ML20113C283
| ML20113C283 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 01/10/1985 |
| From: | Sieber J DUQUESNE LIGHT CO. |
| To: | Varga S Office of Nuclear Reactor Regulation |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM TAC-44562, NUDOCS 8501220276 | |
| Download: ML20113C283 (24) | |
Text
'A@
Telephone (412) 393-6000 Nuclear Division P. O. Box 4 Shippingport, PA 15077-0004 January 10, 1985 Director of Nuclear Reactor Regulation United States Nuclear Regulatory Camtission Attn: Mr. Steven A. Varga, Chief Operating Reactors Branch No. 1 Division of Licensing Washington, DC 20555
Reference:
Beaver Valley Power Station, Unit No. 1 Docket No. 50-334, License No. DPR-66 NUREG-0737 Item II.D.1 Request for Additional Information Gentlenen:
Your letter of July 2,1984 requested additional information related to our subnittals addressing NUREG-0737 item II.D.1, Testing of Safety / Relief Valves.
We indicated in our letter dated October 4,
1984 that outside assistance and additional time would be necessary to emplete all work for the develognent of the responses to your questions and we requested an extension until December 31, 1984.
Upon receipt of supporting information frrrn the Westinghouse Electric Corporation, sare additional time was necessary to cmplete our reviews and to provide additional details.
We have kept our NBC Project Manager aware of the status of this subnittal.
Contained herewith is an attachment which provides responses to your request for additional information. If you have any questions related to this subnittal please contact me or merrbers of my staff.
Very truly yours,
. D. Sieber Senior Manager, Nuclear Group Attachnent O
P O
h i
)
Beaver Valley Power Station, Unit No. 1 Docket No. 50-334, License No. DPR-66 j
NUREG-0737 Item II.D.1 Request for Additional Information
'Page 2 Mr. W. M. Troskhski, Fesident Inspector cc:
U. S. Nuclear Regulatory Ccmnission Beaver Valley Power Station Shippingport, PA 15077 l
U. S. Nuclear Regulatory Ccmnission l
c/o Document Management Branch Washington, DC 20555 Director, Safety Evaluation & Control Virginia Electric & Power Company P. O. Box 26666 One James River Plaza Richmond, VA 23261 L
=.
(
ATTAOIMENT P
RESPONSE TO NRC REQUEST EOR ADDITIGIAL INEORMATICN CATED JULY 2, 1984 TMI ACTION NUREG-0737 (II.D.1)
RELT w AND SAFETY VALVE TESTING BEAVER VALLEY l Questions related to the selection of transients and valve inlet conditions:
QUESTION 1 The submittal identifies the feedwater line break (EWIB) accident as one which'causes liquid water flow through the safety valves. The EPRI tests under similar conditions were performed for only a few seconds. If the plant PWIB accident causes water flow through the valves for a time period greater than that tested, provide information that demonstrates that the plant safety valves can perform their pressure relief function and the plant
- can be safely shu* down.
RESPONSE
The fluid' conditions at the inlet-to the safety.. valves for feedline rupture accidents are sunmarized in the attached Table 1-1.
This information was presented in our submittal of July 1,1982 as part of Attaclynent A, "PWR Safety and Relief Valve Adequacy Report for Duquesne Ligt.t Conpany Beaver
(
. Valley. Unit 1."
A discussion of the feedline break analysis is provided in -
' Westinghouse Electric Corporation Report, " Valve Inlet Fluid Conditions for Pressurizer Safety and Relief Valves in Westinghouse - Design Plants," Interim Report March,1982 which was forwarded to the NRC by Mr. David Hoffman on -
Septanber 30, 1982 on behalf of the EPRI-sponsored PWR Safety and Relief valve Test Progran.
c.
