ML20215M170

TMI Action-NUREG-0737 (II.D.1),Comanche Peak Steam Electric Station Unit 1, Informal Technical Evaluation Rept

ML20215M170
Person / Time
Site:	Comanche Peak
Issue date:	05/31/1987
From:	Nalezny C, Pace N, Yuan C EG&G IDAHO, INC.
To:	NRC
Shared Package
ML20215M144	List: ML20215M140 ML20215M170
References
CON-FIN-D-6005, RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM EGG-NTA-7701, NUDOCS 8706260300
Download: ML20215M170 (30)

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l TECHNICAL EVALUATION REPORT TMI ACTION--NUREG-0737 (II.D.1)

COMANCHE PEAK STEAM ELECTRIC STATION, UNIT 1 DOCKET NO. 50-445 l

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• j N. E. Pace l C. Y. Yuan I C. L. Nalezny 1 May 1987 I

1 Idaho National Engineering Laboratory EG&G Idaho, Inc.

Idaho Falls, Idaho'83415 l

Prepared for the U.S. Nuclear Regulatory Commission Washington, D.C. 20555 Under DOE Contract No. DE-AC07-761001570 FIN No. D6005

ABSTRACT i

Light water reactors have experienced a number of occurrences of l improper performance of safety and relief valves installed in the primary coolant system. As a result, the authors of NUREG-0578 (TMI-2 Lessons l 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 j (NRC) and their consultant, EG&G Idaho, Inc. Specifically, this review examined the response of the Licensee for the Comanche Peak Steam Electric  ;

Station, Unit 1, to the requirements of NUREG-0578 and NUREG-0737 and finds f that the Licensee has provided an acceptable response, reconfirming that the General Design Criteria 14, 15, and 30 of Appendix A to 10 CFR 50 have been met.

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l FIN No. 06005--Evaluation of CW Licensing Actions-NUREG-0737, II.D'.1 l l

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CONTENTS I

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ABSTRACT .............................................................. ii

1. INTRODUCTION ..................................................... 1 i l

1 1.1 Background ................................................. 1 1

, 1.2 General Design Criteria and NUREG Requirements ............. 1 1

2. PWR OWNERS' GROUP RELIEF AND SAFETY VALVE PROGRAM ................ 4 l

3. PLANT SPECIFIC SUBMITTAL ......................................... 6

4. REVIEW AND EVALUATION ............................................ 7 )

l 4.1 Valves Tested .............................................. 7 4.2 Test Conditions ............................................ 7 4.2.1 FSAR Steam Transients .............................. 8 4.2.2 FSAR Liquid Transients ...... ...................... 9 4.2.3 Extended High Pressure Injection Event ............. 12 4.2.4 Low Temperature Overpressure Transient ............. 12 4.2.5 PORV Block Valve Fl uid Condi tions . . . . . . . . . . . . . . . . . . 13 4.3 Operability ................................................ 13 l

l 4.3.1 S a f e ty V al v e s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13  !

4.3.2 Power Operated Relief Valves ....................... 16 I 4.3.3 El ectri c Control Ci rcui try . . . . . . . . . . . . . . . . . . . . . . . . . 17 l 4.3.4 PORV Block Valves .................................. 17 4.4 Piping and Support Evaluation .............................. 17 4.4.1 The rmal Hydraul i c Anal ysi s . . . . . . . . . . . . . . . . . . . . . . . . . 18 4.4.2 Stress Analysis .................................... 21

5. EVALUATION

SUMMARY

............................................... 24

6. REFERENCES ........................................................ 26 TABLES 4.2.1

SUMMARY

OF TEST DATA FOR CROSBY 6M6 SAFETY VALVE AND COMPARISON WITH COMANCHE PEAK REQUIREMENTS ................ 10 4.3.1 EPRI TESTS ON CROSBY HP-BP-86 6M6 SAFETY VALVE ............ 15 iii

TECHNICAL EVALUATION REPORT TMI ACTION--NUREG-0737 (II.D.1)

COMANCHE PEAK STEAM ELECTRIC STATION, UNIT 1 DOCKET NO. 50-445

1. INTRODUCTION

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1.1 Background

- i Light water reactor experience has included a' number of instances of improper performance of relief and safety valves installed in the primary coolant system. There have been instances of valves opening'below set j pressure, valves opening above set pressure, and valves failing to open or reseat. From these-'past instances of improper valve _ performance,~it is not. 1 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 d the failure of a power-operated relieY v'alve (PORV) to reseat was a l significant contributor to the Three Mile Island (TMI-2) sequence of' j events. These facts led the' task force which prepared NUREG-0578 ]

(Reference'1) and, subsequently, NUREG-0737 (Reference 2) to' recommend that~

programs t,e developed and executed which would reexamine the functional performance capabilities of Pressurized Water Reactor (PWR) safety, relief, i and block valves and which 'would verify the integrity of the 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, j j

. 1.2 ' General Design Criteria and NUREG Requirements 1

, 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 J

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not exceeded during normal operation or anticipated transient events, and (c) the components which are part of the reactor coolant pressure boundary shall be constructed to the highest quality standards practical.

