ML20247J910

Rev 1 to Technical Evaluation Rept TMI Action--NUREG-0737 (II.D.1) Relief & Safety Valve Testing,Fort Calhoun

ML20247J910
Person / Time
Site:	Fort Calhoun
Issue date:	06/30/1989
From:	Finemen C, Nalezny C, Pace N EG&G IDAHO, INC., IDAHO NATIONAL ENGINEERING & ENVIRONMENTAL LABORATORY
To:	NRC
Shared Package
ML20247J907	List: ML20247J910
References
CON-FIN-A-6492, RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM EGG-NTA-7634, EGG-NTA-7634-R01, EGG-NTA-7634-R1, TAC-44582, NUDOCS 8907310376
Download: ML20247J910 (38)

Text

1 EGG-NTA-7634 -

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

RELIEF AND SAFETY VALVE TESTING FORT CALHOUN DOCKET NO. 50-285' N. E. Pace C. P. Fineman C. L. Nalezny June 1989

, Idaho National Engineering Laboratory EGAG Idaho, Inc.

Idaho Falls, Idaho 83415 l

Prepared for the U.S. Nuclear Regulatory Cemission Washington D.C. 20555 under DOE Contract No. DE-AC07-76ID01570 FIN No. A6492 TAC NO. 44582 l-p

$$7310376890724 Fri' l ADUCK 05000285 I

PNU IlR --

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ABSTRACT In the past, safety and relief valves installed in the primary coolant system of light water reactors have performed improperly. As a result, the

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authors of NUREG-0578 (TMI-2 Lessons Learned Task Force Status Report and

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Short-Term Recommendations), and, subsequently, NUREG-0737 (Clarification of

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TMI Action Plan Requirements) have recommended that programs be developed I and completed to: (a) reevaluate the functional performance capabilities of pressurized water reactor (PWR) primary coolant system safety, relief, and )

block valves and (b) verify the integrity of the pressurizer safety and l relief valve piping systems for normal, transient, and accident conditions.

This report documents the review of those programs by the Nuclear Regulatory 1 Commission (NRC) and their consultant, EG&G 3daho, Inc. Specifically, this report documents the review of the Fort Calhoun Licensee response to the requirements of NUREG-0578 and NUREG-0737. This review found that the Licensee, Omaha Public Power District, has not provided an acceptable submittal; thus, the Licensee has not reconfirmed that General Design Criteria 14, 15, and 30 of Appendix A to 10 CFR were met for the subject ecuipment.

FIN No. A6492--Evaluation of OR Licensing Actions-NUREG-0737. II.D.1 11

SUMMARY

The failure of a power-operated relief valve (PORV) to resent was a significant contributor to the Three Mile Island (TMI-2) sequence of events. This failure, plus other previous instances of improper valve performance, led the task force which prepared NUREG-0578 and NUREG-0737 to recommend that programs be developed to reexamine the functional performance capabilities of pressurized water reactor (PWR) primary coolant system safety, relief, and block valves. The task force also recommended programs to verify the integrity of the pressurizer safety and relief valve piping systems for noraal, transient, and accident conditions. This was deemed necessary to reconfirm that General Design Criteria 14,15, and 30 of 10 CFR 50, Appendix A, have indeed been satisfied for the subject eouipment.

This report documents the review by EG&G Idaho, Inc., of the Fort Calhoun Licensee response to the requirements of NUREG-0578 and NUREG-0737.

The Licensee submittals were revivwed to determine the applicability of the test valves and test conditions to the plant valves and inlet conditions.

The operability of the test valves was reviewed to determine the operability of the plant valves. The Licensee's analysis of the pressurizer discharge piping was reviewed to determine if acceptable stress limits were met for valve discharge transients.

The Licensee only partially met the requirements of NUREG-0578 and NUREG-0737. The test results showed that the safety valve tested functioned satisfactorily for all steam discharge events that are applicable to the plant valves. This demonstrated the safety valves were constructed in accordance with high quality standards, meeting General Design Criterion No. 30. However, the Licensee's submittals were not sufficient to determine l if: (a) the safety valves, PORVs, and PORV block valves will operate i

acceptably for a feedwater line break, (b) the piant PORV will close properly following operation, (c) the EPRI test data was applicable to the plant PORV block valves, and (d) the piping analysis was adequate to qualify the pressurizer safety and relief valve piping and supports. The Licensee must also incorporate procedures requiring inspection of the safety valves-l -

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fellowing each lift involving loop seal or water discharge. With respect to the p0RVs, it was concluded that unless the heavier springs recommended by Dresser are installed under the main and pilot disks or OPPD can demonstrate that PORV leakage is not'a problem at low pressures, the plant valve is not considered cperable below 100 psig. Because of.these findings it could not' .

be concluded the Licensee had met General Design Criteria 14 and 15 of 10 CFR 50 Appendix A, for the subject equipment. In addition, it was concluded the PORVs and PORV block valves did not meet General Design Criterion No. 30.

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PREFACE This report was prepared for the U.S. Nuclear Regulatory'Comission (NRC), Office of Nuclear Reactor Regulation, by EG4G Idaho, Inc., NRC-Regulatory Technical Assistance Unit.

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d CONTENTS ABSTRACT .............................................................. ii

SUMMARY

............................................................... iii PREFACE ............................................................... v -

1. INTRODUCTION ...................................................... I 1.1 Background .................................................. I 1.2 General Design Criteria and NUREG Requirements .............. I

2. PWR OWNER'S GROUP RELIEF AND SAFETY VALVE PROGRt.M ................ 4

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

4. REVIEW AND EVALUATION ............................................ 7 4.1 Valves Tested ............................................... 7 4.2 Test Conditions ............................................. 9 4.2.1 Safety Valve ......................................... 9 4.2.2 Power-Operated Relief Valve .......................... 12 4.2.3 Block Valve .......................................... 13 4.2.4 Test Conditions Summary .............................. 13 4.3 Valve Operability ........................................... 14 4.3.1 Safety Valve ......................................... 14 4.3.2 Power-Operated Relief Valve .......................... 16 4.3.3 4.3.4 Block Valve .......................................... 19 Operability Summary .................................. 19 4.4 Piping and Support Valuation ................................ 19 4.4.1 Thermal-Hydraulic Analysis ........................... 20 4.4.2 S t r e s s An a l y s i s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 4.4.3 Piping and Support Summary ........................... 25

5. EVALUATION

SUMMARY

............................................... 27 5.1 NUREG-0737 Items Fully Resolved ............................. 27 5.2 NUREG-0737 Items Not Fully Resolved ......................... 28 ,

6. REFEPENCES ....................................................... 30 l

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1 FIGURES

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1. Fort Calhoun pressurizer safety valve inlet piping -!

configuration ..................................................... E'

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TABLES' )

4.4-1 Fort Calhoun USAR loading combinations and primary' stress limits ......................................................... 24 4.4-2 EPRI recommended support load combinations ......................+ 26 1

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omnue f

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1 TECHNICAL EVALUATION REPORT  :

TMI ACTION--NUREG-0737 (II.D.11 RELIEF AND SAFETY VALVE TESTING l FORT CALHOUN DOCKET No. 50-285

1. INTRODUCTION i

I 1.1 Background j l

I In the past, safety and relief valves installed in the primary coolant j system of light water reactors have performed improperly. There were

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instances of valves opening below set pressure, valves opening above set '

pressure, and valves failing to open or reseat. From those past instances of improper valve performance, it is not known whether they occurred because of a limited qualification of the valve or because of basic unreliability of l

the valve design. It is known that the failure of a PORV to reseat was a j significant contributor to the Three Mile Island (TMI-2) sequence of  ;

events. These facts led the task force which prepared NUREG-0578 (Reference 1), and, subsequently, NUREG-0737 (Reference 2) to recomend that programs  !

be developed and executed to: (a) reexamine the functional performance capabilities of pressurized water reactor (PWR) primary coolant system safety, relief, and block valves and (b) verify the integrity of the pressurizer safety and relief valve 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 10 CFR 50, Appendix A, were indeed satisfied for the subject equipment.

