ML18139B925

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PWR Safety & Relief Valve Adequacy Rept for North Anna Units 1 & 2
ML18139B925
Person / Time
Site: Surry, North Anna, 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 0607E:1, 607E:1, NUDOCS 8207080338
Download: ML18139B925 (62)
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Text

Prepared By:

PWR SAFETY AND RELIEF VALVE ADEQUACY.. REPORT FOR VIRGINIA ELECTRIC POWER COMPANY NORTH ANNA UNIT 1 AND UNIT 2 JUNE 1982 Westinghouse Electric Corporation Nuclear Energy Systems P.O. Box 355 Pittsburgh, PA 15230

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8207080338 020701 PDR ADOCK 05000280 p

PDR

1.0 INTRODUCTION

In accordance with the initial recommendation of NUREG 0578, Section 2.1.2 as later clarified by NUREG 0737, item II.D.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 re1ief 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 conditions. The second objective of the program was to obtain sufficient piping thermal hydraulic load data to permit confirmation of models which may 9e 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 North Anna Units 1 and Unit 2.

0607E:l

2.0 VALVE AND PIPING PARAMETERS

. i*

Table 2-1 provides a list* of pertinent valve and piping parameters for the North. Anna Unit 1 and Unit 2 Safety and Power-Operated Relief Valves. The safety valves installed at North Anna 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. The Masoneilan power-operated relief valves, however, were tested by EPRI.

Justification that the valves tested envelope those valves at North Anna is provided in the Valve Justification*report.(l) The justification was developed based on evaluation performed by the valve manuf.;.cturers and considered effects of differences in operating characteristics, materials, orifice sizes and manufacturi~g processes on valve operability.

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

Tables 2-2 and 2~3 compare the North Anna inlet loop seal p1p1ng configuration with that of the EPRI test piping arrangement for the Dresser Safety Valves and compares the actual plant-specific pressure drop with the test pressure drop for the test valve arrangements.

As can be seen by these comparisons, the EPRI test_piping arrangement envelopes the actual piping arrangement for the North Anna units

  • 0607E:l
1.
2.

TABLE 2-1 VALVE AND PIPING INFORMATION SAFETY VALVE INFORMATION Number of valves Manufacturer Type Size Steam Flow Capacity, lbs/hr Design Pressure, psig Design Temperature, OF Set Pressure, psig Accumulation B lowdown Original Valve Procurement Spec.

RELIEF VALVE INFORMATION Number of Valves Manufacturer Type Size Steamflow Capacity, lbs/hr Design Pressure, psi Design Temperature, °F Opening Pressure, psig Closing Pressure, psig 3

Dresser 6

11 31759A 3 x 6 388,670 2500 650 2485 3 percent of set pressure

.5 percent of set pressure E-676279 2

Masoneilan 20,000 series 2 inch 210,000 2485 "680 2335 2315 0607E: 1

.... /" : >'.........

TABLE 2.1 Continued ***

3.

SAFETY AND RELIEF VALVE INLET PIPING INFORMATION Design Pressure, psig

. 0 Design Temperature; F Configuration of Piping Pressurizer Nozzle Configuration Loop Seal Volume, ft3 Loop Seal Temperature, °F Steady State Flow Pressure Drop Acoustic Wave Pressure Drop 2485 680 Unit 1-11715-SSR-4. These are isometrics for fabrication and are not as-built. This information is prelim-inary in nature since an as-built iso-metric will be available for final

.analysis.

Unit 2 - 12050-MSK-llOA.

11715-SSR-4 Pgs 1-3 and 12050-MSK-llOA 1.07 Temp. 650 > T > 110 (approximately 200°F)

See Appendix 1 See Appendix 1

4.

SAFETY AND RELIEF VALVE DISCHARGE PIPING INFORMATION Design Pressure, psig Design Temperature, °F Configuration Pressurizer Re1ief Tank 650 600 12050-MSK-llOA

  • Design Pressure, psig 100 Backpressure, Normal, psig 3

Backpressure, Developed, psig 500 0607E:l

Length of straight pipe, in.

Number of goo elbows Number of 45,:r, bends Misc.

Loop seal water Volume, Ft3 TABLE 2-2 SAFETY VALVE INLET PIPING COMPARISON Typical North Anna Inlet Piping 58 3

1 10" 1.07 Dresser 31739A Inlet Piping*

7i 4

71"

.38

  • Source: Reference (7) 0607E:l Dresser 31709NA Inlet Piping*

54 4

rt'

l

(

*. * !,.J TA"BLE 2-3 COMPARISON OF TEST PRESSURE DROP WITH PLANT SPECIFIC PRESSURE DROP Pl ant Specific*

Pressure Drop North Anna 1 and 2 207

  • Appendix I
    • Source: Reference (8) 0607E:l Dresser 31739A**

Test Pressure Drop 454 psi Dresser 31709NA**

Test Pressure Drop Not available

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Figure 2-1 TYPICAL PORV iNLET PIPlNG ARRANGEMENT

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TYPICAL SAFETY VALVE.INLET PIPING ARRANGEMENT

*-----*-*-**-*----~---*--,--~-..,.,.......-,--..,-,-,.....,....-,-~~.--..

