ML17223A129

Technical Evaluation Rept TMI Action NUREG-0737 (II.D.1) Relief & Safety Valve Testing,St Lucie,Unit 1.

ML17223A129
Person / Time
Site:	Saint Lucie
Issue date:	12/31/1988
From:	Fineman C, Nalezny C, Pace N EG&G IDAHO, INC., IDAHO NATIONAL ENGINEERING & ENVIRONMENTAL LABORATORY
To:	NRC
Shared Package
ML17222A799	List: ML17223A129 ML17223A132
References
CON-FIN-A-6492, RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM EGG-NTA-8331, NUDOCS 8905190243
Download: ML17223A129 (30)

Text

EnclqzuIe. 2 0 EGG-NTA-8331 TECHNICAL EVALUATION REPORT TMI ACTION--NUREG"0737 (I I.D.1)

RELIEF AND SAFETY VALVE TESTING ST. LUG IE, UNIT 1 DOCKET NO. 50-335 N. E. Pace C. P. Fineman C. L. Nalezny December 1988 Idaho National Engineering Laboratory EG&G Idaho, Inc.

Idaho Falls, Idaho 83415 Prepared for the U.S. Nuclear Regulatory Commission Mashington, D.C. 20555 Under DOE Contract No. DE-AC07-76ID01570 FIN No. A6492 8905190243 890511 PDR ADOCK 05000335 P PDC

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ABSTRACT Light water reactors have experienced a number of occurrences of improper performance of safety and relief valves installed in the primary coolant system. As a result, the authors of NUREG-0578 (TMI-2 Lessons Learned Task Force Status 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 Mater 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 (NRC) and their consultant, EGSG Idaho, Inc. Specifically, this report documents the review of the St. Lucie 1 Licensee response to the requirements of NUREG-0578 and NUREG-0737. This review found the Licensee has not provided an acceptable response and, therefore, has not reconfirmed that General Design Criteria 14, 15, and 30 of Appendix A to 10 CFR 50 were met.

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

CONTENTS A BSTRACT ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ii 1 ~ INTRODUCTION ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 1 1 .1 Background .........................................

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

2. PWR OWNER'S GROUP RELIEF AND SAFETY VALVE PROGRAM ............,... 4

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

4. REVIEW AND EVALUATION ...... ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 7 4.1 Valves Tested .............................................. 7 4 2

~ Test Cond>tions .. 8 4.3 Valve Operability .......................................... 12 4.4 Piping and Support Evaluation .............................. 16

5. EVALUATION

SUMMARY

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5. 1 NUREG-0737 Items Fully Resolved . ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 20 5.2 NUREG-0737 Items Not Resolved .............................. 21

6. REFERENCES .. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 22

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1 TECHNICAL EVALUATION REPORT TMI ACTION--NUREG-0737 I I .D. 1 RELIEF AND SAFETY VALVE TESTING ST. LUCI E UNIT 1 DOCKET NO. 50-335

1. INTRODUCTION 1.1 ~Back round Light water reactor experience has included a number of instances of improper performance of relief and safety valves installed in the primary coolant systems. There were instances of valves opening below set pressure, valves opening above set pressure, and valves failing to open or reseat.

From these past instances of improper valve performance, it is not known whether they occurred because of a limited qualification of the valve or because of basic unreliability of the val've design. It is known that the failure of a power operated relief valve (PORV) to reseat was a significant contributor to the Three Mile Island (TMI-2) sequence of events. These facts led the task force which prepared NUREG-0578 (Reference 1) and, subsequently, NUREG-0737 (Reference 2) to recommend that programs be developed and executed which would reexamine 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. These programs were deemed necessary to reconfirm that the General Design Criteria 14, 15, and 30 of Appendi'x A to Part 50 of the Code of Federal Regulations, 10 CFR, are indeed satisfied.

1.2 General Desi n Criteria and NUREG Re uirements General Design Criteria 14, 15, and 30 require that (1) the reactor primary coolant pressure boundary be designed, fabricated, and tested so as to have extremely low probability of abnormal leakage, (2) the reactor coolant system and associated auxiliary, control, and protection systems be designed with sufficient margin to assure that the design conditions are riot

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exceeded during normal operation or anticipated transient events, and (3) 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 the Division of Licensing (DL), Office of Nuclear Reactor Regulation (NRR), to ALL OPERATING NUCLEAR POMER PLANTS. This requirement has since been incorporated as Item II.D.1. of NUREG-0737, Clarification of TNI Action Plan Requirements, which was issued for implementation on October 31, 1980.

As stated in the NUREG reports, each pressurized water reactor Licensee or Applicant shall:

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

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 pressure 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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0 7. Submit a correlation or other evidence to substantiate that the valves tested in a generic test program demonstrate the functionability of as-installed primally 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

'nalysis.

