ML20054L667

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PWR Safety & Relief Valve Adequacy Rept for Surry Units 1 & 2
ML20054L667
Person / Time
Site: Surry, 05000000
Issue date: 06/30/1982
From:
WESTINGHOUSE ELECTRIC COMPANY, DIV OF CBS CORP.
To:
Shared Package
ML18139B924 List:
References
RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM 0605E:1, 605E:1, NUDOCS 8207080346
Download: ML20054L667 (31)
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i PWR SAFETY AND RELIEF VALVE ADEQUACY RPORT FOR VIRGINIA ELECTRIC POWER COMPANY I

SURRY UNIT 1 AND UNIT 2 i

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JUNE 1982 3 _

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1.0 INTR 00VOTION In accordance with the initial recommendation of NUREG 0578, Section ,

2.1.2 as later clarified by HUREG 0737, item I1.0.1 and revised September 29, 1981, each Pressurizer Water Reactor (PWR) Utility on or before July 1,1982, was to submit information relative to the pressurizer safety and relief valves in use at their plant. Specifically, this submittal should include an evaluation supported by test results which demonstrate the capability of the relief and safety valves to operate under expected operating and accident conditions.

The primary objective of the Electric Power Research Institute (EPRI) test program was to provide full scale test data confirming the functionability of the primary system power operated relief valves and safety valves for expected operating and accident conditiors. The second ,

objective of the program was to obtain sufficient piping thermal hydraulic load data to permit confirmation of models which may be utilized for plant specific analysis of safety and relief valve discharge piping systems. Relief valve tests were completed in August 1981 and safety valve tests were completed in January 1982. Reports have been prepared by EPRI which document the results of the test program.

Additional reports were written to provide necessary justification for test valve selection and valve inlet fluid test conditions. These reports were transmitted to the USNRC by David Hoffman of the Consumers Power Company on behalf of the participating PWR Utilities and are referenced herein.

This report provides the final evaluation of these and other submittals and reports prepared during the review of the test data as they apply to the valves used at Surry Units 1 and Unit 2. ,

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r-2.0 VALVE AND PIPING PARAMETERS Table 2-1 provides a list of pertinent valve and piping parameters for the Surry Unit 1 and Unit 2 Safety and Power-0perated Relief Valves. The valve designs installed at Surry were not specifically tested by EPRI; however, valves of a simialar design and operation were tested in a configuration similar to that of the actual system configuration at the plant. Justification that the valves tested envelope those valves at Surry is provided in the Valve Justification report.(1) The justification was developed based on evaluation performed by the valve manufacturers and considered effects of differences in operating characteristics, materials, orifice si72s and manufacturing processes on valve operability.

Typical inlet piping configurations for Surry Unit 1 and Unit 2 are provided in Figures 2.1-2.2.

Tables 2-2 and 2-3 compare the Surry inlet loop seal piping configuration with that of the EPRI test piping arrangement for the Crosby 3K6 and 6M6 Safety Valves and compares the actual plant-specific pressure drop with the test pressure drop for the two (2) test valve arrangements.

As can be seen by these comparisons, the EPRI test piping arrangement.

envelops the actual piping arrangement for the Surry units.

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TABLE 2-1 VALVE AND PIPING INFORMATION

1. SAFETY VALVE INFORMATION Number of valves 3 1

Manufacturer Crosby Valve and Gage Type Self Actuated Size 6K26 Steam Flow Capacity, Ibs/hr 293,330 (ASME Rated)

Design Pressure, psig 2485 Design Temperature, F 650 Set Pressure, psig 2485 Accumulation 3 percent of set pressure Blowdown 5 percent of set pressure Original Valve Procurement Spec. E-676279

2. RELIEF VALVE INFORMATION i

Number of Valves 2 Manufacturer Copes-Vulca n Type Pressurizer Power Relief Size 2"W 3" inlet, outlet Steamflow Capacity,1bs/hr 179,000 210,000 Nom Max Design Pressure, psi 1500 (ANSI)

Design Temperature, F 680 Opening Pressure, psig 2335 t Closing Pressure, psig 400 lbs and 415 lbs (When OP mitigation (1456) (1456c) system i is in service).

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TABLE 2.1 Continued . . .

3. SAFETY AND RELIEF VALVE INLET PIPING INFORMATION Design Pressure, psig 2485 Dasign Temperature OF , 680 Configuration of Piping See 12846.22 MKS 124A1 and 2 ,

Pressurizer Nozzle Configuration 12846.22-MKS-124A1 and 2, Loop Seal Volume, f t Volume - 0.92 Loop Seal Temperature, OF Temp. 650 > T > 110 (approximately 200 F)

Steady State Flow .