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---*~-.,-... -.. -.--.-

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1.* :.*.

3.0 VALVE INLET FLUID CONDITIONS Justification for.inlet fluid conditions used in-the EPRI Safety and Relief Valve tests are summarized in References 2 and 3.

These conditions were detennined based on consideration of FSAR, extended High Pressure Injection, and Cold Overpressuri zati on 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. d*ischarge and an Extended High Pressure Injection event which may result in liquid discharge, are presented for each refer~nce plant.

Use of reference plants results in fluid conditions enveloping those expected for North Anna 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 North Anna 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.

The fl_uid conditions at the inlet to the safety valves forfeedline rupture accidents are summarized in Table 3-2 and a disclssion of the feedline break analysis is p*rovided in Reference 2.

Maximum pressurization rates are taken when the valves open on water (the safety valves i ni ti ally open on steam; however, the pressurization rate is enveloped by those presented for the locked rotor and loss of load events).

The limiting Extended High Pressure Injection event was the spurious activation of the safety injection system at power.

A condition II event, this will result, at worst, in a reactor shutdown with the plant capable of returning to operatic~ The analysis results for three-loop plants are provided in Table 3-3.

Fluid inlet conditions for*

cold overpressure protection are provided in Table 3-4.

Cold overpressure is not a design basis for the safety valves but is for the PO RVs

  • 0607E:l

TABL~ 3-1 VALVE INLET CONDITIONS FOR ¥8~

EVENTS RESULTING IN STEAM DISCHARGE

~

Maximum Valve Pressurizer Reference Opening Pressure( psi a} I Plant Pressure (psi a)

Limiting Event Safety Valves Only 3-Loop 2500 2592/Locked Rotor Safety and Relief Valves 3-Loop 2350 2555/Locked Rotor Source:

Reference (2)

Maximum Pressure Rate (psi a/sec}/

Limiting Event

£16/Locked Rotor r

200/Locked Rotor

  • Represents maximum pressure at safety valv.e inlet.

This value is less than the reported FSAR valµe for the locked rotor transient since it does' not consider conservatively high RCS loop pressure drops.

The FSAR reports peak RCS~pressure.

0607E:l

TABLE 3-2 SAFETY VALVE INLET CONDITIONS FOR FSAR EVENT RESULTING IN LIQUID DISCHARGE (MAIN FEEDLINE BREAK)

Safety Valve Setpoint Opening (psi a) 2575 0607E:l Maximum Pressurizer Pressure (psi a) 2575 Maximum Pressurization Rate (psi a/sec) 4.0 Maximum Liquid Surge Rate (gpm) 507.2 Range of Liquid Temperature at Valve Inlet

~F 634.5-636.6

Reference Pl ant Valve Opening Setpoi nts( psi a)

Safety Valves TABLE 3-3 SAFETY AND RELIEF VALVE INLET CONDITIONS RESULTING FROM SPURIOUS INITIATION OF HIGH PRESSURE INJECTION AT POWER WHEN VALVES ARE DISCHARGING LIQUID Fluid State on Valve Opening(a)

Maximum Pressurizer Pressure (psia)

Range of.

Pressurization Rates( psi/sec) 3-Loop No Discharge Relief Valves 3-Loop 2350 Steam/Liquid 2352 0-12

a.

First/subsequent openings.

0607E Range of Surge Rates When Valve Is P~ssi ng Liquid( GPM) 0.0-781 Range of Liquid Temperature At Valve Inlet( ~F) 498-502

I 1-(,

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I Unit 1 Unit 2 0607E:l TABLE 3-4 PORV INLET CONDITIONS FOR COLD OVERPRESSURE PROTECTION RESULTING IN WATER DISCHARGE Reactor Coolant Pressure (psig) 505 505 Temperature

Range,

~F 100 - 320 100 - 340

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.( 4) Tests were conducted at three sites over a period of 1-1/2 years.

PORVs were tested at Marshall Steam Station(S) and Wyle Laboratories, (5, 7) whiie safety valves were tested at the Combustion Engineering Test Site in Connecticut. { 7}.

4.1 Relief Valve Testing Test results applicable to the PORVs i"!'lstalled in North Anna Unit 1 and Unit 2 are contained in Section 4.5 of Reference 7, Masoneilan Relief Valve.

This valve fully opened and closed on demand for each of the eleven (11) evaluation test cycles at the Marshall Test Facility.

During the shakedown testing of the Masoneilan valve at Marshall, valve stroke times were recorded in excess of three seconds.