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 Institute (EPRI) in developing and implementing a generic test program for pressurizer safety valves, power operated relief valves, block valves, and associated piping systems. Florida Power and Light Co. (FPL), the owner of St. Lucie I, was one of the utilities sponsoring .the EPRI 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 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 conditions. EPRI, through the valve manufacturers, identified the valves used in the overpressure protection systems of the participating utilities and representative valves were selected for testing. These valves included a sufficient number of the variable characteristics so that their'esting would adequately demonstrate the performance of the valves used by utilities (Reference 5). EPRI, through the Nuclear Steam Supply System (NSSS) vendors, evaluated the FSARs of the participating utilities and arriv'ed at a test matrix which bounded the plant transients for which over pressure protection would be required (Reference 6).

EPRI 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). Since St. Lucie I was designed by CE, 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 tested at the Combustion Engineering Company, Kressinger Development

Laboratory, which is located in Windsor, Connecticut. The 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 Valve Test Program was Co 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 analysis) were limited to steam, subcooled water, and steam to water transition. Additional objectives were to (1) obtain valve capacity data, (2) assess hydraulic and structural effects of associated piping on valve operability, and (3) obtain piping reSponse data that could ultimately be used for verifying analytical piping models, Transmittal of the test results meets the requirements of Item 6 of Section 1.2 to provide test data to the NRC.

3. PLANT SPECIFIC SUBMITTAL A preliminary submittal for the adequacy of the overpressure protection system was submitted by FPL on April 1, 1982 (Reference 10). The assessment of the power operated relief valves (PORVs) was transmitted July 9, 1982 (Reference 11). FPL submitted their assessment of the block valves on August 13, 1982 (Reference 12) and of the safety valves and safety valve/PORV piping system on December 30, 1982 (Reference 13). A request for additional information (Reference 14) was submitted to FPL by the NRC on June 21, 1985. FPL responded to this request on March 18, 1986 (Reference 15). A second request for information was sent to FPL on June 10, 1987 (Reference 16). FPL responded to this request on November 6, 1987 and February 5, 1988 (References 17 and 18).

The response of the overpressure protection system to Anticipated Transients Without Scram (ATWS) and the operation of the system during feed and bleed decay heat removal are not considered in this review. 'either the Licensee nor the NRC have evaluated the performance of the system for these events.

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4. REVIEM AND EVALUATION 4.1 Valves Tested St. Lucie 1 is a CE designed PMR that utilizes three safety. valves, two PORVs, and two PORV block valves in the overpressure protection system. The safety valves are Crosby Model HB-BP-86 3K6 valves. The plant safety valves are mounted directly on the pressurizer nozzles. The safety valves all have the same 2500 psia set pressure. The PORVs are Dresser 31533VX-30 solenoid actuated pilot operated valves with a bore diameter of 1-5/32 in. and a 2400 psia set pressure. St. Lucie 1 does not have loop seals upstream of the PORVs.. The block valves are 2-1/2 in. Velan gate valves with Limitorque SMB-00-10 operators.

The Crosby 3K6 valve was one of the valves tested by EPRI. The plant and test valve parameters are identical; therefore, the test valve is considered to adequately represent the plant valves.

The Dresser PORVs (31533VX-30) installed at St. Lucie 1 had type 1 internals, but now have the type 2 internals with a 1-5/32 in. bore. The valve tested by EPRI was a 31533VX-30 design with type 2 internals with a 1-5/16 in. bore size which has bellows employed around the pilot stem to eliminate possible leakage. The type 2 design resulted from a need to improve the seat tightness and include modifications to the internals, body, and inlet flange. The body and flange modifications were not of a nature that would affect operability. Dresser Industries stated the test valve is representative of all valves in service (Reference 5). Also, Dresser Industries recommends that heavier springs be used under the main and pilot disks to ensure closure at pressures below 100 psig. Because leakage has not been a problem at low pressure, FPL has not installed the heavier springs at St. Lucie 1. At full system pressure, the spring force is small relative to the force from the system pressure, so that not using the heavier springs does not affect valve operability. The test valve is considered an adequate representative of the in-plant valves.

The St. Lucie 1 block valves are Velan (Model B09-3054-13MS drawing P-35036-2) 2-1/2 in. gate valves with a Limitorque SMB-00-10 operator. FPL used EPRI data to qualify their block valves. Two Velan 3-inch valves were tested during the EPRI tests; these valves were (1) Model B10-3054B-13MS, drawing 88425/B with a Limitorque SB-00-15 operator and (2)

Model B10-3054B-13MS, drawing GBH-0300-13MS-MO with a Limitorque 'SMB-000-10 operator (Reference 9). Both of these valves are wedge type gate valves.