Pressure Drop See Appendix 1 Acoustic Wave Pressure ,

Amplitude See Appendix 1 1

4. SAFETY AND RELIEF VALVE DISCHARGE PIPING INFORMATION E

Design Pressure, psig 650 Design Temperature,0F 600 Configuration 12846.22-MKS-124A1 and 2.

Pressurizer Relief Tank Design Pressure, psig 100 Backpressure, Normal, psig 3 Backpressure, Developed, psig 500  !

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TABLE 2-2 SAFETY VALVE INLET PIPING COMPARISON Typical Surry 3K6 Inlet 6M6 Inlet Inlet Piping Piping

  • Piping
  • Length of 110 60 61 straight pipe, in.

Number of 900 4 4 elbows Number of 180 0 - -

2 bends Misc. -

78" 71" Loop seal water .92 0.27 1.02 Volume, Ft3

  • Source: Reference (7)
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TABLE 2-3 COMPARIS0N OF TEST PRESSURE DROP WITH PLANT SPECIFIC PRESSURE DROP Plant Specific

  • 6M6 Test ** 3K6 Test **

Pressure Drop Pressure Drop Pressure Drop Surry 1 170.9 psi 251 psi 321 psi Surry 2 171 psi

  • Appendix I -
    • Source: Reference (8) 060SE:1 A

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3.0 VALVE INLET FLUID CONDITIONS Justification for inlet fluid conditions use'd in the EPRI Safety and Relief Valve tests are summarized in References 2 and 3. These conditions were determined based on consideration of FSAR, extended High Pressure Injection, and Cold Overpressurization events, where applicable.

For plants of which Westinghouse is the NSSS supplier, a methodology was used such that a reference plant was selected for each grouping of plant considered.(3) Valve fluid conditions resulting from limiting FSAR events, which result in steam discharge and an Extended High Pressure Injection event which may result in liquid discharge, are presented for each reference plant. Use of reference plants results in fluid conditions enveloping those expected for Surry Unit 1 and Unit 2.

Table 3-1 presents the results of loss of load and locked rotor analysis for three loop plants in which Surry Unit 1 and Unit 2 were included. .

The inlet fluid conditions expected at the safety valve and PORV inlets are identified. As can be seen, the Locked Rotor event is considered as the limiting overpressure transient for three loop plants. Fluid inlet conditions for cold overpressure protection are provided in Taole 3-2.

Cold overpressure is not a design basis for the safety valves but is for the PORVs.

The only transients identified and analyzed to date for Surry are the FASR and cold overpressure transients. No conditions have been established addressing Extended High Pressure Injection Transients.

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TABLE 3-1 VALVE INLET CONDITIONS FOR FSAR EVENTS RESULTING IN STEAM DISCHARGE Maximum Maximum Valve Pressurizer Pressure Rate Reference Opening Pressure (psia)/ (psia /sec)/

Plant Pressure (psia) Limiting Event Limiting Event Safety Valves Only 3-Loop 2500 2592/ Locked Rotor 216/ Locked Rotor ,

i Safety and Relief Valves -

, 3-Loop 2350 2555/ Locked Rotor 200/ Locked Rotor

'l Source: Reference (2) t t

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l TABLE 3-2 PORV INLET CONDITIONS FOR COLO OVERPRESSURE PROTECTION RESULTING IN WATER DISCHARGE Reactor Coolant Temperature ,

l Pressurizer, psig Range, *F i

1 435 100-350 il j

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4.0 COMPARISON OF EPRI TEST DATA WITH PLANT-SPECIFIC REQUIREMENTS The Electric Power and Research Institute (EPRI) conducted full scale flow tests on pressurizer safety and relief valves.( } Tests were conducted at three sites over a period of 1-1/2 years. PORVs were tested at Marshall Steam Station (5) and Wyle Laboratories,(6,7) while safety valves were tested at the Combustion Engineering Test Site in Connecticut.(7) 4.1 Relief Valve Testing Test results applicable to the PORVs installed in Surry Unit 1 and Unit 2 are contained in Section 4.7 of Reference 7, Copes-Vulcan Relief Valve (17-4PH Plug and Cage).