=
The Beaver Valley Updated FSAR provides two safety valve water relief rates for the Main Feedwater Pipe rupture event. The maximum water relief rate prior to bulk boiling and the maximum water relief rate after bulk boiling are both provided. The EPRI report on valve inlet fluid conditions does not provide safety valve liquid relief rates. What the EPRI document does supply is the maximum liquid suge rate into the pressurizer when the safety valves are passing liquid. When the pressurizer is water solid (i.e., prior to bulk boiling) the surge rate into the pressurizer and the relief rate are essentially equivalent. Following bulk boiling the surge line fluid will rot be limited to liquid flow and thus would no longer be equivalent to the safety valve liquid relief rate.
During EPRI SV testing, water flow tests were conducted as reported in WCAP-10105.
In some cases, due to testing limitations, water flow tests were terminated after slurt durations.
In response to the request for identifying applicable liquid flow conditions to which the SVs would be exposed, our response is that the safety valves are not expected to be exposed to any liquid flow. Although this statement contra-dicts the evaluation given in Section 14.2.5.2 of the FSAR the following discussion should provide clarification.
In the UFSAR analysis for feedline breaks, extreme conservatism is used in developing the assunptions upon which the analysis is based. For exanple, the initial reactor power is assuned to be at the engineered safeguards features rating (104.5% of nominal full power); the 1971 ANS decay heat standard plus 20% conservatism is assumed. These assunptions maxunize the heat load of the system. In addition, control systems, such as pressurizer spray and letdown which would mitigate pressurizer surge, and pressure increase were not assumed in the UFSAR analysis. These assunptions and others were
developed to provide a conservative basis to which the auxiliary feedwater system is designed. A result of these assunptions is a maximization of water relief through the safety valves thus decreasing margin to core uncovery and increasing the heat removal duty of the auxiliary feedwater system. This is consistent with the analysis philosophy of providing a conservative analysis of the auxiliary feedwater system capability during feedline breaks and insuring that no core uncovery will result.
The results of the very conservative UFSAR analysis indicate that the pressurizer would be filled for approximately 1600 seconds. However, based on considerations listed above concerning the conservative input assunptions to this feedline break analysis it is felt that if more realistic assunptions are used with respect to pressure control, power level, decay heat, and auxiliary feedwater flow, that liquid relief through the safety valves is precluded.
In the unlikely event of a feedwater line break actually occurring, the operators would follow Dnergency Operating Procedure E-2, "Ioss of Secondary Coolant," and dung steam from all intact steam generators to the main condenser when possible or to the atmosphere from the unaffected steam generators. The purpose of this is to prevent safety valve operation.
The Target Rock safety valves installed in Beaver Valley 1 were not originally designed for the passage of water as this was outside the design basis of our plant.
The Beaver Valley pressurizer safety valve was tested with liquid flow in four tests (Table 1-2) for a total of over 900 seconds with the longest test lasting over 296 seconds. The safety valve operated eleven times during these tests (eight times during test 714). This is h e nted in EPRI Report NP-2770-LD, Vol. 8 and demonstrates that the plant safety valves can perform their function over a sub-stantial time duration with liquid conditions and that the plant can be safely shut down.
5 TABIE l-1 Safety Valve Inlet Conditions For FSAR Event Resulting in Liquid Discharge (Main Feedline Break)
Safety Valve Maxinum Maxinum Range of Liquid Setpoint Pressurizer Pressurizer Maxinum Tenperature at Qaning Pressure Rate Liquid Surge Valve Inlet (psia)
(psia)
(psia /sec)
Rate (qpm)
'F 2575 2575 1.7 2010.8 644.6-672.0 1
m
TABIE l-2 Target Rock 69C Safety Valve Water Tests Test-Safety Valve Pressurization Maxinum Tenp In Test Cpening Pressure Rate Steady Liquid Tank at Tine (psia)
(psia /sec)
Flow (gpm)
Valve (sec)
(*F) 712 2486 2.8 1873 613 296.5 714 2462 2.2 2676 568 180 717 2488 2.6 2041 410 270 719 2487 0.7 1601 397 255 L__
CUESTIm 2 The IJestinghouse inlet fluid corxiittons report identifies Beaver Valley as one of the plants not being covered by the report with respect to the cold overpressurization event. h Beaver Valley subnittal, however, states that review of the cold overpressure protection system has determinal that cold overpressure fluid conditions are represented by the expected inlet fluid conditions for the 3-loop cold overpressurization event, as providal in the liestinghouse report.
