section III, Subsection NB,1977 Edition, with addenda up to and including Summer 1979.
The downstream piping stresses were evaluated in accordance with the ANSI, B31.1, Power Piping Code. The load combination equations and acceptance criteria used for the evaluation of the upstream and downstream piping are identical to those recommended by the piping subcommittee of the PWR Pressurizer safety and relief valve test program (Reference 14). The piping stress summaries presented by the Licensee contain a comparison of the highest stresses in the piping with the applicable stress limits for the load combinations defined above.
The piping stresses are all within their applicable stress limits.
According to results of EPRI tests performed on the Crosby 6M6 safety valve, high frequency pressure oscillations of 170-260 Hz occurred in the piping upstream of the safety valve as a loop seal water slug passed through the valve. This raises a concern that these oscillations could potentially excite high frequency vibration modes in the inlet piping that could contribute to higher bending moments in the piping. This phenomenon was not accounted for in the structural analysis of the system.
The piping between 21
i the pressurizer and safety valves in the EPRI tests, however, was composed of 8-in. Schedule 160 and 6-in. Schedule XX while that at South Texas 1 and 2, is 6-in. Schedule 160.
Since the test piping did not sustain any discernible damage during pressure oscillations occurring in the tests, it is expected that the plant piping also would not incur. damage during similar oscillations. Thus, a specific analysis for these pressure oscillations is not necessary for this plant.
i The piping support information supplied by the licensee indicated that the supports for the.PSARV piping upstream of the valves censist of the structural members that transmit directly to the pressurizer. All other piping supports (downstream of the valves) are attached to the building j
structure. The support loads were taken from the piping analysis results.
The structural code governing the upstream support design is the ASME Boiler and Pressure Vessel Code,Section III, Subsection NF. The upstream supports were designed by considering Service Level loading conditions and the applicable Service Level stress allowable. The allowable stress limits for linear type supports are defined by the Code based on a working limit for design and Service Level A.
Appropriate increases are identified for Service Levels B, C, and D.
The allowable stress limits for plate and shell type supports are defined by the Code based upon primary membrane, primary bending, and expansion stresses.
1 1
The structural code governing the design of supports.for the downstream piping is the American Institute'of Steel Construction (AISC) Manual'of Steel Construction. Any integral attachments to the piping are designed to the same code as the subject piping.
Appropriate AISC' stress allowables
]
were used for the downstream supports.
Concrete anchor bolt adequacy was i
also addressed.
For standard " catalog" components (e.g., snubbers, spring hangers, etc.) the calculated load was compared to the capacity of the component as found in the vendor's published data for the appropriate Service Level.
22 I
The square-root-sum-of-the-squares (SRSS) method was used to combine dynamic loads on the piping supports. These loads were then combined with deadweight and thermal loads to determine the governing load on the individual supports.
\\
The maximum stress calculated for the upstream supports was
)
approximately 42.0 ksi, This was within the allowable limit of approximately 46.7 ksi.
All of the downstream supports were found to have d
stresses or capacities within the AISC defined limits or vendor's published capacities as appropriate.
The selection of a bounding case for the piping thermal-hydraulic evaluation and the resulting piping and support stress analysis results demonstrate that the requirements of Item 3 and Item 8 of Section 1.2 outlined in this report have been met.
4 l
23
5.
EVALUATION
SUMMARY
i The applicant for the South Texas, Units 1 and 2, has provided an acceptable response to the requirements of NUREG-0737.
Specifically, this review examined the submittals of the licensee for the South Texas Project, Units 1 and 2, to the requirements of NUREG-0570 and NUREG-0737 and finds that the licensee has provided acceptable submittals and responses to requests for additional information, thereby reconfirming that General Design Criteria 14, 15, and 30 of Appendix A to 10 CFR 50 have been met.
The rationale for this conclusion is given below.
The applicant participated in the development and execution of an acceptable Relief and Safety Valve Test Program designed to qualify the operability of prototypical valves and to demonstrate that their operation.
would not invalidate the integrity of the associated equipment and piping.
The subsequent tests were successfully completed under operating conditions which by analysis bounded the most probable maximum forces expected from anticipated design basis events. The generic test results and piping analyses showed that the valves tested functioned correctly and safely for all relevant steam discharge events specified in the test program and that the pressure boundary component design criteria were not exceeded.
Analysis and review of the test results and the applicant's justifications indicated direct applicability of the prototypical valve and valve performances to the in-plant valves and systems intended to be covered by the generic test I
program. The plant specific piping also has been shown by analysis to be acceptable.
The test results demonstrated the need for inspection and maintenance of the safety valves following each lift involving loop seal or water discharge to ensure continued reliable operability of the safety valves.
The applicant recognized the potential effects of valve chatter on valve operability and has committed to adopt formal procedures for inspection and maintenance of the safety valves following each valve actuation involving discharge of the loop seal or water.
24
1 i
The requirements of Item II.D.1 of NUREG-0737 (Items 1-8 in j
Paragraph 1.2) which ensure that the reactor primary coolant pressure
)
boundary will have a low probability of abnormal leakage (General Design Criterion No. 14) have been met.
In addition, the reactor primary coolant pressure boundary and its associated components (piping, valves, and supports) have been designed with sufficient margin such that design conditions are not exceeded during relief / safety valve events (General Design Criterion No. 15).
Furthermore, the prototypical tests and the successful performance of the valves and associated components demonstrated that this equipment has been constructed in accordance with high quality standards (General Design j
Criterion No. 30).