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

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the Division of Licensing (DL), Office of Nuclear Reactor Regulation (NRR),

, to ALL OPERATING NUCLEAR POWER PLANTS. This requirement has since been t 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:

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1. Conduct testing to qualify reactor coolant system relief and safety valves under expected operating conditions for design basis transients and accidents.

2. Determine 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 single failures such that the dynamic forces on the safety and relief valves are maximized.

4. Use the highest test pressures predicted by conventional safety analysis procedures.

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.

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7. Submit a correlation or other evidence to 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.

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2. PWR OWNERS # GROUP RELIEF AND SAFETY VALVE PROGRAM l In response to the NUREG requirements previously listed, a group of utilities with PWRs requested the assistance of the Electric Power Research Institute (EPRI) in developing and implementing a generic test program for pressurizer. power operated relief valves, safety valves, block valves, and

, associated piping systems. The Texas Utilities Generating Co. (TUGC), owner

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of the Comanche Peak Steam Electric Station (CPSES), Unit 1,'was one of the

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. 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, relief, and block valves under conditions which bound actual plant operating j conditions. EPRI, through the valve manufacturers, identified the valves l used in the overpressure' protection systems of the participating utilities.

Representative valves were selected for testing with a sufficient number of l the variable characteristics that their testing would adequately demonstrate

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the performance of the valves used by utilities (Reference 5). EPRI, j through the Nuclear Steam Supply System (NSSS) vendors, evaluated the FSARs 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 CPSES, Unit 1, was designed by Westinghouse this report is relevant to this evaluation.

Several test series were. sponsored by EPRI. PORVs and block valves 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

.l tested at the Combustion Engineering Company, Kressinger Development Laboratory, located in Windsor, Connecticut. The'resulte for the relief 4

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and safety valve tests are reported in Reference 8. The results for the block valves tests are reported in Reference 9. A guide for applying these >

I test results to the specific plants is presented in Reference 10. j i

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

. the full range of fluid conditions under which they may be required to l operate. The conditions selected for test (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 structural effects of associated piping on valve operability, and (c) obtain piping response data that could ultimately be used for verifying analytical piping models.  !

1 Transmittal of the test results meets the requirement of Item 6 of Section 1.2 to provice test data to the NRC.

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3. PLANT SPECIFIC SUBMITTAL

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A preliminary plant specific evaluation of the adequacy of the J I

overpressure protection system for CPSES, Unit 1, was submitted by TUGC to j the NRC on July 8, 1981 (Reference 11) and March 31, 1982 (Reference 12).

The information provided was reviewed and a request for additional

- information was sent on July 5,1985 (Reference 13), to which the licensee l responded on June 13, 1986 (Reference 14). On March 27, 1987 (Reference 15) l

- the NRC transmitted a second request for information to TUGC, and the ]

licensee responded on April 15, 1987 (Reference 16). )

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The response of the overpressure protection system to Anticipated l Transients Without Scram (ATWS) and the operation of the system during feed I and bleed decay heat removal are not considered in this review. Neither the Licensee nor the NRC have evaluated the performance of the system for these f

events.

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4. REVIEW AND EVALUATION 4.1 Valves Tested i CPSES, Unit 1, is a four-loop PWR designed by the Westinghouse Electric Co. It 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, 6M6, spring loaded valves with loop seal internals. The design set pressure is 2485 psig and the rated steam flow  ;

capacity is 420,000 lbm/h. The PORVs are 3-in. Copes-Vulcan Model 0-100-160 l globe valves with 316 S.S. stellited plugs and 17-4 PH cages. The PORV l opening set pressure is 2335 psig and the rated steam flow capacity is l 210,000 lbm/h. The inlet pipe to the safety valve and PORVs include loop j seals. The PORV block valves are 3-in. Westinghouse Model 3GM88 gate valves with Limitorque SB-00-15 motor operators; the operator gear ratio has been modified and the wiring has been changed for limit control to assure valve ,

operability as recommended by Westinghouse. i Safety valves, PORVs, and PORV block valves identical to those used at CPSES, Unit 1, were included in the EPRI tests. Since there is no difference between the valves tested and the valves installed at the plant, the test results for these valves are directly applicable to CPSES, Unit 1.