This valve fully opened and closed on demand for each of the eleven evaluation tests at the Marshall Test Facility. Eight additional tests were conducted at the Wyle Test Cacilitiy; during all of these tests the valve fully opened and closed on demand. Subsequent disassembly and inspection revealed the cage to body gasket had partially washed out during the testing. No damage was observed that would affect future valve performance.

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TABLE 4-1 COMPARISON OF PORV INLET FLUID CONDITIONS WITH "AS-TESTED" CONDITIONS Steam Conditions PORV Wyle Test

' Inlet Fluid 63-CV Marshall Test Conditions 174-15 (No.1 - No.11)

Set Point 2350 2477 (2430-2505)

Pressure (psia) -

Temperature 650 670 (sat.)

(OF)

Fluid Type steam steam steam Flow Rate 210,000 255,600 (221,000-220,000)

(lbs/hr)

Water Conditions PORV Wyle Test Wyle Test Inlet Fluid 63-CV 67-CV Conditions 174-1S 174-5W Set Point 435 -

675 675 Pressure (psia)

Temperature 100-350 442 106 (OF)

Fluid Type Water Water Water Flow Rate -

399,600 630,000 (1bs/hr) 0605E:1 i

- - - ~ _ _ . - . .. -. _ _ _ - _ -- - .

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TABLE 4-2 TABULATION OF OPENING / CLOSING l TIMES FOR PORV Opening Time Closing Time l Test (Sec.) (Sec.)

Marshall 1 1.600 1.950 2 1.300 2.000 i

3 1.100 2.100 4 1.300 2.000 5 1.400 2.000 6 1.400 1.700 7 1.300 - 1.700 8 1.300 1.655 9 1.400 1.700 10 1.400 1.600 l 11 1.500 1.700 Wyle 63-CV-174-1S 0.57 1.34 64-CV-174-2S 0.49 1.34 65-CV-174-4W 0.57 1.15 66-CV-174-3W 0.97 0.54 6 7-CV-174-5W 0.90 0.61 68-CV-174-6W 0.66 1.29 69-CV-174-7W/W 0.52 1.27 70-CV-174-8W/W 0.50 1.35 Note: Required Opening Time - 2.0 Sec. ,

Required Closing Time - 2.0 Sec.

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A comparison of th'e "As-Tested" inlet fluid conditions for the Marshall and Wyle tests is provided in Table 4-1. This table indicates the Surry Unit 1 and Unit 2 fluid conditions summarized in Section 3.0 of this report were tested. The results of this testing indicates the valves functioned satisfactorily, opening and closing in the required time and discharging the required flow rate.

4.2 Safety Valve Testing Test results applicable to the safety valves installed at Surry Unit 1 and Unit 2 are contained in Section 3.4 and 3.5 of Reference 7. Although the Crosby 6K26 safety valves used in Surry Unit 1 and Unit 2 was not specifically tested by EPRI, justification for extension of the EPRI test results to this valve was provided by the valve vendor.(1) l l 4.2.1 Crosby 3K6 Safety Valve Tests _

The Crosby 3K6 test valve underwent a series of tests at the EPRI/CE Test l

Facility. The "As-Tested" fluid inlet conditions for the 3K6 test vale are compared to the Surry Unit 1 and Unit 2 fluid inlet conditions in Table 4-3 of this report. This comparison shows the EPRI "As-Tested" fluid conditions envelope those for Surry.

The Crosby 3K6 test valve was tested using various inlet piping configurations and with the loop seal filled and drained. Results of tests conducted on the long inlet piping configuration with loop seal internals installed are summarized herein.

Seven (7) tests were performed with the 3K6 valve mounted on a long inlet piping configuration and with loop seal internals installed. Ring settings used during these tests were established during earlier tests on this valve (with steam internals installed). Steam tests were conducted both with the loop seal drained and filled. For the test with a drained loop seal the valve opened within the EPRI criteria and had stable 0605E:1

1 behavior. When the pressure accumulated to 6 percent above set pressure, rated lif t was achieved. Valve blowdown was reported to be 15.7 to >

20 percent for these tests.

Four loop seal-steam tests were run at ramp rates of 3-220 psi /sec.

Initial valve lif t was reported at pressures from 2356-2630 psi. The valve fluttered at partial lift positions while discharging the loop seal water and then popped open at steam pressures from 2555-2707 psi. This behavior is typical of loop seal safety valve performance. Valve behavior was reported to be stable on steam and the valve achieved rated i lift when the pressure was 6 percent above the valve design set pressure. The valve closed with 17-20 percent blowdown.