These tested valves are similar in design and slightly larger than the St.

Lucie 1 plant block valves and are considered representative. However, for the block valves, the Licensee must demonstrate that the block valve operators are set to produce a torque greater than the minimum torque used in the EPRI tests in order for the test results to be directly applicable to plant valves. Based on the information provided by FPL, it cannot be

'he concluded the torque output of the plant operators is greater than the minimum torque used in the EPRI tests. Therefore, the block valve test results are not considered directly applicable to the St. Lucie 1 valves.

Based on the above, the safety valves and PORVs tested are considered representative of the in-plant valves at St. Lucie 1 and to have fulfilled the part of the criteria of Items 1 and 7 as identified in Section 1.2 regarding applicability of the test valves. The block valves at St. Lucie 1 are the similar to the valve tested by EPRI. Therefore, Item 1 of Section 1.2 was met for the block valves. However, the test results for the block valve/operator combination tested by EPRI are not considered to be applicable to the block valve/operator combination at St. Lucie 1 and, therefore, Item 7 of Section 1.2, regarding applicability of the test valves, was not met for the block valves.

4' Test Conditions The valve inlet fluid conditions that bound the overpressure tra'nsients for CE designed PMR plants are identified in Reference 7. The transients considered in this report include FSAR, extended high pressure in]ection (HPI), and low temperature overpressurization events.

For the safety valves only steam discharge.was calculated for FSAR type transients. The peak pressure predicted was 2562 psia and the maximum

pressurization rate was 65 psi/s. A maximum backpressure of 362 psia is developed at the safety valve outlet (Reference 19). St. Lucie 1 has the safety valves mounted directly on.a pressurizer nozzle. FPL stated in Reference 13 that the plant valve adjusting rings will be set to (-72, -14),

(-82, -14), and (-60, -14) for the plant safety valves with the spare safety valve set to (-61, -14). These positions are relative to the level position.

There were no EPRI tests performed with the above ring settings but the ring settings used bound these settings. Six steam tests with the Crosby 3K6 valve were run with ring settings of (-45, -14), (-55, -14) and (-95,

-14). These were tests 416, 425, 408, 411, 442, and 537. Five of these tests were run on the short (82 in.) inlet piping configuration which is more representative of the St. Lucie 1 configuration. One test (537) was run on the loop seal configuration, but without the loop seal water. All of these tests are applicable to the St. Lucie 1 valves; they all had stable operation, opened at 2462 to 2508 psia (-1.5 to +.32% of nominal.set pressure), and 99-123% of rated flow was achieved at 3% accumulation. These tests had peak pressures from 2462 to 2730 psia and pressurization rates from 2.5 to 325 psi/s. The peak backpressure ranged from 140 to 705 psia.

These conditions bound those, expected at St. Lucie 1.

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. In Reference 17, FPL responded to a question on the Feedwater Line Break (FWLB) at St. Lucie 1. The question asked whether the FWLB was analyzed as part of the plant design basis because Reference 7 did not list it as a accident that challenged the safety valves at St. Lucie. 1. FPL stated that the FWLB was analyzed in Section 15.2.8 of the St. Lucie 1 FSAR, and that based on the assumptions used in the analysis the FWLB was a cooldown transient for the plant. FPL stated the plant response to a FWLB was bounded by the response to a Main Steam Line B~eak, and, therefore, the safety valves and PORVs would not be subject to liquid discharge during this transient. Also, the cutoff head for the St. Lucie 1 HPI pumps is below the safety valve setpoint so that an extended HPI event would not challenge the safety valves.

There was a concern thai. the extended safety valve blowdown (blowdown greater than 5%) observed during the EPRI tests could result in the pressurizer level increasing to the safety valve inlet. CE, in Reference 19, analyzed the loss-of-load (LOLD) transient assuming 20%

blowdown. Other conservative assumptions were also made to maximize pressurizer level swell. The LOLD was chosen because it provided the design basis for sizing pressurizer safety valves. The 20% blowdown is conservative since the blowdown observed in the applicable EPRI tests ranged from 8. 1 to 15.7%%d. This analysis showed the pressurizer level did not reach the inlet to the safety valves. Thus, the steam inlet condition was maintained.

The two Dresser PORVs at St. Lucie 1 do not have loop seals. The peak pressure and pressurization rate for the PORVs during FSAR type transients are given in Reference 7 and are, 2562 psia and 60 psi/s, respectively. The maximum backpressure for the PORVs is 362 psia (Reference 15).

The test PORV was subjected to fifteen steam tests (Reference 20). In the steam tests, the opening pressure ranged from 2415 psia to 2507 psia.