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. ,

4.2 Test Conditions -

As stated above, CPSES, Unit 1, is a four-loop PWR designed by the Westinghouse Electric Corp. The valve inlet fluid conditions that bound the overpressure transients for Westinghouse designed PWR Plants are identified ,

1 in Reference 7. The transients considered in this report include FSAR, extended high pressure injection, and low temperature overpressurization events. The expected fluid conditions for each of these events and the applicable EPRI tests are discussed in this section.

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4.2.1 FSAR Steam Transients 4 For the CPSES, Unit 1, PWR, 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 1 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  !

l 2555 psia and 144 psi /s, respectively. The maximum developed backpressure j in the outlet piping is 500 psig (Reference 15). The loop seal is insulated  :

such that the valve inlet temperature is 3000F (Reference 15).  !

I EPRI tests representative of the valve inlet fluid conditions for the 1 i

limiting transient were selected for the plant specific' evaluation.

In selecting the EPRI tests, the safety valve ring settings and the pressure )

drop through the inlet pipe were also considered. For steam flow conditions, four loop seal discharge tests (Test No. 929, 1406, 1415, 1419) were applicable to CPSES, Unit 1. These tests were performed with valve ring settings representative of the typical ring settings used in Westinghouse PWRs including CPSES. The ring settings used in these tests.

were (-71, -18) or (-77, -18). These represent the. upper and lower ring positions measured from the level position referenced to the bottom of the disc ring. The relative ring settings used at.CPSES Unit 1 are -82 to -103, and -18 relative to the level position. Since both the test ring settings and the in-plant ring settings were determined by the valve manufacturer, the Crosby Valve and Gage Co., using the same methods and the same standard of performance, these ring settings are considered comparable.

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Both the inlet pipe length and the water seal volume in the EPRI tests were greater than those employed at the plant. Therefore, the pressure drop through the inlet pipe would be higher in the tests than that at CPSES,.

Unit 1. The Licensee has provided calculated values for the inlet pressure drop on valve ooening and closing which are comparable to the test 8

values. The loop seal temperature measured in the tests ranged from 90 to 360 0 F at the valve inlet; The maximum pressurizer (tank i) pressures were in the range of 2675 to 2760 psia and the pressurization rate was 90 to 360 psi /s. The backpressures developed in the tests were 245 to 710 psia.

The above data, which is summarized in Table 4.2.1, show that the inlet fluid conditions and backpressures of these tests envelop the corresponding

. fluid data predicted for the CPSES, Unit 1, safety valves, l

- When both the safety valves and PORVs are actuated, the maximum pressurizer pressure is predicted to be 2532 psia and the maximum pressurization rate is 130 psi /s. In the EPRI tests on the Copes-Vulcan l PORV, the maximum steam pressure at valve opening was 2715 psia, which bounds the predicted pressure at CPSES, Unit'1. The backpressure developed l at the outlet of the PORVs is not an important consideration, since the air operated PORVs used at the CPSES, Unit 1, plant are not sensitive to backpres::ure (Reference 6). Therefore the EPRI test inlet fluid conditions for the PORV in steam discharge are representative of the plant specific transient conditions.

4.2.2 FSAR Liquid Transients The limiting FSAR transient resulting,in liquid discharge through the PORVs and safety valves is the main feidline break accident (Reference 7).

From a review of feedwater line break analysis for CPSES, Unit 1, it is clear that the feedwater line break is most likely to be the limiting transient for providing high pressure liquid to the safety valves, a fluid for which thay were not originally designad. Therefore, in accordance with the NUREG requirements, the safety valves and PORVs should be qualified for j inlet conditions typical of the feedline break event. Therefore, the valve operability will be reviewed using the feedline break data provided in f Reference 7.  !

Reference 7 showed that, in a feedline break accident at CPSES, Unit 1, the maximum pressure at the safety valve inlet during liquid discharge was t g

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l calculated to be 2503 psia, the pressurization rate was 5 psi /s and the l maximum pressurizer surge rate was 1109.5 gpm (-369,000 lbm/hr) liquid at 608-6150F.  !

In a feedline break accident resulting in safety valve actuation, water discharge is always preceded by steam and steam to water transition flows.

, Among the EPRI tests performed on the 6M6 valve, Tests 931a and 931b were  ;

performed for loop seal steara, steam to water transition, and water

. discharge conditions. The valve ring settings and inlet pipe configuration  ;

used in these tests were comparable to those of the in plant safety valves. i In Test No. 931a, the maximum inlet pressure was 2578 psia. The pressurization rate was 2.5 psi /s, the inlet fluid temperature was 1170F and the tank fluid temperature was 6350F. After the valve closed in Test 931a, the system was allowed to repressurize and the valve cycled on  !