1.2 General Desion Criteria and NUREG Recuireme.n_ts General Design Criteria 14, 15, and 30 require: (a) the reactor primary coolant pressure boundary to be designed, fabricated, and tested so as to have extremely low probability of abnormal leakage; (b) the reactor coolant system and associated auxiliary, control, and protection systems are to be designed with sufficient margin to assure that the design conditions are not exceeded during normal operation or anticipated operational 1

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occurrences; and (c) the components, which are part of the reactor coolant pressure boundary, shall be constructed to the highest quality standards j practical. I To reconfirm the integri'.y of overpressure protection systems and thereby assure compliance to the General Design Criteria, the NUREG-0578 i position was issued as a requirement in a letter dated September 13, 197g, 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," which was issued for implementation on October 31, 1980. As stated in the NUREG reports, each PWR 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.

2. Determine valve expected operating conditions through the use of  !

l analyses of accidents and anticipated operational occurrences l referenced in Regulatory Guide 1.70, Rev. 2. j

3. Choose the single failure such that the dynamic forces on the safety and relief valves are maximized.

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

5. Include in the relief and safety valve qualification program the qualification of the associated control circuitry.

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6. Provide test data for NRC staff review and evaluation including l criteria for success or failure of valves tested. . I

7. Submit a correlation or other evidence to auestantiate the valves I tested in a generic test program demonsf. rate the functionability )

of as-installed primary relief and safety ' valves. This  !

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correlation must show that the test conditions used are equivalent i to expected operating and accident conditions as prescribed in the Final Safety Analysis Report (FSAR). The affect of as-built 1

relief and safety valve discharge piping on valve operability must '

also 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 OWNER'S GROUP RELIEF AND SAFETY VALVE PROGRAM In response to the NUREG requirements previously listed, a group of utilities with PWRs requested the assistance of the Electric Power Research. l Institute (EPRI) in developing and implementing a generic test program for pressurizer safety valves, PORVs, block valves, and associated piping systems. Omaha Public Power District (OPPD), the owner of Fort Calhoun, was one of the utilities sponsoring the EPRI Relief and Safety Valve Test Program. The results of the program, which are contained in a series of reports, were transmitted to the NRC by Reference 3. The applicability of those reports is discussed below.

Electric Power Research Institute developed a plan (Reference 4) for testing PWR safety, relief, and block valves under conditions which bound actual plant operating conditions. Electric Power Research Institute, through the valve manufacturers, identified the valves used in the overpressure protection systems of the participating utilities, and representative valves were selected for testing. The valves included a sufficient number of the variable characteristics so that their testing would adequately demonstrate the performance of the valves used by utilities (Reference 5). Electric Power Research Institute, 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).

Electric Power Research Institute contracted with Combustion Engineering (CE) to produce a report on the inlet fluid conditions for pressurizer safety and relief valves in CE designed plants (Reference 7).

Because fort Calhoun was designed by CE, this report is relevant to this '

evaluation.

Several test series were sponsored by EPRI. Power operated relief valves and block valves were tested at the Duke Power Company Marshall Steam Ctation 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 Laboratory located in Windsor, Connecticut. The 4

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results of the relief and safety valve tests are reported in Reference 8.

The results of the block valve tests are reported in Reference 9.

The primary objective of the EPRI/CE Relief and Safety 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 operate. The conditions selected for test (based on analyses) were limited to steam, subcooled water, and steam to water transition. Additional objectives were to: (a) obte.in valve capacity data, i (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. j 1

l The EpRI test program was not designed to provide information on valve reliability. The EPRI program plan (Refarence 4) states, "During the course of the specified tests, each valve will be subjected to a number of operational cycles. However, it should be noted that the test program, to be completed by July, 1981, is not intended to provide valve lifetime, cyclic fatigue or statistical reliability data."

NRC staff approval of'che program is contained in Reference 10.

Reference 10 states the staff has concluded the EPRI program produced sufficient generic safety valve and PORV performance information to enable i utilities to comply with the plant specif k information requirements in NUREG-0737, Item II.D.I. Transmittal of the test results to the NRC meets the requirements of Item 6 of Section 1.2 in this report to provide test data for the safety valves and PORVs. Item 6 was not met for the PORV block valves because the plant specific valves were not tested by EPRI, and OPPD did not provide adequate justification that the EPHI test results were applicable to the Fort Calhoun block valves.

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3. PLANT SPECIFIC SUBMITTAL A preliminary assessment of the adequacy of the overpressure protection system was submitted by OPPD on April 1, 1982 (Reference 11). A later '

submittal on the operability of the PORVs was transmitted by OPPD on July 1, 1982 (Reference 12). An initial assessment of the safety valves and the {

pressurizer safety and relief valve piping was transmitted December 30, 1982 )

(Reference 13), and additional information was submitted on August 2, 1983 )

(Reference 14). A request for additional information (Reference 15) was submitted to OPPD by the NRC on July 23, 1985. Omaha Public Power District responded to this recuest on March 1, 1986 (Reference 16). A second request for information was sent to OPPD on February 17, 1988 (Reference 17). Omaha Public Power District responded to this request in five parts; May 27, 1988, June 28, 1988, June 30, 1988, November 22, 1988, and January 10, 1989 ,

(References 18 to 22). l 1 i 1

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4. REVIEW AND EVALUATION 4.1 Valves Tested v

Fort Calhoun, a CE designed PWR, uses two safety valves, two PORVs, and two PORV block valves in the overpressure protection system. The safety i valves are Crosby HB-BP-86 3K6 valves with steam internals. The plant l

safety valve inlet configuration was modified to consist of a short liquid

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i filled loop seal similar to that shown in Figure 1. Figure I was taken from Reference 23. The PORVs are Dresser 31533VX-30 solenoid actuated pilot operated valves with a bore diameter of 1-3/32 in. Fort Calhoun uses cold loop seals upstream of the PORVs. The block valves are Crane 2-1/2 in, gate i valves, Model 787-U, with Limitorque SMB-00-7.5 operators.

The Crosby 3K6 safety valve was one of the valves tested by EPRI. The plant and test valves are of the same design except the test valve had loop seal internals in the loop seal tests. Only the material used in the valve seats differs, and this does not affect valve operability within the limited ,

number of cycles in the test program. The results of the EPRI tests can, thus, be used to demonstrate the operability of the plant safety valves.

The Dresser 31533VX-30 PORVs installed at Fort Calhoun were originally of the type I design with a 1-3/32 in. bore diameter. The valve tested by EPRI was a 31533VX-30 type 2 design with a 1-5/16 in. diameter. The type 2 design resulted from a need to improve the seat tightness and included modifications to the internals, body, and inlet flange. The body and flange modifications had no affect on valve operability. The Fort Calhoun' valves were modified to incorporate type 2 internals in May 1984. The difference in bore size will only affect valve capacity not operability. The test l valve, therefore, is considered representative of the plant valves.