Backpressures ranged from 170 psia to 760 psia. The testing of the Dresser PORV was performed at opening pressures above the set pressure for St.

Lucie 1 during an FSAR transient (2415 to 2507 psia versus 2400 psia) and almost as high as the peak predicted pressure of 2562 psia (Reference 7).

Reference 6 stated that the valve inlet pressure is considered to have a potential for affecting PORV operation only during opening or closing.

Since the Dresser valve opens quickly (less than 0.5 seconds), the pressure increase during the valve opening cycle is minimal (approximately 30 psia increase based on the maximum pressurization rate of 60 psi/s). Testing at the nominal set pressure for CE plants (2400 psia) or slightly above is, therefore, considered adequate and the test conditions 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 St. Lucie 1 HPI pumps is below the PORV setpoint so that an extended HPI event would not challenge the PORVs.

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The PORVs are used for low temperature overpr essure protection (LTOP) at St. Lucie 1. The CE inlet conditions report, Reference 7, includes a plant-specific analysis of LTOP for St. Lucie 1. For low temperature overpressure protection, the valve inlet conditions include steam, steam to water transition, and liquid at pressures from 465 to 800 psia with temperatures ranging from 100 F to 417 F. The peak pressures noted above are based on analyses that assumed the pressurizer was liquid full.

The presence of a steam bubble in the pressurizer, which is the recommended mode. of operation during low temperature operation, would limit the peak pressure when the PORV opened on steam, but this condition was not specifically analyzed. Thus, peak pressure during steam discharge was bounded using the liquid full analyses. The steam discharge conditions are considered to be adequately represented by the high pressure tests discussed above. Steam to water transition is also considered to be adequately represented by the high pressure transition test, 21-DR-85/W. Water discharge during a LTOP transient is represented by the low pressure

(-690 psia) water tests with fluid temperatures ranging from 112oF to 459oF.

Verification of the block valves operability was shown by EPRI testing representative Velan valves in their test program (Reference 9). These tests verified that the test block valves could be opened with full 2500 psig pressure on these valves and closed with full flow and pressure through the valves. These conditions are representative of the plant conditions expected during actual valve operation (Reference 12).

However, as noted in Section 4.1, it could not be determined whether the plant block valve operator was set to produce a torque greater than the minimum torque tested by EPRI. Therefore, although the EPRI test conditions bound those for the plant block valves, the test results are not applicable to the St. Lucie 1 block valve/operator combination.

The test sequences and analyses described above, demonstrating that the test conditions bounded the conditions for the plant valves, verify that Items 2 and 4 of Section 1.2 were met, in that conditions for the operational occurrences were determined and the highest predicted pressures 11

were chosen for the test. The part of Item 7, which requires showing that the test conditions are equivalent to conditions prescribed in the FSAR, was also met.

4.3 Valve 0 erabilit As discussed in the previous section, the Crosby 3K6 safety valves at St. Lucie 1 are required to operate with steam inlet conditions only. The EPRI test program tested the Crosby 3K6 valve for the required range of conditions. During FSAR transients the PORVs are required to only pass steam. The PORVs are used for LTOP and in this mode may be required to pass steam, steam to water transition, and water. The test valve was subjected to the required conditions. The block valves are also required to operate for steam and liquid flow conditions.

For the applicable safety valve tests (416, 425, 408, 411, 442, and 537) with (-45, -14) (-55, -14) and (-95, -14) ring settings, the test valve opened at pressures from 2462 to 2508 psia (-1.5% to +.32% of th'e nominal'et pressure), had stable behavior, and closed with 8.1% to 15.7% blowdown.

In these tests the valve passed from 99% to 123% of rated flow at 3X accumulation. The St. Lucie 1 safety valve maximum pressure of 2562 psia and maximum backpressure of 362 psia are bounded by the peak pressure and backpressure in these tests (2462 to 2730 psia and 140 to 705 psia, respectively). This indicates the valve was able to perform its safety function of opening, relieving pressure, and closing with these three, ring settings (-45, -14) (-55, -14) and (-95, -14).

A maximum bending moment of 133,000 in-lb was applied to the Crosby 3K6 safety valve discharge flange without impairing valve operation. This bounds the maximum expected bending moment of 64,068 in-lb at the plant (Reference 15).

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 measured stagnatiM pressure drop for the reference test (8411) was 12

211 psid. The plant specific stagnation pressure drop was calculated to be 106 psia indicating the plant valves should be as stable as the test valves (Reference 15).