Provide additional detail and discussion on how the Beaver Valley cold overpressure transient and Power Operated Relief Valve (P mV) inlet mnditions were determined to be represented by the 17estinghouse inlet fluid conditions report.
RESPWSE The 11estinghouse inlet fluid conditions report provides a range of inlet fluid taperatures and pressures for mld overpressure transients. Clarification of the Beaver Valley Unit 1 P mV inlet fluid conditions for the cold overpressure transient has been provided in response to question 4.
'Ihese PmV inlet conditions, fluid tenperature and pressure, which are expected at our plant have been reviewed against the inlet fluid conditions provided in the 11estinghouse report. It has been determined that these conditions fall within the envelope of conditions shown cn Figure 5-1 of the EPRI Fluid Conditions Report.
The determination of the PmV inlet conditions, with respect to the cold overpressure protection system (OPPS), was acconplished by mnsidering reactor coolant system (RCS) pressure and tenperature and the fluid conditions inside the pressurizer. During plant cooldown, the OPPS is placed in service after RCS cold leg tenperatures reach 275'F and the RCS pressure drops below the OPPS setpoint.
During start-up, the CPPS remains in service until the RCS cold leg tenperature
reaches 275'F. This represents the inlet fluid conditions under which the PORVs would be expected to operate which include nitrogen, saturated steam, steam with a transition to saturated water and subcooled water.
The design of the Beaver Valley Unit 1 OPPS was not performed by Westinghouse and, therefore, the analysis provided in the referenced reports do not reflect an=1artions which were used in the design of our OPPS. The design objective, however, was the same and that was to determine what mass and heat input events the BV-1 OPPS would be required to mitigate. A description of our system, assunptions, setpoint calculations and proposed technical specifications were submitted to the NRC on November 23, 1977 (C. N. Dunn to R. W. Reid). Since that time, the NRC has issued a safety evaluation report on this system dated April 4, 1983 (S. A. Varga to J. J. Carey) and we have submitted revised technical specifications under change request 1A-34, Rev. 1 dated D h r 12, 1984.
We are currently reviewing additional analyses which were performed by Westinghouse. The purpose of these analyses was to place a more conservative limit on the tenperature differential permitted between the primary and secondary coolants in the steam generators and determine maximum mass input rates under different plant configurations. The intent is to establish a new OPPS setpoint
- and renain within our 10 CFR 50 Appendix G limits.
We have, however, as previously stated, determined that our expected PORV inlet fluid conditions are enveloped by the subject reports. Also, any OPPS setpoint change will not exceed these values.
l
QUESTICN 3 Results from the EPRI tests on the Target Rock 69C safety valve indicate that blowdowns may exceed the design blowdown of 5%. The consequences of potentially higher blowdowns were not addressed in the Beaver Valley Unit 1 submittal. Blowdowns in acess of the design blowdowns of 5% could cause the pressure to be sufficiently decreasal that adequate cooling might not be achieved for decay heat renoval. Discuss these consequences of higher blowdowns if blowdowns in excess 5% are expected.
RESPCNSE Blowdowns in excess of 5 percent have been analyzed by Westinghouse in conjunction with the Westinghouse Owners Group (WCG) program of safety valves. The analyses utilized blowdowns in excess of 10 percent. The results from these analyses showed no adverse effects on plant safety. The peak pressurizer water level calculated renained below the pressurizer inlet piping to the safety and relief valves.
QUESTION 4 In valve operability discussions on cold overpressurization transients, the submittal only identifies conditions for water discharge transients. According to the Westinghouse valves inlet fluid conditions report, however, the PORVs are expected to operate over a range of steam, steam-water, and water conditions because of a potential presence of a steam bubble in the pressurizer.