The regulated air supply pressure to the air operator was adjusted to 60 psig for all the evaluation tests and stroke times were reduced to within two seconds.

For all.the eleven evaluation tests at Wyle (Phase III), the valve opened a-nd closed on demand.

During post test inspection, no damage was observed that would affect future valve performance.

It was observed, however, that the cage to body gasket had partially 11washed out 11 during testing.

Valve opening times were found to be sensitive to air supply system pressures and tubing size during the' tests. It is noted that prior to plant operation stroke times are checked and adjusted to be within the required range.

A comparison of the "As-Tested" inlet fluid conditions for the Marshall and Wyle tests show that th~ North Anna Unit 1 and Unit 2 fluid conditions summarized in Section 3 of this report were eneveloped by the test. Results of the ~elief Valve testing indicate the Masoneilan valves functioned satisfactorily, opening and closing in the required time and discharging the required flow rate.

0607E:l

Set Point Pressure (psig)

Temperature (Of)

Fluid Type Flow Rate (1 bs/hr)

Set Point Pressure (psi a)

Temperature (Of)

Fluid Type Flow Rate (lbs/hr) 0607E:l TABLE: 4-1 COMPARISON OF PORV INLET FLUID CONDITIONS WITH 11AS-TESTED 11 CONDITIONS Steam Conditions PORV Wyle Test Inlet Fluid 52-MN-lS Conditions 174-lS 2335 2480 650' 670 steam steam 210,000 228,600 Water Conditions Wyl e Tests PORV 55-MN-3'1 Inlet Fluid 56-MN-SW Marshal 1 Test (No. 1-No. 11)

(2430-2505)

{sat. )

steam

{204,000-205,000)

Condi ti ans 58-MN-SW

  • 60-MN-7S/W 505 678 2535 100-340

( 101-445) 670 Water Water S team/W ate r (324,000-532,800) 468,000

.-1.

Test Marshall 1

2 3

4 5

6 7

8 9

10 11 Wyle 52-MN-lS 53-MN-2S 54-MN-4S 55-MN-3W 56-MN-5W 57-MN-3vl sa:...MN-5W 59-MN-&I 60-MN-7S/W 61-MN-&l /W 62-MN-9rl TABLE 4-2 TABULATION OF OPENING/CLOSING TIMES FOR PORV Opening Time (Sec.)

2.00 1.900

1. 750 1.800 1.800 2.100
1. 800-
1. 650 1.600 1.700
1. 900
1. 64
1. 84
3. 73 6.39 3.08 2.54 2.39
1. 95 1.81 1.97 3.08 Note:

Required Opening Time

- 2.0 Sec.

Required Closing Time

- 2.0 Sec.

Source:

Reference ( 7) 0607E:l Closing Time (Sec.)

1.700

1. 600 1.600
1. 600
1. 600
1. 600
1. 700
1. 600
1. 600
1. 600
1. 700 1.87 1.88
1. 79 1.33 1.39
1. 4 1.46 1.89
1. 93 1.£4
i. ao*

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4.2 Safety Valve Testing Test results applicable to the safety valves installed at North Anna Unit 1 and Unit 2 are contained in Section*3.1 and 3.2 of Reference 7.

Although the Dresser 31759A safety valve used at North Anna Unit 1 and Unit 2 was not specifically tested by EPRI, justification for extension of the EPRI test results to this valve is contained in Reference 1.

4.2.1 Dresser Model 31739A Safety Valve The Dresser* Model 31739A safety valve underwent a series of tests at the EPRI/CE test facility.

The "As-Tested" fluid inlet conditions for the 31739A valve are compared to the North Anna Unit 1 and Unit 2 fluid inlet conditi ans in Table 4-1 of this report. This comparison shows the EPRI "As-Tested" fluid conditions envelope those for North Anna.

Three loop seal steam tests were conducted using the final two ring settings developed during the steam testing of the Dresser 31739A valve while on the long inlet piping configuration.

For all the tests, EPRI reports the initial valve opening was within

_:3 percent of the set pressure. For two of the tests the valve exhibited typical loop seal discharge and then popped open on steam at pressures of 2595 to 2675 psia and stabilized.

The second ring setting used in the loop seal steam tests was also used for the transition and water tests.

One loop seal test was run at a 3.38 psi/sec ramp rate while the other two tests were run at ramp rates in excess of 300 psia.

One high back pressure, loop seal, steam-to-water transition test was conducted.

The initial lift occurred within.:!:_3 percent of the set pressure, the valve went through a typical loop seal discharge and popped open at 2536 psia, had stable perfonnance on steam and closeci on water with 13.9 percent blowd0wn.-

0607E:l

Two high back pressure water tests were conducted.

The 650~F test showed**

stable valve perfonnance with 18.5 percent blowdown but the SSO~F water test resulted in valve chattering.