I approximately 6400 F water for Test 931b. Since the inlet temperature and i pressure of the tests bounded the predicted in plant condition, the results of these tests are considered representative of the CPSES, Unit 1, safety

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valves. The inlet fluid conditions and corresponding test data for liquid  !

discharge are also summarized in Table 4.2.1.

l The expected fldid conditions at the inlet of the safety valve were based on a Westinghouse analysis that assumed the PORVs-were not operable during the feedline break transient. If the PORVs are operable, the same fluid conditions postulated for the safety valve inlet can also be expected at the PORV inlet (Reference 6). In the EPRI tests, high temperature water discharge and steam to water transition tests were performed with the Copes-Vulcan PORV. In the water discharge test, Test No. 76-CV-316-2W, the maximum pressure at the valve inlet was 2535 psia and the temperature was 6470F. In the transition test, Test No. 77-CV-316-7S/W, the maximum inlet pressure was 2532 psia and the water temperature was 6570F. The inlet fluid conditions for these tests compare well with the predicted maximum pressure and temperature of 2505 psia and 6150F for the CPSES, Unit 1, plant. Therefore this test is adequate to represent the in-plant PORV performance in the feedline break event.

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.4.2.3 Extended High presspre Injection Event The limiting extended high pressure injection event is the spurious actuation of the safety injection system at power (Reference 7). For a I four-loop plant, both the safety valves and PORVs will be challenged. Both steam and water discharge are expected. For safety valve actuation, the maximum pressure at valve inlet is predicted to be 2507 psia and the pressurization rate is within 4 psi /s. The inlet temperature ranges from

. 567_to 5720F. For the PORV, the maximum pressure is predicted to be 2353 psia and the pressurization rate is within 4 psi /s and the inlet temperature ranges from 565 to 5690F. .In this event, however, the safety I valves or PORVs open on steam and liquid discharge would not be observed 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 operator action. Thus the potential for liquid discharge in )

extended HPI events can be disregarded. I 4.2.4 Low Temperature Overpressurizatian Transient The PORV is used for overpressure protection during the low temperature stages in reactor startup and shutdown operations. The low pressure set j point of-the PORVs vary with valve and temperature and range'from 445'psig I to 2350 psig (Reference 14). The expected inlet fluid conditions for' low l temperature overpressurization transients are identified in Reference 7 and range from cold water to steam.

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 low temperature overpressurization tran_sients. For water discharge conditions, there were two low pressure and low temperature water tests performed on the Copes-Vulcan PORV with stellited plug and 17-4 PH' i cage. The tests were conducted at an inlet pressure of 675 psia and water temperatures of 1050F and 4420F, respectively. These conditions are i representative of those at CPSES, Unit 1. Therefore, the EPRI tests can be used to evaluate the performance of the CPSES, Unit 1, PORV for low temperature overpressurization transients. l 12

j 4.2.5 PORV Block Valve Fluid Conditions 1 The block valves used are 3-inch Westinghouse Model 3GM88 gate valves j with Limitorque SB-00-15 operators. These valves were tested for full flow j and pressure conditions in the EPRI tests and, as modified, qualify for operation at these conditions.

The test sequences and analyses described above demonstrate that the test conditions bound the conditions for the plant valuer. They also 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 equiva?ent to conditions prescribed in  ;

the FSAR, is also met. l 4.3 Operability )

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4.3.1 Safety Valves i The EPRI tests representative of the steam discharge cendition for the CPSES, Unit 1, safety valves are the loop seal tests on the Crosby 6M6 valve, Test No. 929, 1406, 1415, 1419. In all these tests (except Test No.'1415), the valve fluttered or chattered during loop seal discharge j and stabilized when steam flow started. The valve opened within 14% of the l design set pressure and closed with 5.1 to 9.4% blowdown. Up to 111% of I rated flow was achieved at 3% accumulation with valve lift positions at 92 to 94% of rated lift. These tests demonstrated that the valve performed its function in spite of the initial chatter during loop seal discharge.

In Test 1419, the valve chattered on closing and the test was terminated after the valve was manually opened to stop the chatter. This result does not indicate a valve closing problem for the CPSES, Unit 1, safety valve since an identical test (Test 1415) had already demonstrated that the valve performed satisfactorily and exhibited no sign of instability. The closing chatter in Test 1419 may possibly be a result of 13

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1 the repeated actuation of the valve in loop seal and water discharge tests.