Although not a fluid inlet condition for Surry, the test valve was subjected to a steam to water transition test. The valve was observed to undergo a typical loop seal discharge at partial lift, popped open on steam viktin +3 percent criteria, was stable on steam flow, and began to flutter and subsequently chatter during the water flow portion of the test.

4.2.2 Crosby 6M6 Safety Valve Tests The Crosby 6M6 test valve underwent a series of tests at the EPRI/CE Test Facility. The "As Tested" Fluid Inlet Conditions for the 6M6 are compared to the Surry Unit 1 and Unit 2 Fluid inlet conditions in Table 4-3.

This comparison shows the EPRI "As Tested" Fluid Conditions envelope those for Surry.

Two groups of tests were conducted on the Crosby 6M6 (Loop Seal Internals) Test Valve, one group with "As Installed" ring settings and one group with " lowered" ring settings.

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For the "As-Installed" ring settings four loop-seal steam tests were conducted, all at pressurization rates far above that expected for the Surry units. Two tests were conducted with a cold loop seal, representative of the Surry Configuration, while the other two tests were conducted with 350 F loop seals.

For the four tests conducted, the test valve popped open on steam at pressures ranging from 2675-2757 psia following a typical loop seal (water) discharge and for the first actuation cycle, the valve stem stabilized and closed with 5.1-9.6 percent blowdown.

For the last test, the valve reopened and the test was terminated after the valve was, manually opened to stop chattering. This was a 350 0F loop seal test and is not representative of the Surry Unit 1 and Unit 2 l

inlet conditions. l l

Although not part of the Surry fluid inlet conditions, a transition test with 6500F water was successfully conducted. Subsequently a 550 F water test was tried with the test terminated when the valve started to chatter.

Seven additional loop seal tests were conducted with " lowered" ring settings as well as two additional transition tests. The results of those tests are detailed in Section 3.5 of Reference 7. Five cold loop seal steam tests were performed at ramp rates from 3-375 psi /sec. The valve exhibited typical loop seal openings with the full opening pressures varying from 2580-2732 psia depending on ramp rate. The valve closed in a range of 7.4 to 8.2 percent blowdown.

Two hot loop seal tests were conducted with full opening pressures of 2655-2692 psia after the typical loop seal opening, and closed with 8.2-9.0 percent blowdown. In the second test the valve reopened and chattered. Again this was a 350UF loop seal test at a high ramp rate and is not considered representative of the Surry Unit 1 and Unit 2 inlet conditions.

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4.2.3 Discussion of Observed Safety Valve Performance In addressing observed valve performance, one must differentiate between the valves and fluid conditions tested and the actual valves and actual fluid conditions for the specific plant. The EPRI inlet piping arrangement, flow and acoustic pressure drops, and inlet fluid conditions bound the same plant-specific parameters for the Surry units. Valve performance observed during the EPRI tests, therefore, reflects worst case performance as compared to results that would be observed had the testing been conducted using actual plant-specific piping arrangements and fluid conditions.

A review cf Table 4-3 shows both Crosby safety valves tested exhibited stable operation on a loop seal piping configuration at pressurization rates of 1.1-375 psilsec with initial opening pressures of 2455-2630 psi and pop pressures of 2455-2757 psi.

The EPRI data also indicates that steam flow rates in excess of rated '

flows are attainable. liowever, data also shows these flow rates are .

delayed some period of time following the assumed valve opening point resulting in the high pop pressures.

Safety valve perrormance observed in the EPRI tests is addressed in Reference 9 for Westinghouse Plants and the results and conclusions of this report can be extended to Surry Unit 1 and Unit 2.

4.2.3.1 Loop Seal Opening Response To assess the effect on reactor coolant system pressure due to valve opening response on loop seal discharge, a series of overpressure transients were run with various time delays inserted for the valve opening. Results of the analysis are presented in Reference 9. For the limiting Condition II events,-safety valve functioning is not required if the reactor trips on high pressurizer pressure. If the reactor does not trip until the second protection grade trip, a valve opening delay time J

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of two seconds would still provide acceptable overpressure protection.

Evaluation of the limiting condition IV event shows all components of the reactor coolant system would remain within 120 percent of the system design pressure even in the event of no safety valve opening.