As noted above, the valve blowdown for the Crosby 3K6 safety. valve 0

during the applicable tests ranged from 8.1 to 15.7%. A CE analysis for a St. Lucie 1 LOLD with 20% blowdown showed that the pressurizer level would not reach the safety valve inlet. This bounds the blowdown observed in the tests. Also, the hot leg remained subcooled during the LOLD analysis with the extended blowdown, indicating adequate core cooling was maintained.

Since the ring settings used with the St. Lucie 1 safety valves were bounded by the EPRI tests they are deemed acceptable. The test valve flow rate was 99 to 123% of its rated value. This indicates the valves at St.

Lucie 1 will provide adequate overpressure protection.

Based on the test results discussed above, demonstration of safety valve operability is considered adequate.

The Dresser PORV opened and closed on demand for all applicable tests.

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 and the manufacturer concluded the failure did not have a poten'tial impact on valve performance. The bellows was replaced and did not fail during any of the additional test series.

The results of tests done by Dresser Industries on a PORV similar to the ones at St. Lucie 1 were provided as part of the Calvert Cliffs, Units 1 and 2 submittal (Reference 21). This data showed the PORV opened and closed on saturated steam without failure at pressures ranging from 65 psia to 1979 psia. There was no apparent leakage after closing in any of these tests. During other tests the minimum pressure achieved without leakage was 90 psia. This test data indicates the valve will operate acceptably with low pressure steam conditions.

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A bending moment of 25,500 in-lb was induced on the discharge flange of the test valve without impairing operability. The maximum bending moment calculated for the St. Lucie 1 PORVs is 25,848 in-lb'he EPRI tests, therefore, are representative of the expected plant condition.

The St. Lucie 1 PORVs are pilot operated valves that use system pressure to hold the disk tight against the seat. At one point Dresser Industries recommended 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 showed the 1000 psig pressure limit to be overly conservative and that the PORV as designed was qualified to a system pressure of 100 psig. 'elow 100 psig the deadweight of the lever on the pilot valve could cause the pilot valve to open or to remain open. Accordingly, the main valve may also partially open. However, FPL stated in Reference 15 that even with the existing springs, if the inlet pressure increases rapidly to above 100 psig, the pilot and main valves should properly load and seal without leakage. From cold start, there may be some cyclic type. leakage until the valve becomes thermally stable. Therefore, FPL has not changed the PORV springs and does not plan to do so.

Based on the valve performance during EPRI tests, unde~ the full range of expected inlet conditions, the demonstration of PORVs operability is considered adequate.

The EPRI tests of representative Velan block valves and operators under typical plant conditions demonstrated the block valve operability (Reference 9). The torque setting for the Limitorque SB-00-15 operator was 1.7 for all regular tests; supplementary cycles with 1.5, 1.25, and 1.0 settings were also done. All cycles produced fully open and closed valve positions, but slight valve leakage was detected for the 1.0 (82 ft-lb) torque setting. The torque setting for the Limitorque SMB-000-10 operator was 1.5 for all regular tests; one more test was run with a 1.0 (82 ft-lb) torque setting. Slight leakage was detected for the 1.0 torque setting, but the valve fully cycled. All tests on both valves produced full open and closed positions of tlie valve with slight leakage occurring only with the lowest operator torque settings.

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The results of these tests indicate satisfactory block valve performance for the plant valves provided the plant block valve operator is set to produce a torque greater than the minimum torque used in the EPRI tests. Another approach acceptable to the staff is to perform in-situ testing of the plant specific operator/block valve combination. :FPL took the first approach and, in Reference 17, responded to a question on the torque setting for the St. Lucie 1 block valve operators. The response by FPL stated the nominal setting of 1.25 produces a to~que of 47.5 ft-lb and the maximum setting of 2.75 produces a torque of 98 ft-lb. This response does not state clearly enough whether the torque produced by the plant operators with the current torque switch setting is greater than or equal to the minimum tested by EPRI, 82 ft-lb. Therefore, it cannot be concluded the St. Lucie 1 block valves will operate properly.

NUREG-0737, Item II.D.l, requires qualification of the associated control circuitry as part of the safety/relief valve qualification. FPL qualified the reactor building circuitj y under 10 CFR 50.49; this equipment included pressure sensors, PORV acoustic flow monitors, and electric cables and penetrations (Reference 15). All other electrical components for indication and control are located in mild environments. This meets the Item II.O. 1 requirements for qualification of the PORV control circuitry.

The presentation above, demonstrating that the safety valve, PORV, and PORV block valves tested operated satisfactorily, verifies that the portion of Item 1 of Section 1.2 that requires conducting tests to qualify the valves and that part of Item 7 requiring that the effect of discharge piping on operability be considered were met. However, the part of Item 7 that requires submitting evidence to substantiate that 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. This is because, based on the information provided by FPL,'t cannot be concluded the plant block valve operator s produce enough torque to close the valves.

gualifying the PORV control circuitry under 10 CFR 50.49 meets Item 5.