As shown in Table 4.3.1 the 6M6 test valve was subjected to seventeen steam, water, and transition tests. In the first four or five tests, the valve i fluttered and chattered during loop seal discharge but stabilized and closed successfully. After Test 913, there were four instances in which the test was terminated due to chattering on closing. Galled guiding surfaces and

, damaged internal parts were found during inspection and the damaged parts J were refurbished or replaced before the next test started. The test results 1

. showed that the valve performed well after each repair, but the closing i chatter recurred in the subsequent test. Test 1415 was performed immediately after valve maintenance and the valve performed stably. The next test (Test 1419) encountered chatter in closing even though it was a i repeat of Test 1415 at similar fluid conditions. This suggests that inspection and maintenance are important to the continued operability of the l valves. The Licensee should develop a formal procedure requiring that the I safety valves be inspected after each actuation and the procedure should be incorporated into the plant operating procedures or licensing documents such as the plant technical specifications.

The blowdown in these tests (5.1 to 9.4%) were in 4xcess of the 5%

value specified by the valve manufacturer and the ASME Code. Westinghouse

~

performed an 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 which occurred in the Crosby 6M6 steam tests is considered acceptable.

As discussed in Section 4.2.2, the limiting FSAR transient resulting in liquid discharge is the main feedline break accident. Tests 931a and 931b with typical plant ring settings of (-71, -18) simulate the expected CPSES, Unit 1, feedwater line break conditions. Test 931a was a loop seal / steam / water transition test. The 6M6 valve initially opened, fluttered or chattered in a partial lift position during loop seal discharge, then 14

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popped open, stabilized on steam, and closed with a 12.7% blowdown.

Test 931b was a saturated water test. The 6M6 valve opened on 6400F water, chattered, and then stabilized. The valve closed with 4.8%

blowdown. For these tests the valve opened within -1% and +3% of the set pressure. The maximum calculated surge rate at CPSES, Unit 1, during the feedline break transient is 1109,5 gpm. The 6M6 valve tested by EPRI passed 2355 gpm at 2415 psia and 6410F which is much higher than the predicted flow rate for CPSES, Unit 1. The above results demonstrate that the Crosby 6M6 safety valves would be adequate to perform the required water relief l

\

function.

The loads induced on the safety valves tested by EPRI exceed the loads for the CPSES, Unit 1, safety valves. The maximum moment tested for the 6M6 valve was during test 908 and was 298,750 in.-lb. The largest moment I

\

predicted for the safety valve inlet at CPSES, Unit 1, is 178,175 in.-lb.

This demonstrates functionability for the CPSES, Unit J safety valves. {

l 4.3.2 Power Operated Relief Valves The EPRI tests on the Copes-Vulcan PORV with 316 S.S. stellited plug and 17-4 PH cage demonstrated that the valve opened and closed on demand in steam, water, and steam to water transition conditions. The opening and

]

closing time were within the 2.0 second opening and closing time normally

]

required for Westinghouse PWRs. The lowest steam flow rate observed in the tests was 232,000 lb/h which exceeded the rated flow of 210,000 lb/h for the j CPSES, Unit 1, PORVs.

A bending moment of 43,000 in.-lb was induced in the inlet of the '

. Copes-Vulcan PORV test valve per EPRI 64-CV-174-2S, The largest moment predicted for the PORV inlet in the CPSES, Unit 1, valves is 28,708 in.-lb. l This demonstrates functionability of the CPSES, Unit 1, relief valves.

v 16

i 4.3.3 Electric Control Circuitry l

NUREG-0737 11.D.1 requires qualification of associated control circuitry as part of the safety / relief valve qualification. The Licensee addressed (Reference 14) the qualification of the PORV control circuitry required by NUREG-0737, Item II.D.1. The information contained a list of equipment and the abnormal events for which they have been qualified. This submittal included the tests required by NUREG-0737, Item II.D.1, thereby assuring _the functionality of the control circuitry.

4.3.4 p0RV Block Valves The Westinghouse 3-inch Model 3GM88 block valves.that are used in CPSES, Unit 1, are the same as those finally tested by EPRI (modified the.

same as the test valves) and the test valves opened and closed fully under the full range of operating conditions. Therefore, the plant valves are-expected to function acceptably when required to do so.

The above discussion, demonstrating that the valves operated satisfactorily, verifies that the part of Item 1 of 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 1 have been met provided that the Licensee documents formal procedure for the inspection of safety valves as discussed in Section 4.3.1. Also, the i qualification testing of the control circuitry satisfies the requirements of Item 5 of Section 1.2.

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 discharge conditions. The calculation of the time histories of hydraulic forces due to valve discharge, the method of structural analysis, and the load combinations and stress evaluation are discussed below.

17. 1

l 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 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.