While the loop seal water was being discharged in the Dresser 31739A test valve discussed above, water-hammer pressure oscillations were observed in the valve inlet piping. These pressure oscillations are detailed in Reference 7 and Reference 9.

4.2.2 Dresser Safety Valve Model 31709NA The Dresser Model 31709NA safety valve w~s subjected to only one loop*

seal piping test at the EPRI/CE test facility.

The 11As-Tested 11 fluid inlet condition for this test is provided in Table 4-1.

The single loop seal test conducted on the Dresser 31709NA test valve was a low backpressure, high ramp rate test. The valve opened within

~3 percent of set point and chattered and closed at a pressure of 2010 psia.

The valve reopened after several minutes and reclosed just below 2150 psia.

A post test leakage check was conducted and leakage was measured at 0.5 gpm.

No further loop seal testing was conducted on this valve and no ring adjustments were attempted (for loop seal piping configurations) to attain stable loop seal performan~e.

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 *North Anna 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.

0607E:l l

I I I

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A review of Table 4-3 shows the Dresser 31739A safety valve tested exhibited stable operation on a loop seal piping configuration at pressurization rates of 3.38-328 psi/sec with initial opening pressures of (2451-2582) psi and pop pressures of (2594-2675) psi.

The EPRI data also indicates that steam flow rates in excess of rated flows are attainable.

However, 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 perfonnance observed in the EPRI tests is addressed in Reference 9 for Westinghouse Plants and the results and conclusio.ns of this report can be extended to North Anna 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 1 oop 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 of two seconds would still provide acceptable overpressure protection.

Evaluation of the 1 imiting 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 Inl.et Piping Pressure Oscillations As observed during the loop seal discharge tests, oscillations occur upstream of a spring loaded Safety valve while water is flowing through the valve.

An analysis*of this phenomenon was conducted and the results are documented in Reference 9.

Table 4-4 provides the maximum pennissible pressure for pressurizer Safety valve inlet piping sizes and 0607E: 1.

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 and during safety valve loop seal 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 resul~d 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

  • 0607E:l

Set Point Pressure (psia)

Temperature (OF)

Fluid Type Fl ow Rate

. (1 bs/hr)

Pre ssuri zati on Rate (psi/sec)

Stability Initial openinJ Pressure (psi a Pop Pressure, (psi a)

TABLE 4-3 COMPARISON OF SAFETY VALVE INLET FLUID CONDITIONS WITH 11AS-TESTED 11 CONDITIONS Safety Valve Inlet Fluid Tests 31739A-Conditions 1016, 1017, 1021 Test 31739A-1025 2350 2500 2500 650 650 650 Steam loop seal/steam Steam/water 212,000 200-216 3.88-328 1.95 Stable**

Stable**

2451-2582

. 2525 2594-2675 2536 Rated flow achieved but not reported *in EPRI Tables, reference (7).

    • As reported by EPRI in Perfonnance data tables of Reference (7)
  • 0607E:l

Pipe Size 6-i nch Sch. -160 6-i nch Sch. 120 4-*i nch Sch. 160 4-i nch Sch. 120

  • 3-i nch Sch. 160 TABLE 4-4 MAXIMUM PERMISSIBLE PRESSURE FOR PRESSURIZER SAFETY VALVE INLET P1PING*

Outside Diameter Nominal (in)

Thickness (in) 6.625

o. 719 6.625 0.562 4.500
o. 531.

4.500 0.438 3.500 0.438 Source:

Reference (9)

  • Applicable for temperature below 300°F.

0607E:l Permissible Pressure (psi)

Level B Level C 5229 7131 4004 5460 5733 7818 4644 6333 6119 8344

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 North Anna 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 confinn the ability of the Safety and Relief Valves to open and close under the expected operating fluid conditions.

0607E:l

APPENDIX 0607E:l

i,-4.'

1.

APPENDIX I INLET PIPING PRESSURE EFrECTS(B)

Inlet Piping Flow Pressure Drop (!1PF)

The flow pressure drop is given by, (k+l + fl} M2 o

l1PF = --~2~-

2g pA c

where, k = expansion or contraction loss coefficient (dimensionless) f = friction factor (dimensionless)

L = piping equivalent length/diameter considering effects of D

fittings and friction (dimensionless)

M = maximum valve flowrate for steam {as established by the valve manufacturer) {lb/sec) gravitational constant {32.2 lb-ft/lb-sec2) p = steam density at nominal valve set pressure (lb/ft3}

A = inlet piping flow area (ft2)

2.

Acoustic Wave Amplitude* (l1PAW) safety The acoustic wave amplitude is calculated as follows. (8) There are two situations to consider:

- If T

< 2 L/a, op -

0607£:1

3.

4.

-c If Top > 2L/a,

where, a

=

L

=

T

=

op steam sonic velocity at nominal valve set pressure (ft/sec}

inl~t pipin~ length (ft}

valve opening time for steam inlet conditions as established from the EPRI testing effort is lOmsec for the Crosby safety valves and 15msec for the Dresser safety valves.