The Fort Calhoun block valve / operator combination was not tested by EPRI. A request for additional information was sent to the Licensee regarding operability of the block valves (Reference 15). The Licensee's response (Reference 16) was that the block valve test program (Reference 9) was sufficient to demonstrate operability of the untested Crane block valves. A second request for information was sent to OPPD requesting l

. . j SAFETY VALVE INLET FLANGE MATING SURFACE t

3" sch 150 2500#

W. NECX FLANGE 2 PLACES # l 4" sch 150 PIPE 3" sch 160 g l 45' ELBOW 4" sch 160 l P!PE 6" LONG l ,

2 PLACES ,

4" x 3" REDUCING ELE 0W sch ISO L --

2 PLACES d I 2.5" / L 6.88" 1r n

_ 22.30" , i ,

j 16.94" l

PRESSilRIZER i

' ir cf m 3.0" 1.D.

Figure 1. Fort Calhoun pressurizer safety valve inlet piping configuration. .

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additional information ta qualify the block valves (Reference 17). Omaha public power District's response (Reference 20) stated that the operator )

torque requirement to close the valve was recalculated using a valve factor j of 0.3 recommer.ded by Crane and a 0.55 valve factor determined by Westinghouse. A torque requirement of 57 ft-lb was calculated using the 0.3 valve factor, and a torcue requirement of 106 ft-1b was calculated using the f 0.55 valve factor. Omaha Public Power District stated the block valve operators will be set to 106 ft-lb or modified in order to provide this toroue output. While this approach seems to ensure the block valves will fully close when needed, it does not demonstrate the operability of the Fort Calhoun block valve by test data. This is because OpPD still did not clarify how the valves tested by EpRI demonstrate the operability of the Fort Calhoun valves.

I Based on the above, the safety valve and PORV tested are considered applicable to the valves at Fort Calhoun and to have fulfilled Items 1 and 7 of Section 1.2 in this report regarding applicability of the test valves.

1 The Fort Calhoun block valves and operators were not tested in the EpRI l test program, and no applicable test data was presented to demonstrate their operability. Therefore, Items 1 and 7 of Section 1.2 in this report regarding applicability of the block valves tested were not met.

4.2 Test Conditions The valve inlet fluid conditions that bound the overpressure transients .

for CE designed PWR plants were identified in References 7 and 23. The transients considered in those reports include FSAR extended high pressure ,

injection (HpI), and low temperature overpressurization events. The plant specific conditions for these events discussed in this section are taken from References 7 and 23.

4.2.1 Safety Valves l For the safety valves, only steam discharge was predicted for FSAR type l transients. From Reference 23, the peak pressure was 2530 psia and the maximum pressurization rate was 40 psi /s. A maximum backpressure of I

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496 psia was developed at the safety valve outlet. Omaha Public Power l District stated (Reference 16) the plant valve adjusting rings will be set l to -115 (upper) and -14 (lower). These positions are relative to the level position. Fort Calhoun initially had a cold (160'F) safety valve loop seal. Omaha Public Power District modified the Fort Calhoun safety valve j inlet piping to a short liquid filled loop seal. The loop seal was l I

shortened to increase the loop seal fluid temperature and to reduce the dynamic loads on the piping in the event the safety valves discharged.

Omaha Public Power District stated (Reference 18) the loop seal temperature ranged from 265'F at the valve inlet to 500'F at the steam / water interface.

Four steam tests were run with ring settings of 14, or -115,

-14. As noted above, the safety valves at Fort Calhoun are installed using short (6.31 ft) inlet piping with a loop seal. Combustion Engineering and OPPD stated Tests 516, 517, 535, and 537, run with steam using long inlet piping, were the most applicable tests for the Fort Calhoun safety valves (Reference 23). The safety valve used for tests 516 and 517 had steam internals while the safety valve used for tests 535 and 537 had loop seal i internals. The difference between steam and loop seal inter.nals is the use f

of different valve seat materials (Reference 5). Therefore, tests with both j internals are valid for evaluating the operability of the Fort Calhoun I safety valves within the limited number of cycles of the test program.

These tests had peak pressures ranging from 2436 to 2725 psia, pressurization rates from 3 to 267 psi /s, and backpressure of 507 to 582 psia. These tests bound the Fort Calhoun conditions except for testing the valve with a filled loop seal.

The Fort Calhoun 3K6 safety valve performance also needs to be evaluated with a filled loop seal condition. Four cold loop seal tests I (525, 526, 529, and 536) were performed using the Crosby 3K6 safety valve with ring settings of -115, -14 that'can be applied to Fort Calhoun. The four loop seal tests were run with the following conditions: pressurization rate range was 3.3 to 220 osi/s, peak pressure range was 2558 to 2708 psia, l peak backpressure range was 471 to 615 psia, and loop seal temperature range l was 86 to 360'F. These test conditions bound those at Fort Calhoun.

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-1 There was a concern the extended safety valve blowdown (blowdown greater than 5%) observed during the EPRI tests could result in the pressurizer liouid level increasing to the safety valve inlet. Combustion ,

Engineering reanalyzed the LOLD transient, assuming a 20% blowdown, for the-  !

Fort Calhoun plant. Two LOLD transient conditions were analyzed. One was analyzed with a normal safety valve opening while the other assumed a 4-s  ;

delay for steam flow to account for loop seal passage. Other conservative assumptions were also made to maximize pressurizer level swell. The LOLD was chosen because it is the design basis accident that results in tae highest pressurizer pressure for Fort Calhoun. The 20% blowdown is  ;

representative because the blowdown observed in the applicable EPRI tests was 13.6 to 21.1%. The analyses showed the pressurizer level did not reach l

the inlet to the safety valves. Thus, the steam inlet condition was  ;

i maintained.

Review of the CE inlet conditions report (Reference 7) showed that water did not reach the valve during FSAR transients or an extended high pressure injection (HPI) event. The cutoff head for the Fort Calhoun HPI pumps is below the safety valve setpoint so that an extended HPI event would 1 not challenge the safety valves.

l The CE inlet conditions report (Reference 7) did not list the feedwater line break (FWLB) as a transient which challenged the safety valves or PORVs at Fort Calhoun. Because the FWLB is the limiting transient for delivering i high temperature and high pressure water to the safety valve inlet in many  !

PWRs, OPPD was asked a question on the FWLB at Fort Calhoun. Omaha Public Power District stated (Reference 16) that the loss of load (LOLD) is the limiting transient at the plant. They stated the FWLB is less severe than the steam line break (SLB) and the LOLD bounds both of these accidents.

While it is true the FWLB is not as severe as the SLB in terms of break size, the SLB represents an over cooling event; whereas, the FWLB represents an event which is initially an overcooling event followed by an overheating '

event which can fill the pressurizer. This can cause high pressure liquid discharge through the safety valves. Therefore, the operability of the safety valves for the specific fluid conditions due to the FWLB must be addressed.

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4.2.2 Power-Operated Relief Valve

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The two Dresser PORVs at Fort Calhoun have cold loop seals. The loop seal temperature immediately upstream of the PORVs is approximately 200*F (Reference 18). The peak pressure and pressurization rate for the PORVs during FSAR type transients are 2480 psia and 45 psi /s, respectively (Reference 7). The maximum expected backpressure for the PORVs at Fort Calhoun is 400 psia (Reference 18).