'Ib assure that the PORVs operate for all cold overpressure events, discuss the range of fluid conditions expected for the expected types of fluid discharge and identify the test data that demonstrate operability for these cases. Since no low pressure steam tests were performed for the PORVs, confirm that the high pressure steam tests demonstrate operability for the low pressure steam case for both opening and closing of the PORVs.
RESPONSE
Beaver Valley 1 PORV Inlet Fluid Conditions apected for cold overpressure events have been re-evaluated and are identified in the attached Table 4-1.
As can be seen, valve inlet fluid pressures and tsperatures for each scenario for which the PORVs may be expected to operate are <453 psig and from 75'F to <448'F, respectively.
EPRI Test conditions for the PORVs were chosen based on expected inlet conditions. Tests were limited but designed to confirm operability over a full range of expected inlet conditions. Steam, steam to water transition and water flow tests were conducted. Results of these tests can be found in EPRI Report EPRI NP-2670-LD, Volume 6.
Although the steam tests were conducted only at the higher pressure, it is expected that satisfactory operation would also result at the less severe lower pressures. This cc.n be seen by the successful low pressure (675 psia), low tenperature (100*F) water tests (56-m-5W and 58-MN-5W) and low pressure (675 psia), high tenperature (445'F) water tests (55-m-3W and 57-m-3W).
' TABLE'4-1 RCS TRANSIENT TEMP SCENARIO PORY FLUID MODE-RANGE *F CONDITIONS
,75F-140F,P.<453psig)
HEATUP 75-140 1
SUBC00 LED WATER 0 SATURATED
'338 F-448 F (PRESSURIZED)
"338 F-448 F SUBC00 LED
'140 F-448 F HEATUP 140-275 2
sSTEAM 0
,100**-453 psig***N WATER 0
,100**-453 psig*** f sWATER* 0
,100**-453 psig***,/.
A B
C HEATUP 140-275 3
Condition 2A only HEATUP 140-275 4
Condition 2B only HEATUP 140-275 5
Condition 2C only HEATUP 140-275 6
SCENARIO 2A Cr SCENARIO 2B HEATUP 140-275 7
SCENARIO 2B SCENARIO 2C C00LDOWN 75-140 8
NITROGEN O'75 F-160*F ' (after establishing N SUBC00 LED I75F-160F 2
,P < 453 psig bubble at P < 100 psig)
WATER @
P < 453 psig***
D E
C00LDOWN 75-160 9
Condition D only C00LD0WN 75-160 10 Condition E only SATURATED STEAM 0 'T < 448"F 1
'T < 448 F SUBC00 LED
'160 F-448 F
,P<453psig***gPRESSURIZED)sP < 453 psig***,, WATER 0
,P < 453 psig***,
C00LDOWN 160-275 11 WATER 0 F
G H
C00LDOWN 160-275 12
. Condition 11F only
- RCS water at 140 F to 275 F mixing in pzr with saturated pzr water at 448 F C00LDOWN 160-275 13 Condition 11G only
- Pressure at which steam bubble is drawn in pressurizer using pressurizer heaters C00LDOWN 160-275 14 Condition 11H only
- RCS pressure is normally maintained between
'400 psig and the RCP Seal pressure limit.
C00LDOWN 160-275 15 SCENARIO 11F 5
SCENARIO 11G (at the present time, 400 psig represents an envelop for the PORV setpoint and 453 psig C00LDOWN 160-275 16 SCENARIO 11G r
SCENARIO 11H is our 10 CFR 50 Appendix G limit at 75 F)
Questions Related to Valve operability:
QUESTIm 5 The Beaver Valley Unit 1 Target Rock 69C safety valve was tested by EPRI.