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4.4 Pi in and Su ort Evaluatioi'n the piping and support evaluation (References 13 and 15), the safety valve and PORV inlet and outlet piping from the pressurizer to the relief tank were analyzed (including supports) in the original design arjalysis.

The thermal-hydraulic analysis was redone using RELAP5/MOD1 (verified in Reference 22) and the loads determined using CALPLOTFIII. Loads from these analyses were then compared with the original design loads to assure adequacy of the design. The codes used to evaluate the piping and supports were the USAS B31.7 Code (1969) for Class 1 piping and supports and the ANSI B31.1 Code (1973) for non-safety related piping and supports.

Three saturated steam discharge transients were analyzed. In the first case, the two PORVs opened and the three safety valves remained closed. The second case had the PORVs remain closed and the thr ee safety valves open simultaneously. In the third case, the two PORVs opened, the pressure continued to rise, and the three safety valves opened simultaneously.

In Reference 18, FPL provided the results of a thermal-hydraulic analysis that considered water through the PORV during a LTOP transient.

Because of questions on the LTOP transient analysis, there is a potential problem regarding the St. Lucie, Unit 1, discharge piping. However, analysis of the PORV discharge piping for LTOP conditions is not considered by the NRC staff to be in the scope of the Item II.D.1 review. Therefore, this issue will be reviewed separately, at a later time, and will not impact the NUREG-0737, Item II.D.1, review for St. Lucie 1.

The thermal-hydraulic analysis was performed with RELAP5/MOD1.

RELAP5/MOD1 was shown to be a suitable tool for performing the thermal-hydraulic analysis of valve discharge transients in Reference 22.

RELAP5 output is input to CALPLOTFIII for calculation of piping loads.

CALPLOTFIII was verified to accurately calculate these types of loads by comparing its results to hand calculated loads and to GE 4-inch pipe blowdown test results (Reference 15).

A RELAP5 model representing the piping from the pressurizer to the quench tank was assembled and is shown in Figure 2 of Reference 15. Node 16

sizes in the safety valve discharge piping model for the components immediately downstream of the safety valves ranged from 0.58 to 1.375 ft.

These node sizes are considered adequate. Information on the node sizes for the other components in the safety valve discharge piping model was not given. The node sizes in the PORV discharge piping model immediately downstream of the PORVs, however, ranged from 0.46 to 6.49 ft. FPL stated that it considered these node sizes adequate, even though they were bigger than those recommended in Reference 22, because of the slower opening time of the PORV (0.11 s versus 0.006 s for the safety valves). This statement was not supported by any analysis results and, thus, is not considered adequate justification for FPL's position. Information on the node sizes for the other components in PORV discharge piping model was not given. The maximum time step used in the analysis was 2 x 10 4, which is adequate.

The safety valves wer e assumed to open in 6 ms and the PORVs in 110 ms. The safety valve and PORV opening times were based on the minimum pop time measured in the EPRI tests. The flow rates for the safety valves and PORVs were based on EPRI test data. The safety valve flow rate used was 122%%d of the rated value. The safety valve rated flow rate is 213,000 ibm/h. The PORV flow in the analysis ranged from 153,000 to 190,800 ibm/h.

Based on the information provided by FPL, the adequacy of the thermal-hydraulic analysis could not be determined. Sufficient information on the node sizes in the piping model was not given. Also, the node size information FPL did provide for the PORV piping model indicated the node size used was too large to ensure conservative piping forces were calculated.

The only structural analysis performed was the earlier design analysis. Current analysis loads were compared with the loads used in the earlier analysis to assure structural adequacy was still predicted. In Reference 15, FPL stated the load combinations used in the earlier design stress analysis are consistent with the Standard Review Plan, Section 3.9.3, Rev. 1. The load combinations included the operating basis earthquake combined with the maximum values of safety valve and PORV loads and compared to Level B limits. The design basis earthquake was combined with the maximum values of safety valve and PORV loads and the stresses compared to Level C limits. The loading used in the design of the restraints was the 17

~ I combination of the worst thermal, deadweight, seismic ana "afety valve/PORV discharge loads. The restraint design considered this combination and normal allowable stress values (Reference 15). These load combinations are acceptable and meet the criteria presented in Reference 23.