These valves are typical of the rastest opening times measured during the tests.

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

Plant-Specific Pressure Drop The plant-specific pressure drop associated with valve opening is equal to the sum of the friction pressure drop (~PF} and the acoustic wave amplitude (~P.Alil} as detennined above.

Calculation of Inlet Piping Flow Pressure Drop for North Anna 1 and 2 (K + 1 + f.!:. } M2 D

0607E:l

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

!:. = ~

+ 3x30+1xl6 = 103.2 (Reference 10)

D

.432 p = 7.65 lb/ft3 (satuated. steam at 2500 psia) 2 A= 0.147 ft M = 388, 670 lb/hr = 108 lb/sec 2600 sec/hr The Fl ow Pressure Drop for North Anna 1 is, (0.5 + 1 +.015 x 103.2) x (108) 2 23 2 tiP f =

2

=

psi 64.4 x 7.65 x.147 x 144 TABLE A-1

  • North Anna 1 and 2 Inlet Piping Configuration*

- Total Pipe Length

- Pipe Diameter

- Fittings

- Total Loop Seal Length

- Dresser 31759A Safety Valve 388,670 lb/hr rated capacity

.015 sec opening time

= 5.7 ft

= 6 11 sch 160

= 3 - 90° elbows 1 -

45~ elbow

= 8.7 ft

  • Note:

Assumed typical for both units

  • 0607E:l

5.0 AcousticWave Amplitude North Anna 1 and 2 For the configuration described in Table A-1, the Parameters are, T0p =.015 sec.

2L 2 x 8. 7 a = 1300 ft/sec =.013 sec S.

T 2L lnce op a

2(8. 7) x 108

= {32.2)(.147)(144)(.015) t.PflW = 183.8 psi 0607E:l

~"'...

6.0 PLANT-SPECIFIC PRESSURE DROP North Anna 1 and 2 AP = 23.2 + 183.8 AP = 207 psi 0607E:l

REFERENCES

1.

EPRI !'WR Safety and Relief Test Program, Valve Selection/

Justification Report, 11 lnterim Report, August 1981 11

2.

Westinghouse Electric Corporatio.n Report, 11 Valve lnle.t Fluid Conditions for Pressurizer Safety and Relief Valves in Westinghouse

- Design Plants (Phase C) 11

, Interim Report, December 1981.

3.

EPRI !'WR Safety and Relief Vaive Test Program, 11Test Condition Justificatfon Report 11

, Interim Report, April 1982.

4.

11 EPRI ~R Safety and Relief Valve Test Program, Description and Status 11

, April 1982.

5.

11 EPRI - Marshall Power-Operated Relief Valve Interim Test Data Report:

EPRI N0-1244-20, Interim Report, February 1982.

6.

11 EPRI/Wyle Power-Operated Relief Valve Test Report, Phase I and II 11 EPRI NP-2147, LO, Interim Report, December 1981.

7.

11 EPRI !'WR Safety and Relief Valve Test Program, Safety and Relief Valve Test Report 11,

Interim Report, April 1982.

8.

11 EPRI !'WR Safety and Relief Valve Test Program Guide for Application of Valve Test Program Results to Plant-Specific Evaluations 11 Interim Report, March 1982.

9.

11 Review of Pressurizer Safety Valve Performance as Observed in the EPRI Safety and Rel i"ef Valve Test Program 11

, June 1982.

10.

Crane Technical Paper No. 410, 11 Flow of Fluids Through Valves, Fittings, and Pipe 11

, 1976

  • 0607E:l

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Prepared By:

PWR SAFETY AND RELIEF VALVE ADEQUACY Rr;.?OR T FOR VIRGINIA ELECTRIC POWER COMPANY SURRY UNIT 1 AND UNIT 2 JUNE 1982 Westinghouse Electric Corporation Nuclear Energy Systems P.O. Box 355 Pittsburgh, PA 15230 8207080346 820701 PDR ADOCK 05000280 P

PDR

1.0 INTRODUCTION

In accordance with the initial recommendation of NUR£G 0578, Section 2.1.2 as later clarified by NUREG 0737, item II.D.l 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 conditions. The second objective of the program was to obtain sufficient piping thermai 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.

0605E:l

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-Operated 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. (l) The justification was developed based on evaluation performed by the valve manufacturers *and considered effects of differences in operating characteristics, materials, orifice siz~s 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 ~ompares 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.

0605E:l

1.
2.

TABLE 2-1 VALVE AND PIPING INFORMATION SAFETY VALVE INFORMATION Number of valves Manufacturer Type Size Steam Flow Capacity, lbs/hr Design Pr.es sure, psi g Design Temperature, OF Set Pressure, psig Accumulation Blowdown Original Valve Procurement Spec.