The test valve was subjected to three loop seal simulation tests and j fifteen steam tests. In the steam tests, the peak. pressure ranged from 2435 J to 2505 psia. Reference 6 stated that the valve inlet pressure is f

considered to have a potential for affecting PORV cperation only during opening or closing. Therefore, the pressurization rate affects PORV  ;

operability only through the pressi.re achieved at the valve inlet during the I valve opening process. Because the Dresser valve opens quickly (less than 0.5 seconds), the pressure increase during the valve opening cycle is minimal (approximately 22.5 psia increase based on the maximum pressurization rate of 45 psi /s). Testing at the Fort Calhoun setpressure (2400 psia) or above is, therefore, considered adequate. Backpressure ranged from 170 to 760 psia. The loop seal simulations were run with loop ,

seal temperatures of 103, 105, and 321'F, peak pressure of 2490 to l

2505 psia, and 295 to 690 psia backpressure. The test conditions are considered representative of the plant conditions.

As with the safety valves, the CE inlet conditions report (Reference 7) indicated that water did not reach the PORV during FSAR transients or an extended HPI event. The cutoff head for the Fort Calhoun HPI pumps is below the PORV setpoint so that an extended HPI event would not challenge the l

PORVs. The CE inlet conditions report (Reference 7) did not list the FWLB as a transient which challenged the PORVs at Fort Calhoun. As discussed for the safety valves, the operability of the PORVs for the specific fluid conditions due to the FWLB must be addressed.

ThePORVsareusedforlowtemperatureoverpressure(LTOP) protection at Fort Calhoun. For LTOP protectioro, the valve is required to pass the loop seal water, steam at pressures from 465 to 750 psia, steam to water

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transition, and liquid at pressures from 465 to 750 psia with temperatures ranging from 100 to 417'F. The peak pressures noted above are based on analyses that assumed the pressurizer is liquid full (Reference 7). The presence of a steam bubble in the pressurizer, which is the recomended mode  ;

of operation during low temperature operation, would limit the peak pressure i when the p0RV opened on steam. However, this condition was not specifically analyzed. Thus, peak pressure during steam discharge was bounded using the licuid full analysis, i

l The loop seal discharge and steam discharge conditions are considered to be adequately represented by the high pressure tests discussed above. I Steam to water transition is also considered to be adequately represented by l the high pressure transition test 21-DR-85/W. Water discharge during an

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LTOP transient is represented by the low pressure (approximately 690 psia) water tests with fluid temperatures ranging from 112 to 459'F.

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The block valve is required to open and close over a range of steam and  !

water conditions. However, Reference 9 did not provide test data for the Crane block valve at Fort Calhoun. Also, OPPD did not sufficiently justify how the valves tested by EPRI and/or the test data in Reference 9 demonstrate operability of the Crane block valve. Omaha Public Power District stated (Reference 20) the block valve operators will be set to provide a torque of 106 ft-lb based on the revised Westinghouse valve factor of 0.55 versus the Crane valve factor of 0.3. However, this still does not ~

verify the operability of the plant block valves by test. Because the PORV tested showed problems closing with cold loop seal conditions, it is important that Fort Calhoun's block valves be able to function under all conditions. The Licensee's responses (References 16 and 20) are considered inedequate.

4.2.4 Test Conditions Sumary Two transient conditions not part of the d'esign basis are anticipated transients without scram (ATWS) and feed and bleed decay heat removal. The response of the overpressure protection system to ATWS and the operation of 13

a the system during feed 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 events.

For the Fort Calhoun safety valves and PORVs, the test sequences and analyses described above, which demonstrate ,that the test conditions bounded l the conditions for the plant valves, verify that Items 2 and 4 of Section 1.2 in this report were met (except for the fluid inlet conditions for the FWLB). Items 2 and 4 require that conditions for acciderits and i

anticipated operational occurrences be determined and the highest predicted i pressures be chosen for the test. The part of Item 7 which requires showing that the test conditions are equivalent to conditions prescribed in the FSAR was also met for the safety valves and PORVs, except for water discharge during a FWLB.

1 The Licensee did not provide test data or sufficient justification that the EPRI tests are applicable to the plant block valves. Therefore, Items 2, 4, and 7 of Section 1.2 in this report, have not been met for the bicek valves.

4.3 Valve Operability As discussed in the previous section, the Crosby 3K6 safety valves at Fort Calhoun are required to operate with a liquid filled loop seal followed by steam and/or liquid water. The Dresser PORVs are required to operate with a cold liquid filled loop seal followed by steam or liquid. The fluid inlet conditions for the FWLB have not been provided by OPPD; otherwise, the EPRI program tested the Crosby 3K6 safety valve and the Dresser PORV for the required range of conditions. The Crane block valves are required to fully open and close for all possible plant flow and pressure conditions.

i 4.3.1 Safety Valve Combustion Engineering stated (Reference 23) tests 516, 517, 535, and 537 are the most appropriate tests to evaluate the Fort Calhoun safety valves. These four tests are steam chly long inlet piping tests where the test safety valve opened at 2435 to 2530 psia (-2.6 to +1.2% of the design

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set pressure of 2500 psia), had stable behavior, and closed with 13.6 to 21.1% blowdown. The test safety valve flow rate during these four tests ranged from 94 to 103% of rated flow rate at 3% accumulation and 105 to 109%

of rated flow rate at 6% accumulation. The ring settings for these tests were (-95, -14) and (-115 -14) and are similar to those at the plant

'{

(Reference 16).

Loop seal tests 525, 526, 529, and 536 are also applicable to the evaluation of the Fort Calhoun safety valves. In all tests except 536, the j valve experienced chatter during loop seal discharge and stabilized during I steam flow through the valve. The last test (536) was stable during loop seal discharge. Chatter during loop seal passage is expected, but it )

apparently did not damage the satellite valve disk and seat (used for loop seal applications) enough to cause the valve to malfunction. For these four loop seal tests, the opening pressure ranged from 2536 to 2637 psia (+1.4 to

+5.5% above the 2500 psia set pressure), the blowdown ranged from 17.7 to i 19.9%, the rated flow rate ranged from 94 to 99% at 3% accumulation and from 101 to 104% at 6% accumulation, and the lift ranged from 105 to 111%.

Safety valve operation during these tests demonstrated the plant safety i valves should operate stably. Tests were not performed on the 3K6 safety valve with steam internals in a loop seal configuration. However, a steam / water transition test (428) and several water tests (431a and b, 435, and 438) indicate that the 3K6 safety valve may experience more leakage following discharge of water. These tests indicate that inspection and

]

inaintenance are important to the continued reliable operation of the Crosby  ;

3K6 safety valve.

A maximum bending moment of 161,500 in-lb was applied to the 3K6 valve discharge flange during test 441 without impairing valve operation. This {

~

bounds the maximum expected bending moment of 133,000 in-lb at the plant.

For a test to be an adequate demonstration of safety valve stability, the test inlet piping pressure drop should exceed the plant pressure drop.

The plant predicted inlet piping pressure drop is 325 to 339 psi; the pressure drop predicted for test 517 is 346 psi. Therefore, the plant safety valves should be as stable as the test safety valve.