The earlier analysis was preformed using the Impell computer program EDSGAP. According to Reference 18, EDSGAP was verified using a comprehensive set of sample problems in accordance with Impell Corp. quality assurance procedures. Maximum and minimum mass point spacings in the structural model ranged from 2.25 inches for 2-1/2 inch Sch. 160 piping to 73,5 inches for 10 inch Sch. 20 piping. A sufficient number of modes were included in the analysis to ensure that both the fundamental structural and the relatively high frequency longitudinal responses of the piping would be accurately r.epresented. A time step of 0.00141 s was used. The analysis was made using a direct integration time history technique. As such a maximum cutoff frequency is not specified. However, FPL compared the EDSGAP model to the model used in the seismic .analysis and concluded that, because the detail in the two models was similar and the seismic analysis showed that frequencies up,to 100 Hz were included, the EDSGAP model had sufficient detail to analyze dynamic,.loadings up to 100 Hz. Damping of 1/2% was used in the earlier structural analysis. These parameters are considered acceptable.

However, from the information provided by FPL, it is not possible to conclude the St. Lucie 1 piping and supports meet applicable code allowables. First, question 4a of Reference 16 requested FPL to provide a table comparing the calculated piping and support stresses and loads with the code allowables for the most highly loaded locations. FPL's response did not provide the requested comparison. FPL only stated that the allowable stresses were compared to the predicted pipe stresses and support loads. Also, question 3 of Reference 16 requested FPL to compare content of the forcing functions based on the current RELAP5/MOD1 the'requency analysis and those used in the earlier design analysis. FPL stated this comparison was not possible because the design analysis calculated the loads e

based on a modal analysis technique and the RELAP5/MOD1 analysis calculated the loads at each pipe segment. This statement seems to be comparing a structural analysis, where a modal analysis is a common analysis technique, 18

to a thermal-hydraulic analysis. The structural analysis, even if it used a modal analysis technique, would require as input the forcing functions from a thermal-hydraulic analysis. It is the comparison of the frequency content of the forcing functions from the earlier thermal-hydraulic analysis and the frequency of the forcing functions based on RELAP5/MOD1 that was n equested.

Even if the thermal-hydraulic model for the earlier design analysis and the RELAP5/MOD1 model are different, it should still be possible to appropriately combine the forcing functions in one model or the other to compare the frequency content of the two force-time histories. This comparison was not provided by FPL. Therefore, it cannot be concluded that comparison of the new loads to the design loads is sufficient to ensure the piping system meets code allowables for the new loads.

The analysis discussed above demonstrated that a bounding case was chosen for the piping configuration. Therefore, Item 3 of Section 1.2 was met, However, the analysis discussed above for the piping and support system has not verified Item 8 was met.

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5. EVALUATION

SUMMARY

The Licensee for St. Lucie 1 has not provided an acceptable response to the requirements of NUREG-0737. Therefore, it has not been reconfirmed that the General Design Criteria 14, 15, and 30 of Appendix A to 10 CFR 50 were met. The rationale for this conclusion is given below.

5. 1 NUREG-0737 Items Full Resolved Based on the following information provided by the Licensee, the requirements of Item II.D.1 of NUREG-0737 were partially met ( Items 1 to 6 and part of Item 7 in Section 1.2).

The Licensee participated in the development and execution of an acceptable Relief and Safety Valve Test Program designed to qualify the operability of prototypical valves and to demonstrate that their operation would not invalidate the integrity of the associated equipment and piping.

The subsequent tests were successfully completed under inlet conditions which by analysis bounded the most probable maximum forces expected from anticipated design basis events. The generic test results and piping analyses showed that the valves tested functioned correctly and safely for all relevant steam discharge events specified in the test program and that the pressure boundary component design criteria were not exceeded. Analysis and review of the test results and the Licensee's justifications indicated direct applicability of the prototypical valve and valve performances, except as discussed in Section 5.2 with respect to the PORV block valves, to the in-plant valves and systems intended to be covered by the generic test program.

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

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,5.2 NUREG-0737 Items Not Resolved Based on the Licensee's submittal, the following requirements of NUREG-0737, Item II.D. 1, as shown in Section 1.2, were not met.

Item 7: The part of Item 7, which requires submitting evidence to substantiate that 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. This is because the information provided by FPL on the torque output of the plant block valve operators was not sufficient to show whether the torque produced by the plant operators is greater than or equal to the minimum tested by EPRI, 82 ft-lb. Therefor e, it cannot be concluded the St. Lucie 1 block valves will operate properly.

Item 8: Item 8, which requires qualification of the piping and supports, was not met. This is because sufficient information on the node sizes in the piping model (other than iaeediately downstream of the valves) was not given and the node sizes shown for the PORV piping immediately downstream of the valves were too large to ensure conservative forces were calculated. FPL'id not provide a requested table comparing the calculated piping and support stresses and loads with the code allowables for the most highly loaded locations. Also, FPL did not compare the frequency content of the forcing functions based on the current RELAP5/MOD1 analysis and those used in the earlier design analysis as requested. Therefore, it cannot be concluded that comparison of the new loads to the design loads is sufficient to ensure the piping system meets code allowables for the new loads.