RELIEF VALVE INFORMATION Number of Va 1 ves Manufacturer Type Size Steamflow Capacity, lbs/hr Design Pressure, psi Design Temperature, °F Opening Pressure, psig Closing Pressure, psig 3

Crosby Valve and Gage Self Actuated 6K26 293,330 (ASME Rated) 2485 650 2485 3 percent of set pressure 5 percent of set pressure E-676279 2

Copes-Vulcan Pressurizer Power Relief 2"W 3" inlet, outlet 179,000 210,000 Norn Max 1500 (ANS I) 680 2335 400 lbs and 415 lbs (When OP mitigation (1456)

(1456c) system is in service)

  • 0605£:1

-~--'

I TABLE 2.1 Continued ***

3.

SAFETY AND RELIEF VALVE INLET PIPING INFORMATION Design Pressure, psig Design Temperature, °F Configuration of Piping Pressurizer Nozzle Configuration 3

Loop Seal Volume, ft

  • Loop Seal Temperature, °F Steady State Flow Pressure Drop Acoustic Wave Pressure Amplitude 2485 680 See 12846.22 MKS 124Al and 2 12846.22-MKS-124Al and 2, Volume - 0.92 Temp. 650 > T > 110 (approximately 200°F)

See Appendix 1 See Appendix 1

4.

SAFETY AND RELIEF VALVE DISCHARGE PIPING INFORMATION Design Pressure, psig 650 Design Temperature,°F 600 Configuration 12846.22-MKS-124Al and 2.

Pressurizer Relief Tank Design Pressure, psig 100 Backpressure, Normal, psig 3

B ackpressure, Developed, psig 500 0605E: 1

TABLE 2-2 SAFETY VALVE INLET PIPING COMPARISON Typical Surry 3K6 Inlet 6M6 Inlet I n 1 et Pi pi ng Piping*

Piping*

Length of iiO 60 61 straight pipe, in.

Number of 90° 4

4 elbows Number of 180° 2

bends Misc.

78 II 71" Loop seal water

.92 0.27 1.02 Volume, Ft3

  • Source:

Reference (7) 0605E:l

TABLE 2-3 COMPARISON OF TEST PRESSURE DROP WITH PLANT SPECIFIC PRESSURE DROP Pl ant Spec if i c* _

Pressure Drop Surry 1 170. 9 psi Surry 2 171 psi

  • Appendix I
    • Source:

Reference (8) 0605E:l 6M6 Test**

Pressure Drop 251 psi 3K6 Test**

Pressure Drop 321 psi

. tr

?-/ 'g I/

FIGURE 2-1 TYPICAL PORV INLET PIPING CONFIGURATION I

2:~;:*

..... ~*.:*...

.* ~

II

~

4---

\\

FIGURE 2-2 CONFIGURATION TYPICAL S~FETY VALVE INLET PIPING 1,....0 I

jY y

i I.

.., r 3.0 VALVf 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 ref.erence plant was selected for each grouping of plant considered.( 3) Valve fluid conditions resulting from limiting FSAR events, which result in steam ~ischarge and an Extended High Pressure Injection event which may result in liquid discharge, are presented for each referenc~ 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 Table 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

  • 0605E: 1

TABLE 3-1 VALVE INLET CONDITIONS FOR FSAR EVENTS RESULTING IN STEAM DISCHARGE Reference Plant Valve Opening Pressure (psia)

Safety Valves On.ly 3-Loop 2500 Safety and Relief Valves 3-Loop 2350 Source: Reference (2) 0605E:l Maximum Pressurizer Pressure(psia)/

Limiting Event 2592/Locked Rotor 2555/Locked Rotor Maximum

. Pres st.ire Rate (psi a/ sec) I Limiting Event 216/Locked Rotor 200/Locked Rotor

0605E: 1 TABLE 3-2 PORV INLET CONDITIONS FOR COLO OVERPRESSURE PROTECTION RESULTING IN WATER DISCHARGE

.* Reactor Coolant Pressurizer, psig 435 Temperature Range, ° F 100-350

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.( 4) Tests were conducted at three sites over a period of 1-1/2 years.

PORVs were tested at Marshall Steam Statfon(S) and Wyle Laboratories,( 6,7) while safety valves were tested at the Combustion Engineering Test Site in Connecticut.(?)

4.1 Relief Valve Testing Test results applicable to the PORVs i~talled in Surry Unit 1 and Unit 2 are contained in Section 4.7 of Reference 7, tapes-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 Facilitiy; 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.*

0605E: 1

Set Point Pressure (psia)

Temperature (OF)

Fluid Type Flow Rate (lbs/hr)

Set Point Pressure (psia)

Temperature (OF)

Fluid Type Flow Rate (lbs/hr) 0605E:l TABLE*4-1 COMPARISON OF PORV INLET FLUID CONDITIONS WITH "AS-TESTEO" CONDITIONS Steam Conditions PORV Wyl e Test

-I n 1 et Fl u i d 63-CV Marshall Test Conditions 174-lS

( No

  • 1 -

No

  • 11 )

2350 2477

( 2430-2505) 650 670 (sat.)

steam steam steam 210,000 255~600 (221,000-220,000)

Water Conditions PORV Wyle Test Wyle Test Inlet Fluid 63-CV 67-CV Conditions 174-lS 174-5W 435 675 675 100-350 442 106 Water Water Water 399,600 630,000

Test Marshall 1

2 3

4

5.