C e
25
i 6.
REFERENCES 1.
TMI Lessons Learned Task Force Status Report and Short-Term Recommendations, NUREG-0578, July 1979.
2.
Clarification of TMI Action Plan Requirements, NUREG-0737, November 1980.
3.
D. P. Hoffman, Consumers Power Co., letter to H. Denton, NRC,
" Transmittal of PWR Safety and Relief Valve Test Program Reports,"
September 30, 1982.
4.
EPRI Plan for Performance Testing of PWR Safety and Relief Valves, July 1980.
i 5.
EPRI PWR Safety and Relief Valve Test Program Valve j
Selection / Justification Report, EPRI NP-2292, January 1983.
6.
EPRI PWR Safety and Relief Valve Test Program Test Condition Justification Report, EPRI NP-2460, January 1983.
7.
Valve Inlet Fluid Conditions for Pressurizer Safety and Relief Valves in Westinghouse-Designed Plants, EPRI NP-2296, January 1983.
8.
EPRI PWR Safety and Relief Test Program Safety and Relief Valve Test Report, EPRI NP-2628-SR, December 1982.
9.
R. C. Youngdahl, Consumers Power Co., letter to H. Denton, NRC,
" Submittal of PWR Valve Data Package," June 1, 1982.
10.
M. R. Wisenburg, Houston Lighting & Power Co., letter to G. W.
Knighton, NRC, " South Texas Project, Units 1 and 2, Responses to DSER/FSAR Items Regarding Chapter 7A, Item II.D.1," ST-HL-AE-1466, October 31, 1985.
11.
N. P. Kadambi USNRC, letter to J. H. Goldberg, Houston Lighting & Power Co. " Request for Additional Information - NUREG-0737, Item II.D.1 -
Performance Testing of Relief and Safety Valves, South Texas Project Units 1 and 2," January 4, 1987.
12.
M. R. Wisenburg, Houston Lighting & Power Co., letter to USNRC, 'HL&P Responses to the NRC's Comments and Questions for NUREG-0737, Item II.D.1, " Performance Testing of Relief and Safety Valves," '
March 2, 1987.
13.
M. R. Wisenburg, Houston Lighting & Power Co., letter to USNRC, NUREG-0737 Item II.D.1, Supplemental Information, May 8, 1987.
14.
EPRI PWR Safety and Relief Valve Test Program Guide for Application of Valve Test Program Results to Plant-Specific Evaluations, Revision 2, Interim Report, July 1982.
26
15.
G. K. Miller et al., Technical Evaluation Report TMI Action--NUREG-0737 (II.D.1) Relief and Safety Valve Testing Diablo Canyon Units 1 and 2, Docket No. 50-275, 50-323, EGG-RST-6972, July 1975.
16.
R. L. Todesco, NRC letter to T. M. Anderson, Westinghouse Electric Co.,
" Acceptance for Referencing of Licensing Topical Report WCAP-8252, Revision 1," April 7, 1981.
17.
L. C. Smith and T. M. Adams, " Comparison of Analytically Determined Structural Solutions with EPRI Safety Valve Test Results," 4th National Congress on pressure Vessel and Piping Technology, Portland, Oregon, June 19-24, 1983, PVP-Volume 74, pp. 193-199.
l i
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27
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Stt INsimuCTIONS ON THE REVER$t 2 TirLt ANo sv.f tTLt J LE Avt.LAN.
Technical Evaluation Report, TMI Action--Nureg-0737 (II.D.1) South Texas, Units 1 and 2
- 4. QAf t REPORT COWPLETED MONTH YEAR May 1987
.auf oaisi
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.. PaoacTer Aa.ca. uNir No-.ta INEL-EG&G Idaho, Inc.
. P N oa caANT Nu-.ta Idaho Falls, ID 83415 06005
- 10. SPON50Rir4G OaGANIZAfloN NAME ANo MAlWNQ AoQmt38 t,acke le cese, its. TYPt oP REPORT Mechanical Engineering Branch I"# **I Office of Nuclear Regulatory Commission i
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Washington, D.C.
20555
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32 SUWLEMENTAMV NoT85 13 AS$ f R AGT (J00 we,,. or 'ess, Light water reactors have experienced a number of occurences of improper performance of safety and relief valves installed in the primary coolant system.
]
As a result, the authors of NUREG-0578 (TMI-2 Lessons Learned Task Force Status i
Report and Short-Term Recommendations) and subsequently NUREG-0737 (Clarification of THI Action Plan Requirements) recommended that programs be developed and completed which would reevaluate the functional performance capabilities of
. Pressurized Water Reactors (PWR) safety, relief, and block valves and which would verify the integrity of the piping systems for normal, transient, and accident conditions.
This report documents the review of these programs by the Nuclear Regulatory Commission (NRC) and their consultant, EG&G Idaho, Inc.
Specifically, this review examined the submittals of the applicant for the South Texas Project, Units 1 and 2, to the requirements of NUREG-0578 and NUREG-0737 and finds that the applicant has provided acceptable submittals and responses to requests for additional information, thereby reconfirming that the General Design Criteria 14,15, and 30 of Apprenix A to 10 CFR 50 have been met.
14 DOCuwt NT ANAL T$st e at.wono&>Dt1CReef 088S tl Av asLA.s LIT Y Unlimited 16 SECURITv CLAS$le,CAfl0N
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