Therefore, the Licensee has not demonstrated by testing and analysis that the reactor primary coolant pressure boundary will have a low 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) were designed with sufficient margin such that design conditions are not exceeded during relief/safety valve events (General Design Criterion No. 15).

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6. REFERENCES TMI-Lessons Learned Task Force Status Re ort and Short-Term Recommendations, NUREG-0578, July 1979.

Clarification of TMI Action Plan Re uirements, NUREG-0737, November 1980.

R. C. Youngdahl ltr. to H. D. Denton, Submittal of PWR Valve Test Report, EPRI NP-2628-SR, December 1982.

EPRI Plan for Performance Testin of PWR Safet and Relief Valves, July 1980.

EPRI PWR Safet and Relief Valve Test Pro ram Valve Selection/Justification Re ort, EPRI NP-2292, December 1982.

EPRI PWR Safet and Relief Valve Test Pro ram Test Condition Justification Re ort, EPRI NP"2460, December 1982.

Valve Inlet Fluid Conditions for Pressurizer Safet and Relief Valves in Combustion En ineerin -Desi n Plants, EPRI NP-2318, December 1982.

EPRI PWR Safet and Relief Valve Test Pro ram Safet and Relief Valve EPRI/Marshall Electric Motor 0 crated Block Valve, EPRI NP-2514-LD, July 1982.

Letter R. E. Uhrig, Florida Power and Light Co., to D. G. Eisenhut, NRC, "St. Lucie Unit 1, Docket No. 50-335, Post-TMI Requirements, NUREG-0737, Item II.D.1, PWR Relief and Safet Valve Testin ",

L-82-126, April 1, 1982.

Letter R. E. Uhrig, Florida Power and Light Co., to D. G. Eisenhut, NRC, "St. Lucie Unit 1, Docket No. 50-335, Post-TMI Requirements, NUREG-0737, Item II.D.1, PWR Relief and Safet Valve Testin ",

L-82-277, July 9, 1982.

Letter R. E. Uhr ig, Florida Power and Light Co., to D. G. Eisenhut, NRC, "St. Lucie Unit 1, Docket No. 50-335, Post-TMI Requirements, NUREG-0737, Item II.D.l, PWR Relief and Safet Valve Testin ",

L-82-353, August 13, 1982.

Letter R. E. Uhrig, Florida Power and Light Co., to D. G. Eisenhut, NRC, "St. Lucie Unit 1, Docket No. 50-335, Post-TMI Requirements, PWR Relief and Safet Valve Testin ", L-82-564, December 30, 1982.

Letter E. J. Butcher, NRC, to J. W. Williams of Florida Power and Light Co., "Request for Additional Information re Response to TMI Action Item II.D.l 'Relief and Safety Valves Test Requirements,'"

June 21, 1985.

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15. Letter C. 0. Woody, Florida Power and Light Co., to A. C. Thadani, NRC, "St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389, Relief and Safet Valve Test Re uirements," L-86-114, March 18, 1986.

16. Letter E. G. Tourigny, NRC, to C. 0. Woody, Florida Power and Light Co., "Request for Additional Information re Response to TMI Action Item II.D. 1, Relief and Safety Valves Test Requirements,"

June 10, 1987.

17. Letter C. 0. Woody, Florida Power and Light Co., to USNRC Document Control Desk, "St. Lucie Unit Nos. 1 and 2, Docket Nos. 50-335 and 50-389, TMI Action Item II.D.1, Re uest for Addition Information,"

L-87-446, November 6, 1987.

18. Letter C. 0. Woody, Florida Power and Light Co., to USNRC Document Control Desk, "St. Lucie Units. 1 and 2, Docket Nos. 50-335 and 50-389, TMI Action Item II.D.1, Re uest for Addition Information," L-88-59, February 5, 1988 ort erabilit of Pressurizer

'9.

Summar Re on the 0 Safet Valves in CE

20. Summar Re ort on the 0 erabilit of Power 0 crated Relief Valves in CE

21. Letter R. S. Huffman, Dresser Inc., to R. J. Quinn, BGSE, "Baltimore Gas and Electr'ic Co., Calvert Cliffs Units 1 and 2, Power Operated Relief Valves CE P09903304 and P09903305," August 12, 1985.

22. A lication of RELAP5/M001 for Calculation of Safet and Relief Valve Dischar e Pi in H dred namic Loads, EPRI-2479, December 1982.

23. EPRI PWR Safet and Relief Valve Test Pro ram Guide for A lication of Valve Test Pro ram Results to Plant-S ecific Evaluations, Rev. 2, Interim Report, July 1982.

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