6 7

8 9

10 11 Wyle 63-CV-174-lS 64-CV-174-2S 65-CV-174-4W 66-CV-174-3W 6 7-CV-174-5W 68-CV-174-6W 69-CV-174-7W/W 70-CV-174-8W/W TABLE 4-2 TABULATION OF OPENING/CLOSING TIMES FOR PORV Opening Time (Sec.)

1.600 1.300 1.100 1.300 1.400 1.400 1.300 -

1.300 1.400 1.400 1.500 0.57 0.49 0.57 0.97 0~90 0.66 0.52 0.50 Note: Required Opening Time

- 2.0 Sec.

Required Closing Time

- 2. 0 Sec.

0605E:l Closing Time (Sec.)

1.950 2.000 2.100 2.000 2.000 1.700 1.700 1.655 1.700 1.600 1.700 1.34 1.34 1.15 0.54 0.61 1.29 1.27 1.35

i" 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 test.ing 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.Cl) 4.2.1 Crosby 3K6 Safety Valve Tests The Crosby 3K6 test valve underwent a series of tests at the EPRI/CE Test 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 cin 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 earl~er tests on this valve (with steam internals installed). Steam tests were conducted both with the loop seal d.raine*d and filled. For the test with a drained loop seal the valve opened within the EPRI criteria and had stable 0605E:l

f..

behavior. When the pressure accumulated to 6 percent above set pressure, rated lift 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 lift was-reported at pressures from 2356-2630 psi. The valve fluttered at partial lift positions while discharging the loop seal water and then P?PPed 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 lif~ when the*pressure was 6 percent above the valve design set pressure. The valve closed with 17-20 ~ercent 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 within ~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 EPKI/CE Test Facility. The "As Te~ted" 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 th~ Crosby 6M6 (Loop Seal Internals) Test Valve, one group with "As Installed" ring settings and one group with "lowered" ring*settings

  • 0605E:l

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 3S0°F loop seal test and is not representative of the Surry Unit 1 and Unit 2 inlet conditions.

Although not part of the Surry fluid inlet conditions, a transition test with 650°F water was successfully conducted. Subsequently a 5S0°F water test was tried with the test terminated when the valve started to chatter.

Seven additional loop seal tests were conducted with 11 lowered 11 ring s.ett~ngs as well as two additional transition tests. The results of those tests are detailed in Section 3.5 of Reference 7. Five cold 16op 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 w~s a 350°F loop seal test at a high ramp rate and is not considered representative of the Surry Unit 1 and Unit 2 inlet conditions.

0605E:l

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 test1ng been conducted using actual plant-specific piping arrangements and fluid conditions.

A review of 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 psi/sec 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. However, 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 performance 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.l 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 var.ious time delays inserted for the valve opening. Results of the analysis are presented in Reference 9. For the

  • limiting Condition II eve~ts,-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 0605E:l

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 flowing 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 t~ 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 a*rrangement, 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 r~sults of this study are detailed in Reference 9

  • 0605E: 1

Set Point Pressure (psi a)

Temperature (OF)

Fluid Type Flow Rate (lbs/hr)

Pressurization Rate (psi/sec)

Stability Initial opening Pres sure (psi a)

Pop Pressure, (psi a)

TABLE 4-3 COMPARISON OF SAFETY VALVE INLET FLUID CONDITIONS WITH 11AS-TESTED 11 CONDITIONS Tests 6M6 No *. 906-913, Safety Valve Inlet Fluid Tests 3K6 917-923, 925 1406, Conditions 525-532 and 536 1415 and 1419 2350 2500 2500 650.

650 650 Steam loop seal/steam loop seal/steam 212,000 200-216 3.4-200 1.1-375 Stable**

Stable**

2536-2630 2455-2600 2532-2707 2455-2757 Rated flow achieved but not reported in EPRI Tables, reference (7).

    • As reported by EPRI in Performance data tables of Reference (7).

0605E:l

),

Pipe Size 6-inch Sch. 160 6-inch Sch. 120 4-inch Sch. 160 4-i nch Sch. 120.

3-inch Sch. 160 TABLE 4-4 MAXIMUM PERMISSIBLE PRESSURE FOR PRESSURIZER SAFETY VALVE INLET PIPING*

Outside Diameter Nominal (in)

Thickness (in) 6.625 0.719 6.625 0.562 4.500 0.531 4.500 0.438 3.500 0.438 Source: Reference (9)

  • Applicable for temperatures below 300Dr.