15

____-____-___-_-__a

As noted above, the valve blowdown for the 3K6 valve during the i applicable tests ranged from 13.6 to 21.1%. The Fort Calhoun LOLD analysis with 20% blowdown showed that the pressurizer liquid. level would not reach l the safety valve inlet. This approximates the blowdown observed in the

]

test. Also, the het leg remained subcooled during the LOLD analysis with I the extended blowdown. This indicated that adequate core cooling was  !

maintained.

I 4.3.2 Power-operated Relief Valve  !

1 l 1

The Dresser PORV opened and closed on demand for all nonloop seal tests. During loop seal test 22-DR-9W/W with 321*F water at the valve l inlet, the valve opened on demand but remained open for two seconds upon de-energizing the valve. During cold loop seal tests 16-DR-6W and' 24-DR-6W/W with 103 and 105'F water at the valve inlet, the valve opened i on demand. However, on de-energizing the valve, the valve remained open  !

70 s for one test and until the block valve was closed for the other test '

(approximately 90 s). '

The Fort Calhoun loop seal temperature is approximately 200'F at the valve seat (Reference 18). In Reference 18, OPPD stated that, although this I temperature is lower than the temperatures in the EPRI tests where immediate PORV closure on demand was recorded, this temperature was considered high enough to ensure adequate PORV closure. Omaha Public Power District cited two plant transients where the PORVs opened and, to OPPD's knowledge, closed successfully as support for proper PORV operation with this loop seal  !

temperature.

There are several problems with this argument. First, the Dresser PORV tested by EPRI experienced a 2-s closure delay with a 321'F loop seal. I Omaha Public Power District has not addressed this problem. Also, proper.

performance of the Fort Calhoun valves during the plant transients was inferred from the pressure response; there was no direct indication of when the PORV closed in response to the closing signal. The minimum pressures in the two plant transients (1950 and 1725 psia) were considerably below the '

PORV closing pressure so it is possible the plant PORV had' delayed closure.

16 _ _ . _ _ _ _ _ _

1 1

Therefore, demonstration of the operability of the Fort Calhoun PORV with the 200*F loop seal is still considered inadequate.

Inspection of the valve after testing at the Marshall Steam Station showed the bellows had several welds partially fail. The failure did not

• affect valve performance. Based on the limited number of cycles in the test program, the manufacturer concluded the failure did not have a potential impact on valve performance. The bellows were replaced and did not fail during any of the additional test series.

A bending moment of 25,500 in-1b was-induced on the discharge flange of the test valve without impairing operability. According to the Licensee, the calculated bending moment is 23,016 in-lb (Reference 18). Therefore, the plant value is bounded by the test data.

The Fort Calhoun PORVs are pilot operated valves that use system pressure to hold the disk tight against the seat. At one point Dresser Industries recomended the block valve be closed at system pressures below 1000 psig to avoid steam wirecutting of the PORV disk and seat. Testing by Dresser later indicated the 2000 psig pressure limit to be overly conservative, and the PORV as designed was qualified to system pressures of 100 psig. Below 100 psig, the deadweight of the lever on the pilot valve was sufficient to keep the valve open. Dresser recomends that heavier springs be used under the main and pilot disks to ensure closure if the  !

plant is to operate at pressures below 100 psig. Without the heavier springs recomended by Dresser the PORVs might leak at system pressures below 100 psig. However, if the PORVs have not experienced leakage at low pressures the heavier spring would not be necessary. Omaha Public Power District has not installed the heavier springs at Fort Calhoun. Unless OPPD can demonstrate that leakage at low pressures is not a problem. EG&G Idaho

• concludes they should be modified as recomended by Dresser.

f The Licensee's submittal regarding operability of the PORVs is not considered adequate. The performance of the PORV during EPRI tests under the full range of expected inlet conditions indicates that the PORVs may rot close properly with the 200'F loop seals. In addition, until the heavier

.J 17

springs are installed under the main and pilot disks or OPPD can demonstrate that leakage is not a problem at low pressures, the valve is not considered operable below 100 psig.

NUREG-0737, Item II.D.1, requires qualification of assor.ided control circuitry as part cf the safety / relief valve qualifiestion. It is tb NRC staff position that the qualification required by Itet II.D.1 is environmental qualification of the control ci-ruits. Based on Reference 10, the requirement for environmental qualification of those circuits was to be met by including them in the program to meet the licensing requirements of -

10 CFR 50.49. If the PORV control circuits are included in the 10 CFR 50.49 program, specific testing to meet the NUREG-0737 requirements is not necessary. However, the Fort Calhoun PORV control circuitry is primarily outside containment (except fer the solanoid valves which are in containment) and not subject to severe service conditions. In Reference 19, OPPD reviewed the conditions durinn which the PORVs are required to operate.

The PORVs are expected to open only during a LOLD, a power increase event, or a LTOP event. In the first two ce m . the PORVs pass steam and the pressurizer quench tank is sized to conuin the primary coolant released. Thus, a harrh environment is not created. Under LTOP conditions, OPPD stated the amount of primary coolant that would be discharged is not known exactly. However, OPPD provided several reasons-the coolant oischarge for an LTOP transient was axpected to be less than for a transient starting i from normal operating conditions. Therefore, the quench tank would be able to contain the fluid discharge and the containment environment would remain mild. EG&G Idaho reviewed the reasons discussed by OPPD (Reference 19) and agrees the fluid discharge for LTOP conditions should be less than the ' fluid discharge for a transient starting from normal operating conditions.

Because the PORV control circuitry will only see a mild environment for which it is qualified, the environmental qualification requirements for the PORV control circuitry were met.

18

l 4.3.3 Block Valve The PORV block valve must be capable of closing over a range of steam 'l and water conditions. The Crane block valve with its Limitorque $MB-00-7.5 I operator was not tested by EPRI. The Licensee's responses (References 16 and 20) are inadequate considering the fact the PORVs are not qualified.

1 4.3.4 Operability Sumary l

1 The Licensee conducted tests to qualify the safety valves (Item 1 of Section 1.2 in this report) and considered the effect of discharge piping on safety valve and PORV operability (Item 7 of Section 1.2 in this report).

The information provided by the Licensee demonstrates that the safety valves )

will operate satisfactorily, provided OPPD develops methods to ensure continued operability following each lift involving loop seal or watar discharge (e. g. procedures to inspect and maintain the safety valves foliowing rach lift). The information provided by the Licensee on the environmental qualification of the PORV control circuitry is adequate to I.

satisfy Item 5 of Section 1.2 in this report. The information above does not demonstrate that the PORVs and PORV block valves will operate reliably (Item I of Section 1.2 in this report). With. respect to the PORVs it was concluded that unless the heavier springs reconrnended by Dresser are 1 installed under the main and pilot disks or OPPD can demonstrate that PORV leakage is not a problem at low pressures, the plant valve is not considered operable below 100 psig.

4.4 pipino and Support Evaluation The Licensee stated the safety valve and PORV inlet piping and the piping between the valve discharge flanges and the pressurizer relief tank were analyzed. This analysis included the pipir.g supports. The piping upstream of the safety valves and PORVs was analyzed to the requirements of the USAS B31.7 Code, 1969 Edition with 1971 Addenda. However, the ASME Code,Section III, Subsection NB, 1983 Edition was substituted for Equation 10 of the USAS Code. The downstream piping was designated as USAS B31.1 Code piping, but analyzed to the requirements of the ASME Code, Section 111,.  ;

19 '

l Subsection HC (Class 2), 1974 Edition. The supports were analyzed to the requirements of the Fort Calhoun Updated $afety Analysis Report (USAR).