Durirs the loop seal-water tests the EPRI Target Rock test valve experienced flutter. Post-test inspection revealed scorirg of the piston and piston j
rings and bowirs of the main disk shaft. The valve was replaced. The plant submittal has' identified transients and events which may cause liquid discharge which would possibly result in valve instability (chatter or flutter). The extent of valve damage'is dupandent on the severity of the valve instability. If Am is extensive, valve inoperability could occur. Discuss the utility's position'and required actions to insure reliable operation after such a safety valve-lift.
RESPONSE
In general, operation of the Target Rock 69C pilot operated valve was considered
. by EPRI to be stable on the lorg inlet pipe configuration for steam, loop seal-steam, and transition tests. Blowdowns were observed in the 0.4-12.5 percent range, and in every instance the valve was observed to have stable performance and s
operate satisfactorily.. There was no indication of valve flutter during these tests.
Four cold loop seal-water tests were performed at naninal water taperatures Lof 650*F, 550*F and 400*F '( 2 tests). For the initial actuation cycles of each Ltest,. the pilot disc and nmin disc opened within 13% of the valve design set pressure and closed with 3.1 to 23.7% blowdown. In the 550*F water test, the valve cycled opened'and closed seven additional times in response to system repressurizations with opening pressures of 2390-2466 psia and closing pressuree of 2245-2390 psia. namad on upstream pressure data, the valve fluttered during all the water tests..
m m
It is expected that valve flutter will occur with most liquid discharge events, however, the EPRI tests have shown that even under these conditions the valve operates satisfactorily and will reseat with no post-discharge leakage. Addi-tionally, as stated in response to question 1, the EWIB accident is the only accident identified which, based on the UFSAR, would discharge liquid. If nore realistic assunptions are utilized it is felt that liquid relief would be precluded.
To date, through the various transients the plant has experienced, including a loss of all offsite power, the safety valves have never lifted. Safety valve challenges, if any, are reported annually in accordance with the guidelines provided in NUREG-0737 iten II.K.3.3.
These valves are also periodically inspected as part of the Inservice Test program under ASME Section XI to assure they remain capable of performing their safety function. In the unlikely event these valves would ever be required to open to mitigate a transient, it is expected they would only discharge steam and would not be subjected to conditions which would cause damage having the potential to degrade valve operability. If a safety valve were required to open to mitigate an overpressure event, and it is suspected that the safety valve discharged liquid, that valve would be inspected at the earliest opportunity. This should be identified as an open item in the NRC Safety Evalu-ation Report (SER) on this issue. Following receipt of the SER, we will submit the appropriate Technical Specifications to require this inspection following any safety valve liquid discharge. This along with the valve's acceptable performance during the EPRI testing insure reliable operation after any safety valve lift.
c
QUESTION 6 Bending moments are induced on the safety valves and the PORVs during the time they are required to operate because of discharge loads and thermal expansion of the pressurizer and inlet piping. Make a cxmparison of the predicted plant moments with the noments on the valves tested to demonstrate that the cperability of the valves will not be inpaired.
RESPONSE
The maximum bending moments induced in the EPRI Target Rock safety valve exceeded the bending moments predicted for the Beaver Valley 1 safety valves.
The nav4=vn noment tested by EPRI was 258,750 in-lbs. during Test No. 709a.
The largest mment predicted at the safety valve outlet for Beaver Valley 1 is less than 160,000 in-lbs., thus d monstrating functionability for the Beaver Valley 1 safety valves.
A bending moment of 35,600 in-lbs. was induced in the Masonellan test valve during EPRI test no. 53-mi-2S. The navi=vn bending noment predicted for the Beaver Valley 1 PORVs is less than 25,400 in-lbs., thus dmonstrating functionability of these PORVs.
L..
QUESTION 7 The EPRI Test Conditions Justification report stated that a method of demonstrating applicability of the inlet piping for verifying the safety valve stability is to conpare the total pressure drop of the inlet piping for the plant safety valve with the total pressure drop of the inlet piping for the EPRI test valve. The total pressure drop is conprised of a frictional and acoustic wave ocuponent evaluated under steam conditions. Provide a discussion of the applicability of the test inlet piping for demonstrating the safety valve stability in the Beaver Valley Unit 1 plant.