I In the analysis, the safety valve and PORV discharge transients were

- treated as two separate events, that is, the safety valves were assumed to actuate simultaneously with the PORVs closed, and the PORVs were assumed to actuate simultaneously with the safety valves closed. This approach is acceptable, since the safety valves and PORVs have different set points; they will not lift at the same time. A valve operating condition which is more likely to occur would be a discharge of the PORVs followed by discharge of the safety valves at their respective set points. Since the PORVs have a lower set point, they will open ahead of the safety valves. In this case, the PORV piping loads would be the same as those calculated from the simultaneous PORV actuation case above, but the safety valve discharge forces would be reduced due to the build-up of backpressure in the discharge piping resulting from the preceding PORV actuation. Therefore, this condition needs not to be analyzed.

I I

The steam discharge transients are potentially the worst loading conditions for the safety valve and PORV piping. Both the safety valves and PORVs at Comanche Peak I have' loop seals upstream of the valve inlets. When I the safety valve or PORV actuates, the water slug in the loop seal driven by ,

the high steam pressure imposes the highest hydrodynamic loads on the piping and supports. The piping loads due to water discharge are not expected to exceed the steam discharge conditions. The loop seal temperature is 300 F at the safety valve inlet and 6500F at the steam / water interface at the upstream end of the loop seal (Reference 17). The average temperature of the loop seal water would be in the range of 3500F t'o 4000F. The limiting event for water discharge through the safety. valves is the feedline break accident. The water temperature was predicted to.be 6080F to 615 F (Reference 7). This temperature is considerably higher than the f 18 l

1 l

1

.I l

1 loop seal temperature. Therefore, more flashing is expected in the high -

temperature water discharge case and the hydrodynamic forces on the piping j would be less severe than the water slug discharge condition.

.]

l For the PORVs, the steam discharge also represents the limiting condition for the pipe loads. The PORV inlet piping has a cold loop seal

, with 1500F water (Reference 14). The thrust of the: cold water slug under.  ;

• l high steam pressure generates the highest piping loads of all steam and I

. water discharge transients including the cold overpressurization events.

Therefore, the valve discharge conditions selected for the piping and support stress evaluations were the steam discharge conditions resulting from the simultaneous actuation of the safety valves and the simultaneous J

actuation of the PORVs respectively.

. In the thermal hydraulic analysis, fluid conditions were assumed to bound all limiting transients discussed in Section 4.2. For the safety valve analysis, the initial pressure of the saturated steam upstream of the loop seals was assumed to be 2575 psia and the initial downstream pressure l

'was assumed to be 18 psia. The pressurizer conditions were held constant for the entire transient at 2575 psia and 1100 Btu /lb'. The loop seal water temperature was assumed to be 3000F at the safety valve inlet. For:the PORV analysis, the initial upstream pressure of the saturated steam was assumed to be 2350 psia and the downstream pressure was assumed to be 18 psia. The pressurizer conditions'were held. constant for the entire transient at 2350 psia and 1162 Btu /lb. The temperature of the liquid upstream of the PORV was assumed to be a constant 1500F. The pressurizer pressure used in the analysis is lower than the maximum pressure of' 2532 psia predicted by Westinghouse. This slight nonconservatism is more than compensated by assuming a constant loop seal temperature of 1500F, since the loop seal water at the steam-water interface would.be at saturation and'the temperature along the loop seal would be. hotter than at the PORV inlet. The effect on calculated discharge loads of.slightly lower )

upstream pressure is less than the the effect of lower loop seal temperature.

19

The thermal hydraulic analysis was performed using the Westinghouse I computer code, ITCHVALVE. ITCHVALVE calculates the fluid parameters as a function of time. The unbalanced forces or wave forcos in the piping 3 segments are calculated from the fluid properties obtained from the I ITCHVALVE analysis using'another Westinghouse program, FORFUN. The forcing functions on the piping system resulting from the fluid transients are 1

. obtained from these calculations.

. The adequacy of the ITCHVALVE/FORFUN programs for the thermal-hydraulic j analyses 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 detailed comparisons.of the ITCHVALVE predicted force time-histories and the EPRI test results are presented in  !

the submittal (Reference 3) and results of these comparisons are considered satisfactory.

The thermal hydraulic and stress analysis of the Comanche Peak 1 safety j 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 l (References 18 and 19). The method of analysis used by Westinghouse-including the analysis assumptions, the structural'modeling as well as the- l key parameters usea in the computer inputs such as the node spacing, j calculation time interval, valve opening time, etc. has been examined and found to be acceptable. The Comanche Peak 1 piping analysis followed the same method and procedure used in previous Westinghouse analyses. Therefore the Comanche Peak 1 analysis method is considered acceptable. The flow rate of the safety valve used in the analysis was 120% of the rated flow for the Crosby, 6M6, safety valves. The conservative factor contained in this flow  ;

rate is greater than needed to account for the 10% derating for the safety 0 valve required by ASME Code and the allowance for uncertainties or errors.