These codes of record are acceptable.

4.4.1 Thermal-Hydraulic Analysis The thermal-hydraulic analysis of the safety valve /PORV piping systems (References 16 and 22) was performed using the RELAPS/ MODI code, the Impe11 proprietary code HYDRAFLOW, and RELAPS/M002. RELAPS/ MODI was verified for use on safety valve /PORV piping (Reference 25). RELAPS/ MOD 2, an impreved version of RELAP5/M001, is considered adequate for this type of analyses.

HYDRAFLOW is based on RELAP5/M0f)1, cycle 14, but with a dynamic spring-loaded safety valve model added to the code to calculate valve dynamics during the opening and closing process. HYDRAFLOW was benchmarked against EPRI data for the Crosby 3X6 safety valve, the same valve used at l Fort Calhoun. This verification, along with the verification work presented I in Reference 25 on the RELAP5/ MODI base code, is considered adequate.

Based on Reference 22, four cases were originally analyzed: (a) both FORVs opening et the same time (the PORVs have the same set pressurt), (b) each safety valve opening alone (the safr>ty valves have staggered set pressures, cases 2 and 3), and (c) both safety valves opening simultaneously while the PORVs remain closed. During the loop seal tests, the opening pressure for the valve ranged from +1.4 to +5.5% oT set pressure, and during the ?,eam tests, the opening pressure ranged from -2.6 to +1.4% of set pressure. The difference in set pressures for the two Fort Calhoun safety valves is only 1.8%; this is within the e..pected range of lift prescures for the safety valves. Therefore, a case where the two safety valves lifted at the same pressure was analyzed (Reference 22).

The safety valve and relief valve discharge loads were calculated for the fluid transient condition that will produce the most severe loading on the piping system. This occurs during a high pressure steam transient where steam from the pressurizer forces the water in the loop seal through the safety or relief valve down the piping system to the relief tank. -

i 20

~

The safety valve rated flow rate is 240,000 lb/h. The safety valve flow rete used in the analyses ranged from 221,846 lb/h in the single valve actuation cases to 252,000 lb/h in the simultaneous valve actuation case.

The measured safety valve flow, during EPRI testing, ranged from 94 to 99%

of rated flow at 3% accumulation in the applicable loop seal tests.

Although the flow rate used in the single ssfe u valve actuation cases is slightly low (02% cf rated flow) compared to the EPRI data, the flow rate for the simultaneous valve opening case is larger than the measured flow.

Overall, the flow rates used in the analysis are considered adequate. For the p0RV, the rated flow of 117,000'Ib/h was used. This is acceptable based on the EPRI Dresser PORV test results adjusted for the difference in valve size. The valves were assumed to open at their set pressures (2400 psia for the p0RVs, and 2500 and 2545 psia in the single safety valve actuation cases). In the simultaneous rafety valve actuation case, both valves were assun d to open at 2545 psia. A system pressurization rate of 60 psi /s was usee, but the maximum pressurizer pressure used in the analysis was not provided. Because the appropriate flow rates were used in the analysis and j the Fort Calhoun inist configuration includes a loop seal, the peak pressure used in the analysis is considered to have a second order effect on the force calculation. Thus, review of this parameter is not considered necessary to determine whether an adequate analysis was performed. Opening pop times in the analyses ranged from 4 to 5 ms for the safety valves.

These opening times are more conservative than opening times measured in the EpRI tests for the safety valves (valve opening time in the applicable loop seat tests ranged from 8 to 90 ms). For the PORVs, an opening time of 140 ms was used in the analysis; however, the minimum opening time for the Dresser PORV during the loop seal simulation tests was 60 ms. Because the PORV inlet includes a cold loop seal, the valve opening time is considered to have a second order effect on the force calculation. The PORV opening time is, therefore, considered adequate. - '

The loop seal temperatures used in the analyses are provided in .

Reference 22. The temperature in the PORV loop seal ranged from 600'F at the steam / water interface to 130'F at the valve inlet. The temperature in the safety valve loop seal ranged from 500*F next to the steam / water interface to 265'T at the valve inlet. The safety valve loop seal temperature profile was based on a full scale loop seal temperature test.

21

j l

l Conservative (130"F at the valve inlet versus an expected 200'F) plant j calculations based on the safety valve loop ceal temperature tests are used to determine the PORV loop seal temperature profile, i

The node sizes used in the analyses are provided in Reference 22. They were reviewed and found to be appropriate for this type of analysis. The  !

time step size ranged from 1 x 10-6 to I x 10-3 s, with a maximum time 5:.ep of 2.5 x 10~4 s during the loop seal discharge. The Impe11 report attached to Reference 22 stated these time steps were consistent with those recommended in Reference 25. This is not entirely true. First, Reference 25 used a maximum time step of 2 x 10'4 s for the entire analysis not just the loop seal discharge portion. Therefore, there is a potential that the larger time steps in the Impell analysis underestimated the piping forces. Second, the maximum time step is related to the minimum  !

node size used in the piping model. The 2 x 10'4 s time step used (Reference 25) was adequate for a minimum node size of 0.5 ft. However, the minimum node size shown in Tabic 4.1-2 of the Impe11 report mentioned above was 0.208 ft. Therefore, a time step of at least 0.208/0.5 = 0.42 times the time step in Reference 25 should have been used. Therefore, until the time i j

step size used in the analysis is justified, the thermal-hydraulic analysis is not considered adequate. '

4.4.2 StressAnalys3 The Licensee stated (Reference 16) that hydrau'lic loads were calculated using the FORCE "'.d REFORC codes in conjunction with the RELAPS/ MODI and RELAPS/M002 output. TPIPE and SUPERPIPE were then used to do the piping alysis where piping stresses and hanger leads were predicted. These i analyses were done at OPPD and Impe11 Corp. The Licensee provided adequate  ;

information on the verification of the FORCE and TPIPE codes i (Reference 19). Verification of SUPERPIPE and REFORC was reviewed in other i NUREG-0737, Item II.D.1, submittals and found adequate.

The important structural analysis parameters of time step size, lumped mass spacing, cutoff frequency, and damping were reviewed. A time step size of 0.0005 s was used for all the structural ar' lyses. This time step size is considered adequate. Damping of 0.5% was used for the TPIPE analysis of i

22

7 1

I the p0RV discharge and single safety valve discharge cases. This damping is acceptable. Damping of 2.5% at 20 Hz and 2.7% at 175 Hz, based on NUREG/CR-4562 (Reference 26), was used in the SUPERpIPE analysis of the simultaneous safety valve discharge. Although this damping is larger than that used in the TPIPE analysis, it is considered acceptable. This is because recent research (Reference 26) indicates these damping values are q more realistic and could improve the overall piping / support system )

performance relative to the use of smaller, overly conservative damping values. Because a direct integration technique was used to analyze the

]

system response, cutoff frequencies were not input to the codes. Therefore, the maximum frequen:y to be adequately analyzed would be based on the time.

step size and the lumped mass spacing. The time' step size is considered

)

adequate to analyze frequencies greater than'200 Hz, which is acceptable.

]

The lumped mass spacing was chosen to limit the maximum element length to approximately 12 pipe diameters; typical elements were less than one half the maximum size. Based on the typical size, an element would be on the order of 3.5 ft long for a 6 in. pipe. With these element sizes, the maximum frequency that could be adequately analyzed would be greater than 200 Hz. This is adequate. Therefore, the important parameters in the analysis are considered acceptable.