RESPONSE
A conparison of the EPRI test piping arrangment and the Beaver Valley Unit 1 safety valve piping arrangement is provided in our July 1,1982 submittal.
The EPRI Test Conditions Justification Report states that becauso a range of safety valve inlet geometries exists in PWRs and because the inlet piping geometries tested included area changes not generally found in PWRs, a method was required to assess the applicability of test results obtained with the inlet piping geometry /
safety valve design combinations tested, to those existing in PWRs. The nethod developed consists of a ocuparison between the expected total pressure drop for the in-plant safety valve / inlet piping combination to that for the safety valve /
inlet piping conbination tested.
Beaver Valley Unit 1 is the only PWR which utilizes the Target Rock pilot-operated safety valve. As such, the test piping arrang ment was similar to the actual installed piping, and the tast valve was identical to that installed at Beaver Valley Unit 1.
Because of this similarity and the uniqueness of our design, this method of conparison, conparing total inlet piping pressure drop, was not considered to be necessary for the assessment of test results. Addi-tionally, EPRI was unable to provide the pressure drop at the valve inlet for j
hek
-..m.
w
l comparison purposes. In order to calculate this pressure drop it is necessary l
to accurately know the valve opening and closing times. Because of the construc-l tion of the Target Rock safety valve, the disc and stan located inside the pressure boundary, it was not possible to determine stem position and valve opening and closing times. These parameters were not measured during the EPRI tests of the Target acck safety valve.
r EPRI, in their guide for Evaluation of Plant-Specific Results, states in several I
places ( Appendix D, Section B for one) that inlet piping pressure effects associated with valve opening and closing should be calculated for spring-loaded safety valves of the Crosby or Dresser design. In the same guide, Appendix B, Table B-3, the inlet piping pressure differences for valve opening and closing are provided so that the inlet pressure drop conparisons for the spring-loaded safety valves can be performed. EPRI does not provide data for the pilot-
. operated safety valve.
~Since the piping configurations are similar for the test valve and the plant valve l
and since no chatter was reported for any of the tests, it is believed the Target Rock Safety Valve will provide stable operation at Beaver Valley Unit 1.
1 l
l
QLESTION 8 During testing of the Masonellan 20000 series PORV, stroke time was found to be sensitive to actuator supply pressure and actuator supply line size. To achieve the 2-sec stroke time requirenent, the line size was increased and the actuator styply pressure was increased to 60 psig. Review of the EPRI Safety and Relief Valve Selection and Justification report for the Masonellan PORV (Drawing A8529 Rev. B) indicated that a==i-a of 55 psig is allowed to the actuator to prevent component damage. The Beaver Valley plant submittal stated that adjustments are made as required to the PORVs prior to plant cperation to assure the stroke times meet the requirunants. Provide discussion of the basis for the 2-secoext stroke time requirenant and of the action being taken to assure that the required stroke time will be achieved without potentially damaging ocuponents.
RESPONSE
PORV stroke times are provided in the equipment specification sheet for the subject valves and are intended to reflect a time of operation that will not manaa a challenge to the safety valves on opening in the steam relief mode. EPRI tests attaptal to keep the PORV stroke times for the Masonellan valves in the range of two seconds.
Beaver Valley 1 also utilizes two of the three PORVs in the cold overpressure protection system. The analysis which supports our PORV setpoint assumes a 2-second opening time, with a 0.4-second delay for diaphragm pressurization and 0.3-second delay due to signal transmission. In order to achieve this stroke, time, modifications to our PORVs in this system were performed which incraaaari the tubing size and incraamari the air supply pressure to the actuator from 55 peig to 60 psig.
Lw...-
This increased air pressure was evaluated with the valve nanufacturer and determined to be an acceptable change without causing damage to the valve or actuator conponents. Subsequent testing on the PORV and associated accunulator air supply system verified available air capacity and valve stroke time perfor-J mance to be acceptable. These valves are stroke tested when the plant enters a cold shutdown unless the test was performed within the previous three months.