The PORV flow rate used in the analysis was 139% of the rated flow for the- <

Copes-Vulcan valve, which again is amply conservative.

20 j

4.4.2 Stress Analysis The structural responses of the piping system due to the safety valve /PORV discharge transients were calculated using the modal superposition method. The fluid force time histories generated from the FORFUN' program in the thermal hydraulic analysis were used as forcing functions on the structurai 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 loads.

The WESTDYN series of structural programs mentioned above was previously reviewed and approved by the NRC (Reference 20). The adequacy of' these programs for piping discharge analysis was further verified by comparingthesolutionsgenerated'bytheseprogramswiththeEPRIsafety valve test results (Reference 21).

The piping stress analysis was performed in accordance with the requirements of the ASME Boiler and Pressure Vessel Code,Section III, Subsectior NB, 1977 Edition, with addenda to and including Summer 1979. The  !

piping supports were analyzed in accordance with the ASME Boiler and Pressure Vessel Code Section III, Subsection NF, 1974 Edition, with addenda to and including Winter 1979. The load combination equations and stress limits used for the evaluation of the piping and support stresses are identical to those recommended by the piping subcommittee of the PWR Pressurizer safety and relief valve test program (Reference 10). The piping stress summaries presented by the Licensee (Reference 16) contain a comparison of the highest stresses in the piping with the applicable stress limits for the load combinations defined above. The' piping stress results were reviewed and all the stresses were found to be within the applicable stress limits.

21 i

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 I 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 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 Comanche Peak 1, 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.

1 Reference 16 presented the worst case load / stress versus the allowables for representative piping supports. The results all showed that the load / stresses were within their respective allowables.

The selection of a bounding case of the piping evaluation and the piping and support stress analysis demonstrate that the requirements of i Item 3 and Item 8 of Section 1.2 outlined in this report have been met.

4 22

j

'i

5. EVALUATION

SUMMARY

j

'w icensee for CPSES, Unit 1, has provided an acceptable response to j the cequirements of NUREG-0737, and thereby reconfirmed that the General Design Criteria 14, 15, and 30 of Appenc'ix A to 10 CFR 50 have been met.

The rationale for this conclusion is given below.

The Licensee particip'ated 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 specif.ied in the test program and that the pressure boundary component design criteria.were not exceeded. Analysis and review of the test results and the Licensee's: justifications indicated direct applicability of the prototypical valve and valve perfor'mances to the in-plant valves and systems intended to be covered by the generic test program. ]

l Thus, the requirements of Item ~II.D.1 of NUREG-0737 have been met '

(Items 1-8 in Paragraph 1.2) and, thereby demonstrate by testing and-  !

analysis, that the reactor primary coolant pressure boundary will have a low I probability of abnormal leakage (General Design Criterion No.14) and that 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 Criterion No. 30).

23

REFERENCES

1. TMI Lessons Learned Ta_s_k Force Status Report and Short-Term Recommendations, NUREG-0578, July 1979.

2. Clarification of TMI Action Plan Requirements, NUREG-0737, November j 1980. ]

3. D. P. Hoffman, Consumers Power Co., letter to H. Denton, NRC,

" Transmittal of PWR Safety and Relief Valve Test Program Reports," l September 30, 1982. l

. 4. EPRI Plan for Performance Testing of PWR Safety and Relief Valves, July 1980. ]

l

5. EPRI PWR Safety and Relief Valve Test Program Valve i 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 j 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. EPRI PWR Safety and Relief Valve Test Program Guide for Aoplication of I7alve Test Program Results to Plant-Specific Evaluations, Revision 2, Interim Report, July 1982.

11. P. Knight, Texas Utilities Services, Inc., memorandum for R. L. Tedesco, Assistant Director of Licensing, NRC, " Input to Comanche Peak SER," July 8, 1981.

12. H. C. Schmidt, Texas Utilities Services, Inc., letter to S. B. Burwell, Licensing Project Manager, NRC, " Comanche Peak Steam Electric Station Draft Response to Generic Letter No. 81-36," Log # TXX--3503, File #

10035, March 31, 1982.

13. V. S. Noonan, NRC, letter to M. D. Spence, Texas Utilities Generating

. Co., " Performance Testing of Relief and Safety Valves," July 5, 1985.

14. W. G. Counsil, Texas Utilities Generating Co., letter to V. S. Noonan, Director, Comanche Peak Project, DL, NR-C, " Comanche Peak Steam Electric Station (CPSES), Docket Nos. 50-445 and 50-446, NUREG-0737, Item II.D.1--Performance Testing of Relief and Safety Valves,"

Log # TXX-4849, File # 10010, June 13, 1986.