The load combinations used in the structural analysis are provided in Reference 22. The source of the piping load combinations was not provided in the reference; however, the attached Impell report stated the load combinations used met the intent of the plant USAR and the original design basis. This is not clear, however, as the load combinations used in the 1 i

analysis never combined valve discharge loads and safe shutdown earthquake  ;

(SSE) loads as required by the plant USAR (see Tables 4.2-1, -2,'and -3 in l

the Impe11 report attached to Reference 22 and Table 4.4-1 in this report). ,

A load combination combining valve discharge and SSE loads was also  !

recommended by EPRI (Reference 27). I

• l The load combinations used for the support analysis were those recommended by EPRI (Reference 27). However, the support analysis used loading limits based on the plant USAR (see Attachment 2 to Reference 22) rather than the limits recommended by EPRI. It is not clear whether the two (EPRI load combinations and USAR load limits) were integrated properly. The 23 I

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plant USAR and EPRI load combination requirements are shown in Tables 4.4-1 and 4.4-2, which were taken from the plant USAR and Reference 27, respectively. The EPRI' normal load combination was compared to the USAR load combination 1 allowable (working stress), even though the USAR load combination includes a design basis earthquake (DBE) load and the EPRI load combination does not. The EPRI upset, emergency, and faulted load combinations were compared to the USAR load combination 2 allowable (within yield). However, the USAR load combination contains an SSE load, while the EPRI upset and emergency load combinations do not contain seismic loads, or if a seismic lead is included, it is based on a DBE load and not a SSE load.

Based on the above considerations, it is not clear whether appropriate load combinations and allowables were used in the structural analysis.

The original analysis showed the system piping and supports to be overstressed due to the forces generated by the loop seal discharge. To reduce the pipe and support loads, a line was added to drain part of the loop seals upstream of the PORVs, and the safety valve inlet piping was reconfigure to reduce the loop seal volume. These factors combined to reduce the system loads due to smaller water volumes and higher loop seal temperatures. However, additional modifications were needed in order to reduce the system loads below code allowables for the PORV and single safety valve discharge cases. These modifications were made. Subsequently, the simultaneous safety valve discharge case was analyzed and a need for additional modifications was identified. These modifications were made and OPPD determined the system met all code requirements. However, because of -

the questions on the thermal-hydraulic and structural analyses identified by EG&G Idaho, Inc., OPPD has not provided sufficient information to confirm the conclusion regarding code compliance of the system.

l 4.4.3 Piping and Support Sumary The analyses discussed above demonstrated that a bounding case was chosen for the piping configuration. Therefore, Item 3 of Section 1.2 in this report was met. However, because of questions on the adequacy of the thermal-hydraulic and structural analyses, it cannot be concluded that Item 8 of Section I.2 in this report was met.

_ _ _ _ _ _ ____ _ ______ _ . _ _ _ . _ _m

TABLE 4.4-2. EPRI RECOMMENDED SUPPORT LOAD COMBINATIONS

'l LOAD COMBINATIONS AND ACCEPTANCE CRITERIA FOR PRESSURIZER SAFETY AND REllEF VALVE PIPING cND SUPPORTS - SEISMICALLY DESIGNED DOWNSTREAM P0,R_T1QN Plant / System Service Stress Ce-bination Operatino Condition 126d Combination Limit 1 Normal N A 2 Upset N + SOTU B 3 Upset N + OBE + SOTU C 4 Emergency N + SOTE C S Faulted N + MS/FWPB or DBPB D

+ SSE + SOTp 6 Faulted N + LOCA + SSE + SOTp D NOTES: 1.) Plants without an FSAR may use the proposed criteria contained in Tables 1-3. Plants with an FSAR may use their original design basis in conjunction with the appropriate system operating transient definitions in Table 3; or they may use the proposed criteria contained-in Tables 1-3.

2.) This table is applicable to the seismically designed portion of downstream noncategory I piping (and supports) necessary to isolate the Category I portion from the nonseismically designed piping response, and to assure acceptable valve loading on the discharge nozzle.

3.) See Table 3 for SOT definitions and other load abbreviations.

4.) The bounding number of valves (and discharge sequence if setpoints are significantly different for the applicable system operating transient defined in Table 3 should be used.

S.) Verification of functional capability is not' required, but allowable loads and accelerations for the safety relief valves i must be met.

6.) Use SRGS for combining dynamic load responses.

_ _ _ _ _ _ - _ _ - _ _ - _ _ _ _ _ _ _ - _ - _ _ _ - - _ - _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ R

5. EVALUATION SLMiARY The Licensee for Fort Calhoun has not provided an acceptable response to the requirements of NUREG-0737. Therefore, the Licensee has not reconfirmed that the General Design Criteria 14, 15, and 30 of Appendix A to 10 CFR 50 were met with regard to the safety valvts, PORVs, ar.d PORV block valves. The rationale for this conclusion is given below.

5.1 NUREG-0737 Items Fully Resolved Based on the information provided by the Licensee, the requirements of Item II.D.1 of NUREG-0737 were partially met. This includes Item 1, part of 'i Item 2, Items 3-6, and part of Item 7 of Section 1.2 in this report regarding the safety valves, part of Items 1 and 2, Items 3-6, and part of Item 7 were met for the p0RVs.

)

The Licentee participated in the development and execution of an I

j acceptable relief and safety valve test program. The program was 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, bound the most probable maximum forces expected from anticipated operational occurrences'and design basis events.

The test results indicated that the safety valve tested functioned correctly and safely for all steam discharge events specified in the test program that  !

were applicable to Fort Calhoun. Analysis end review of both the test results and the Licensee justifications indicated the performance of the l l

safety valves can be directly extended to the in-plant valves.

Therefore, the prototypical tests and the successful performance of the safety valves and associated components, demonstrated that this equipment was constructed in accordance with high quality standards meeting General Design Criterion No. 30.

_ _ _ _ _ _ _ _ _ . _ _ _ _ - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ' - - ' - " ^ ' ^ - ' - - -

5.2 NUREG-0737 Items Not Fully Resolved Based on the information provided by the Licensee, the following requirements of Item II.D.1 of NUREG-0737, as identified in Section 1.2 of this report, were not met.

Item 1: The part of Item 1 that requires tests be conducted to qualify reactor coolant system relief valves was not met for the PORVs or the PORV block valves. The test results demonstrated that the PORVs might not close properly following operation; therefore, they were not demonstrated to operate reliably. Data from tests that are applicable to the Fort Calhoun bicek valves was not presented.

Item 2: The part of Item 2 that requires the expected valve operating conditions to be determined for the transients and accidents listed in Regulatory Guide 1.70, Rev. 2 was not met for the feedwater line break.

This is because conditions for the FWLB were not considered.

Item 4: The part of Item 4 that requires the highest predicted pressure be chosen for the tests was not met for the PORV block valves because the Fort Calhoun block valves were not tested.

Item 6: The part of Item 6 that requires test data be provided for the NRC staff review and evaluation, including criteria for success or failure of valves tested, was not met for the FORV block valves. This is because the plant specific valves were not tested by EPRI, and OPPD did not provide adeesste justification that EPRI test results are

! applicable to the Fort Calhoun block valves.