4.2.3.2 Inlet Piping Pressure Oscillations As observed during the loop seal discharge tests, oscillations occur upstream of a spring loaded Safety valve while water is flcwing through the valve. An analysis of this phenomenon was conducted and the results are documented in Reference 9. Table 4-4 provides the maximum permissible pressure for pressurizer Safety valve inlet piping sizes and schedules representative of Westinghouse plants. These pressures are shown for upset (level B) and emergency (level C) conditions. Based on tests and analytical work to date, all acoustic pressures observed or calculated prior to and during safety valve discharge are below the maximum permissible pressure.

4.2.3.3 Valve Chatter on Steam Since the EPRI testing was conducted at enveloping fluid and piping conditions, adjustments were made to. the safety valve ring positions in order to obtain stable valve performance on steam discharge for the test arrangement. These adjustments resulted in longer blowdowns for the test valves. The ring positions determined during the test represent the adjustment required for a particular valve when exposed to the particular test piping arrangement, fluid conditions, backpressure and pressurization rate.

An investigation was conducted to determine those parameters which are critical to the onset of valve chatter under steam discharge conditions.

The results of this study are detailed in Reference 9.

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TABLE 4-3 COMPARISON OF SAFETY VALVE INLET FLUID CONDITIONS WITH "AS-TESTE0" CONDITIONS Tests 6M6 Safety Valve No. '906-913, Inlet Fluid Tests 3K6 917-923, 925 1406, Conditions 525-532 and 536 1415 and 1419 Set Point 2350 2500 2500 Pressure (psia)

Temperature 650' 650 650 ,

(OF)

Fluid Type Steam loop seal / steam loop seal / steam Flow Rate 212,000 (1bs/hr)

Pressurization 200-216 3.4-200 1.1-375 Rate (psi /sec)

Stability Stable ** Stable **

Initial opening 2536-2630 2455-2600 Pressure (psia)

Pop Pressure, 2532-2707 2455-2757 (psia) l

  • Rated flow achieved but not reported in EPRI Tables, reference (7).
    • As reported by EPRI in Performance data tables of Reference (7).

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TABLE 4-4 MAXIMUM PERMISSIBLE PRESSURE FOR PRESSURIZER SAFETY VALVE INLET PIPING

  • Outside Diameter Nominal Permissible Pipe Size (in) _

Thickness (in) Pressure (psi)

Level B Level C 6-inch Sch. 160 6.625 0.719 5229 7131 6-inch Sch.120 6.625 0.562 4004 5460 4-inch Sch. 160 4.500 0.531 5733 7818 4-inch Sch.1,20 4.500 0.438 4644 6333  ;

3-inch Sch. 160 3.500 0.438 6119 8344 Source: Reference (9) t

  • Applicable for temperatures below 3000F. l

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5.0 CONCLUSION

S The preceeding sections of this report and the reports referenced herein indicate the valves, piping arrangements, and fluid inlet conditions for Surry Units 1 and Unit 2 are indeed bounded by those valves and test parameters of the EPRI Safety and Relief Valve Test Program. The EPRI

tests confirm the ability of the Safety and Relief Valves to open and close under the expected operating fluid conditions.

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INLET PIPING PRESSURE EFFECTS (8)

1. Inlet Piping Flow Pressure Orop (aPp) .

The flow pressure drop is given by, [

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(k+1 + fM M l 0

aP F= 2g "A [

c I

where, k - expansion or contraction loss coefficient (dimensionless) f = frictionfactor(dimensionless)

L = piping equivalent length / diameter considering effects of 0 fittings and friction (dimensionless)

M = maximum valve flowrate for steam (as established by the safety valve manufacturer) (lb/sec) 2 1 g

c

= gravitational constant (32.2 lb-f t/lb-sec )

3 o = steam density at nominal valve set pressure (ib/f t ) i A = inlet piping flow area (f t2)

2. Acoustic Wave Amplitude ( APgg)

The acoustic wave amplitude is calculated as follows. (8) There are two situations to consider:

- If Top < 2 L/a, aM aP AW " g A 0605E:1 m -_7 , - _ . __ ,

r If Top > 2L/a, 2LM AP AW " GAT g op where, a = steam sonic velocity at nominal valve set pressure (ft/sec)

L = inlet piping length (ft)

T gp

= valve opening time for steam inlet conditions as established from the EPRI testing effort is 10 msec for the Crosby safety valves and 15 msec for the Dresser safety valves. These valves are typical of the f3stest opening times measured during the tests.

The other variables are the same as defined in the previous section.