24

15. C. Grimes, NRC, letter to W. G. Counsil, Texas Utilities Generating Co., " Performance Testing of Relief and Safety Valves," March 27, 1987.

16. W. G. Counsil, Texas Utilities Generating Co., letter to V. S. Nuclear l Regulatory Commission, " COMANCHE PEAK STEAM ELECTRIC STATION (CPSES),

DOCKET NOS. 50-445 and 50-446, REQUEST FOR ADDITIONAL INFORMATION -

NUREG-0737, ITEM II.D.1--PERFROMANCE TESTING OF RELIEF AND SAFETY {

VALVES," Log # TXX-6398, File # 10010, April 15,1987. j i

17. Amendment 40 to Comanche Peak FSAR, " Response to NRC Action Plan, I II.D.1," May 10, 1983.

. 18. L. C. Smith and T. L. Nazlett, Pressurizer Safety and Relief Line j Evaluation Summary Report, Pacific Gas and Electric Corp., Diablo 1 Canyon Unit 1 and Unit 2, Westinghouse AM-SSA-2.534, November 1982.

19. J. O. Schuyler, Pacific Gas and Electric, letter to G. W. Knighton, I NRC, " Response to NRC Request for Additional Information, NUREG-0737, l Item II.D.1, Performance Testing of Relief and Safety Valves," l January 23, 1984.

20. R. L. Tedesco, NRC letter to T. M. Anderson, Westinghouse Electric Co., i

" Acceptance for Referencing of Licensing Topical Report WCAP-8252, Revision 1," April 7, 1981.

21. t.. C. Smith and T. M. Adams, " Comparison 'of Analytically Determined i Structural Solutions with EPRI Safety' Valve Test Results," 4th National j Congress on Pressure Vessel and Piping Technology, Portland, Oregon, June 19-24, 1983, PVP-Volume 74, pp. 193-199.

)

i 25

1 U.S. NUCL EMI K EEULATOR Y CouMisSION 1 RtrORT NUM8ER (Ass ,nea ey TfDC.4dat Ve, Ng, ef myf 1 NRC P4LM 338

• J2 ' BIBLIOGRAPHIC DATA SHEET EGG-NTA-7701 SEE INSTRUCTIONS ON THE REVERSE

2. TITLE AND SUO TITLE J LEAVE BLANK TMI Action-NUREG-0737 (II.D.1) Comanche Peak Steam Electric Station, Unit .1 l j

4 QATE REPORT COMPLETED MO~rn ..AR j j

.4u f NOR ,,,

May 1987 N. E. Pace, C. Y. Yuan, C. L. Nalezny MONTH

• o^ aoa "55u'o vtAR May 1987

. o i-ORM.NO ORaANiz Ai,0N NAM. ANo MA.uNo AooR.3. ,,,,,,,,,,e, C , . PROaCT,r As ,wom u~, r NuM.E R j i

INEL-EG&G Idaho, Inc. . ,N OR OR ANi NuM. R I

. Idaho Falls, ID 83415 D6005

10. SCONSORING QRGANtzAflON NAME AND M AILING ADDRESS (1,et, dele Coaes its TYPE OF R4 PORT Mechanical Engineering Branch Office of Nuclear Reactor Regulation Informal

. ,, R,Oo CO y R,o ,,,,,, ..e ,e.,

U.S. Nuclear Regulatory Commission Washington, DC 20555 l 1

12 $UPPLEMENT ARY NOTES

13. A84TR ACT 400 woras er desst Light water reactors have experienced a number of occurrences of improper I 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 Report j and Short-Term Recommendations) and subsequently NUREG-0737 (Clarification of'TMI ,

Action Plan Requirements) recommended that programs be developed and completed which l would reevaluate the functional performance capability of Pressurized Water Reactor  !

(PWR) . safety, relief, and block valves and which would verify the integrity of the l piping systems for nonnal, 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 response of the Licensee for the Comanche Peak Steam Electric Station, Unit 1, to the requirements of.

NUREG-0578 and NUREG-0737 and finds that the Licensee has provided an acceptable response, reconfirming that the General Design Criteria 14,15, and 30 of Appendix A to 10 CFR 50 have been met.

6 t o DOCUMENT AN ALYSas . s. KE YWORD$/QE3CR,PTORS IS AW A LA8 U r Y Unlimited t$ SECURITY CLA&SI'!! CATION IThos repes m io:NiiPi Rs,OP N eNoso firms Unclassified (Thos reportl Unclassified i1. NUMBER OP PAGES IS PRICE

.. . . . . .