0605E:l Permissible Pressure (psi)

Level B Level C 5229 7131 4004 5460 5733 7818 4644 6333 6119 8344

\\

I

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

  • 0605E:l

APPENDIX 0605E:l

.. ' i

  • APPENDIX I INLET PIPING PRESSURE EFFECTS{S)
1. Inlet Pipfog Flow Pressure Drop (APF)

The flow pressure drop is given by,

where, k = expansion or contraction loss coefficient {dimensionless) f

= friction factor {dimensionless)

L = piping equivalent length/diameter considering effects of D

fittings and friction {dimensionless)

M = maximum valve flowrate for st.earn (as established by the safety valve manufacturer) {lb/sec) gc =

gravitational constant (32.2 lb-ft/lb-sec2) p = steam density at nominal valve set pressure (lb/ft3)

A = inlet piping flow area (ft 2)

2. Acoustic Wave Amplitude (APAW)

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

- If T0 p ~ 2 L/a, aM llPAW = gA c

0605E:l

~

\\

) j:.

- If Tap > 2L/ a,

where, a

=

L

=

T

=

op steam sonic velocity at nominal valve set pressure (ft/sec) inlet piping length (ft) valve opening time for steam inlet conditions as established from the EPRI testing effort is lOmsec for the Crosby safety valves and lSmsec for the Dresser safety valves. These valves are typical of the fctstest opening times measured during the tests.

The othe~ 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 (&PF) and the acoustic wave amp 1 i tu de {~PAW) as determined above.
4. Calculation of Inlet Piping Flow Pressure Drop for Surry 1 and 2
  • Surry l& 2 0605E:l
where, k = 0.5 (sudden contraction at Pressurizer Nozzle) f =.015 {Reference 10)

!:. = ~

+ 4x30 = 141.3 (Reference 10)

D

.432 p = 7.65 lb/ft3 (:satuated.. steam at 2500 psi a) 2 A = 0.147 ft M = 293,000 lb/hr= 81.4 lb/sec 2600 sec/hr The Flow Pre~sure Drop for Surry 1 is, 6p = (0.5 + 1 +.015 x 141.3) x 81.42 = 15 *6 psi f

64.4 x 7.65 x.147 2x 144

where, k = 0.5 (sudden contraction at Pressuriz~r N~zzle) f =.015 L = 10.3 + 4x30 = 143.8 0

.432 p = 7.65 lb/ft3 (saturated steam at 2500 psi a).

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

6p = (0.5 + 1 +.015 x 143.8) x 81.4 ) = 15 *8 psi f

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

'- *- (

t~..

5.0 Acoustic Wave Amplitude Surry 1 For the configuration described in Table A-1, the Parameters are, T0p =.010 sec.

2L 2 x 11. 7 a - 1300 ft/sec = *018 sec Si nee T op 2L

<-a' 1300 x 81. 4

= 32.2 x.147 x 144 aPAW = 155.3 psi Surry 2 For the Configuration described in A-1, the Parameters are, T

=

  • 010 sec.

op 2L 2 x 12. 8

-a= 1300 ft/sec = *019 sec S.

T 1 nee op <

2L

-a aM 1300 x 81. 4 aP AW = g A = 32. 2 x.147 x 144 c

aP AW = 155. 3 psi 0605E:l

6.0 PLANT-SPECIFIC PRESSURE DROP Surry 1 AP = 15.6 + 155.3 11P = 170.9 psi Surry 2 AP = 15.8 + 155.3 AP = 171~1 psi 0605E: 1

to"

    • " t-~

TABLE A-1 Surry 1 Inlet Piping Configuration

- Total Pipe Length

- Pipe Diameter

- Fittings

- Total loop seal length

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

.010 sec opening time

= 9.2 ft

= 6 11 sch 160

= 4 - 90° elbows

= 11. 7 ft Surry 2 Inlet Piping Configurati~

- Total Pipe Length

- Pipe Diameter

- Fittings

- Total loop seal length

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

.010 sec opening time 0605E: 1

= 10.3 ft

= 6 11 sch 160

= 4 - 90° elbows

= 12.8 ft

.-~.

.,\\. J.. *;

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", In~erim Report, April 1982.

4. * "EPRI PWR Safety and Relief Valve Test Program, Description and Status", April 1982.
s.

11 EPRI - Marshall Power-Operated Relief Valve Interim Test Data Report:

EPRI N0-1244-20, Interim Report, February 1982.

6.

11 EPRI/Wyle Power-Operated Relief Valve Test Report, Phase I and II",

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

7.

"EPRI PWR Safety and Relief Valve Test Program, Safety and Relief Valve Test Report", Interim Report, April 1982.

8.

11 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 Through Valves, Fittings, and Pi pe 11,. 19T6.

0605E:l

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