Item 7: The following parts of Item 7 were not met.

a. The part of Item 7 that requires the Licensee to submit a -

correlation or other evidence to substantiate the valves tested in a generic test program demonstrate the functionability of as-installed primary relief'and safety valves was not met for the PORV block valves.

The Licensae has not provided evidence to indicate the valves tested by EPRI are representative of the untested block valve at Fort Calhoun.

28

l , ,

l The Licensee's conclusions regarding the adequacy of the plant operator-were based on calculations and not supported directly by test data.

b. The part of Item 7 that requires showing the test conditions are equivalent to those prescribed in the FSAR was not met for water discharge through the safety valves, PORVs, and PORV block valves.

Conclusive evidence was not provided to show the PORVs and safety valves will not be required to pass water during a feedline break event.

Evidence was not provided-that block valve tests were completed under conditions that bound the Fort Calhoun plant specific conditions.

Item 8: The part of Item 8 that requires qualification of the piping and supports was not met. This is because, based on the information supplied by the Licensee, it cannot be concluded the thermal-hydraulic and structural analyses were adequate to qualify the pressurizer safety and relief valve piping and supports.

The tests demonstrated the need for inspection and maintenance to maintain the operability of the safety valves. Therefore, the Licensee must develop procedures requiring inspection and maintenance of the safety valves following each lift which involves loop seal or water discharge. They must be incorporated into the plant operating procedures or licensing documents.

With respect to the PORVs, it was concluded that unless the heavier springs recommended by Dresser are installed under the main and pilot disks or OPPD can demonstrate that PORV leakage is not a problem at low pressures, the plant valve is not considered operable below 200 psig.

Therefore, the Licensee has not demonstrated by testing and analysis for the subject equipment that: (a) the reactor primary coolant pressure boundary will have a low probability of abnormal leakage (General Design Criterion No. 14), (b) the reactor primary coolant pressure boundary and its associated components (piping, valves, and supports) were designed with a sufficient margin so that design conditions are not exceeded during safety valve /PORV events (General Design Criterion No. 15), and (c) the PORVs and PORV block valves were constructed in accordance with high quality standards (General Design Criterion No. 30).

FB . _ _ _ _ _ _ _ _ -

6. REFERENCES

1. TMI-2 Lessons Learned Task Force, TMI-2 Lessons Leaned Task Force Status i Reoort and Short-Term Recommendations, NUREG-0578, July 1979. l

2. Clarification of TMI Action Plan Requirements, USNRC, Division of Licensing, NUREG-0737, November 1980.

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

" Transmittal of PWR Safety and Relief Valve Test Program Reports,"

September 30, 1982. 3

{

4 Procram Plan for Performance Testino of PWR Safety and Relief Valves, Electric Power Research Institute, July 1980.

5. EPRI PWR Safety and Relief Valv,e Test Procram Valve 1 Selection /Justif'ication Report, MPR Associates Inc., EPRI NP-2292, December 1982.

6. PWR Valve Program Staff, EPRI PWR Safety and Relief Valve Test Procram, Test Condition Justification Report, EPRI NP-2460, December 1982.

7. Valve Inlet Fluid Conditions for Pressurizer Safety and Relief Valves in Combustion Encineerinc-Desion Plants, Combustion Engineering, EPRI NP-2318, December 1982. )

)

B. EPRI Valve Test Program Staff, EPRI PWR Safety and Relief Valve Test Procram, Safety and Relief Valve Test Report, EPRI NP-2628-SR, December 1982.

9. EPRI/ Marshall Electric Motor Ooerated Block Valve, Intermountain Technologies, Inc., EPRI NP-2514-LD, July 1982. l 10.

Letter W. J. Dircks, NRC Staff, to NRC Commissioners "Adecuacy of Safety and Relief Valve Testing and Performance," SECY-83-270, July 5, 1983.

11. Letter W. C. Jones, OPPD, to R. A. Clark, NRC, " Safety and Relief Valve Test Program," LIC-82-138, April 1, 1982. '

12.

Letter W. C. Jones, OPPD, to R. A. Clark, NRC, "NUREG-0737 -Item II.D.1, Relief and Safety Valve Test Program," LTC-82-253, July 1, 1982. '

13.

Letter W. C. Jones, OPPD, to R. A., Clark, NRC, "NUREG-0737. Item II.D.1, Relief and Safety Valve Test Program," LIC-82-415 December 30, 1982.

14.

c Letter W. C. Jones, OPPD, to R. A. Clark, NRC, "NUPEG-0737. Item II.D.1, Safety and Relief Valve Test Program," LIC-82-182, August 2, 1983.

15. Letter E. J. Butcher, NRC, to R. L. . Andrews, OPPD, " Request for Additional Information Regarding NUREG-0737. Item II.D.1 Cuncerning Performance Testing of Relief and Safety Valves," July 23, 1985.

_ _ _ . _ _ - _ _ _ _ _ - _ -_ . _ _ . _ _ - - _ _ _ _ _ _ - _ - _ .. N _

16. Letter R. L. Andrews, OPPD, to A. C. Thadani, NRC, " Additional Information on Performance Testing of Relief and Safety Valve Testing, NUREG-0737,_ Item II.D.1," LIC-86-083, March 1, 1986.

17. Letter A. Sournia, NRC, to R. L. Andrews, OPPD, " Request for Additional Information Concerning NUREG-0737 Item II.D.1,". February 17, 1988.

18. Letter R. L. Andrews, OPPD, to U.S. Nuclear Regulatory Commission, Document Control Desk, " Response to Request for Additional Information Ccncerning NUREG-0737, Item II.D.1," LIC-88-384, May 27, 1988.

19. Letter R. L. Andrews, OPPD, to U.S. Nuclear Regulatory Commission, Document Control Desk, " Response to Request for Additional Information Concerning NUREG-0737. Item II.D.1," LIC-88-477, June 28, 1988. .

20. Letter R. L. Andrews, OPPD, to U.S. Nuclear Regulatory Commission, Document Control Desk, " Response to Request for Additional Information Concerning NUREG-0737, Item II.D.1," LIC-88-550, June 30, 1988.

21. Letter K. J. Morris, OPPD, to U.S. Nuclear Regulatory Commission.

Document Control Desk, " Response to Request for Additional Information Concerning NUREG-0737, Item II.D.1," LIC-88-1020 November 22,.1988.

22. Letter K. J. Morris, OPPD, to U.S. Nuclear Regulatory Commission, Document Control Desk, " Responses to Request for Additional Information Concerning NUREG-0737, Item II.D.1," LIC-89-040, January 10, 1989.

, 23. CE Owner's Group, Summary Report on the Operability of Pressurizer Safety Valves in C-E Designed Plants, CEN-227, December 1982.

24 CE Owner's Group, Summary Report on the Operability of Power Operated Relief Valves in C-E Designed Plants, CEN-213, June, 1982.

25. Verification of RELAP5/M001 for Calculation of Safety and Relief Valve Discharge Piping Hydrodynamic Leads,-Intermountain Technologies, Inc...

EPRI-2479, December 1982.

26. A. G. Ware, Pipe Dampino - Results of Vibration Tests in the 33 to 100 gertz Frecuency Rance, NUREG/CR-4562, EGG-2450, July 1986.

27. EPRI PWR Safety and Re*ief Valve Test Program. Guide for Application of Valve Test Program Results to Plant-Specific Evaluations, Revision 2, MPR Associates, Inc., Interim Report, July 1982. .

31

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