3. Plant-Specific Pressure Drop The plant-specific pressure drop associated with valve opening is equal to the sum of the friction pressure drop (aP F) and the acoustic wave amplitude (aPAW) as determined above.
4. Calculation of Inlet Piping Flow Pressure Drop for Surry 1 and 2 Surry la 2 (K + 1 + f h ) M tPF" 29c' ^2 0605E:1

where, k = 0.5 (sudden contraction at Pressurizer Nozzle) f = .015 (Reference 10)

L = 9.2_ + 4x30 = 141.3 (Reference 10)

D .432 p = 7.65 lb/ft3 ( satuated.. steam at 2500 psia) 2  ;

A = 0.147 f t M = 293,000 lb/hr = 81.4 lb/sec -2600 sec/hr The Flow Pressure Drcp for Surry 1 is, 2

3p , (0.5 + 1 + .015 x 141.3) x 81.4 - 15.6 psi 64.4 x 7.65 x .1472x144 ,

where, k = 0.5 (sudden contraction at Fressurizer Nozzle) f = .015 L = _10.3 + 4x30 = 143.8 0 .432 o = 7.65 lb/ft3 (saturated steam at 2500 psia)

A = 0.147 f t2 M = 233,000 lb/hr = 81.4 lb/sec 3600 sec/hr The Flow Pressure Drop for Surry 2 is, 2

(0.5 + 1 + .015 x 143.8) x 81.4 ) = 15.8 ps i

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64.4 x 7.65 x .1472 x 144 0605E:1

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5. 0 Acoustic Wave Amplitude -

Surry 1 For the configuration described in Table A-1, the Farameters are, T

op

= .010 sec.

2L 2 x 11.7 T

  • 1300 ft/sec = .018 sec Since T < ,

9p aM

^M*gAc 1300 x 81.4 A

M " 32.2 x .147 x 144 ao g = 155.3 psi Surry 2 For the Configuration desc. ibed in A-1, the Parameters are,

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T = .010 sec.

op 2

h=13g0t sc = .019 sec Since T gp < ,

s aM 1300 x 81.4 AP y=9Ac 32.2 x .147 x 144 APy = 155.3 psi 0605E:1 .

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6.0 PLANT-SPECIFIC PRESSURE DR0_P AP = APF + APAW Surry 1 aP = 15.6 + 155.3 aP = 170.9 psi Surry 2 aP = 15.8 + 155.3 aP = 171.1 psi 0605E:1 s

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,. r, TABLE A-1 Surry 1 Inlet Piping Configuration Total Pipe Length = 9.2 ft

- Pipe Diameter = 6" sch 160

- Fittings

= 4 - 90 elbows Total loop seal length = 11.7 ft

- Crosby 6K26 Safety Valve 233,000 lb/hr rated capacity

.010 sec opening time .

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Surry 2 Inlet Piping Configuration

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Total Pipe Length = 10.3 ft l - Pipe Diameter = 6" sch 160

- Fittings

= 4 - 90 0elbows l

Total loop seal length = 12.8 ft l

- Crosby 6K26 Safety Valve  ;

233,000 lb/hr rated capacity i,

.010 sec opening time 3

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REFERENCES

1. EPRI PWR Safety and Relief Test Program, Valve Selection /

Justification Report, " Interim Report, August 1981".

2. Westinghouse Electric Corporation Report, " Valve Inlet Fluid Conditions for Pressurizer Safety and Relief Valves in Westinghouse

- Design Plants (Phase C)", Interim Report, December 1981.

3. EPRI PWR Safety and Relief Valve Test Program, " Test Condition Justification Report", Interim Report, April 1982.
4. "EPRI PWR Safety and Relief Valve Test Program, Description and Status", April 1982.
5. "EPRI - Marshall Power-0perated Relief Valve Interim Test Data Report: EPRI N0-1244-2D, Interim Report, February 1982.
6. "EPRI/Wyle Power-0perated Relief Valve Test Report, Phase I and II",

EPRI NP-2147, LD, Interim Report, December 1981.

7. "EPRI PWR Safety and Relief Valve Test Program, Safety and Relief Valve Test Report", Interim Report, April 1982.
8. "EPRI PWR Safety and Relief Valve Test Program Guide for Application of Valve Test Program Results to Plant-Specific Evaluations",

Interim Report, March 1982.

9. " Review of Pressurizer Safety Valve Performance as Observed in the EPRI Safety and Relief Valve Test Program", June 1982.

10 . Crane Technical Paper No. 410, " Flow of Fluids Througn Valves, Fittings, and Pipe",.197'6.

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