EPRI tests report NP-2670-LD Vol. 6 Table VI-4 also listed PORV tests conducted i
satisfactorily at 60 psig inlet air regulator setting.
\\
e
Questions Related to Thermal Hydraulic Analysis:
QLESTION 9 The submittal does not identify what fluid coditions were used in the thermal hydraulic analysis of the safety valve and PORV piping systs. Provide assurance that the assunptions used include==vi=== loading on the piping system eM consideration of liquid flow conditions.
RESPONSE
During normal operation, a water seal exists upstream of the PORVs. The piping between the pressurizer nozzle and the elbow at node 1091 (see Figure 6-2 of our June 24, 1983 submittal for an illustration of the upstream PORV piping) is steam-filled. The piping fr a the elbow to each PORV is water-filled. The limiting discharge case for PORV actuation is discharge of the water slug, not steam discharge nor cold-overpressurization water-solid discharge. The initial inlet fluid conditions for the water slug PORV discharge case utilized in the specific Beaver Valley Unit I thermal hydraulic analysis are:
'1162.4 btu /lb.,
p = 2350 psia Steam Phase h
=
2350 psia Water Phase:
h 143.5 btu /lb.,
p
=
=
During normal operation, a hot loop seal exists upstream of each safety valve.
The piping between each pressurizer nozzle and each loop seal is steme-filled (see Figures 6-3, 6-4, and 6-5 of the June 24, 1983 submittal). The limiting
- discharge case for safety valve actuation is discharge of the loop seal. Water solid discharge through the safety valves is not included in the design basis (see response to question 1). The initial inlet conditions used in the hot loop 4
seal safety valve discharge analyses are: p 2575 psia, h (steam phase) -
=
1130 btu /lb.
s
As noted in the referenced submittal, the loop seal tenperature profile es assumed to have the same distribution as EPRI Test 917; that is, the eter temperature at the valve as 300*F and as at system saturation tenperature near the steam /m ter interface.
1 4
1 e
[l J
.4
y Questions Related to the Structural Analysis:
Q(ESTION -10 The design of the pilot-operated TaaJet Rock Safety Valve precludes rapid oscillations of the disc. Nevertheless, the EPRI tests with filled loop seals and with water had high frequency pressure oscillation upstream of the valve.
The peak pressure of these oscillations was below 2800 psig, which is well below the allowable pressures for valve inlet piping defined in the Westinghouse report WCAP-10105. However, the anplitude of the oscillations, peak to peak, was as high as 660 psi. The high frequency pressure oscillations could potentially excite high frequency vibration nodes creating bending nonents in the pipe. The Westinghouse report defines allowable bending noments for Level C Service conditions..
Provide one of the following: (1) a ccuparison of allowable bending noments established in NCAP-10105 for Ievel C series conditions with the bending noments induced in the plant piping by dynamic notion and other mechanical loads, or (2) justification for other alternate allowable bending moments with a similar conparison with noments induced in the plant piping.
RESPONSE
The Beaver Valley Unit 1 piping system critical frequency response which includes the' safety valve loop seal region has been determined to be at frequency less than 100 Hz. A review of industry data indicates that lower frequencies, typically on the order of 100 Hz or less, are meaningful in that W may occur at these lower frequencies. The EPRI data confirms this. 'the frequency of the forces and noments potentially induced by the pressure oscillations is expected to be greater than this. Fran the EPRI report NP-2770 Volume 8, March 1983, stable valve performance was observed for the loop seal test. No appreciable pressure
F 9
oscillation occurred during the time the water was being discharged through the valve. Consequently, no significant bending nonent during the pressure oscil-lation phase of the transient will occur.
In our submittal of June 24, 1984, pressure stresses based upon a design pressure of 2485 psig were included with the bending nrments resulting from the deadweight and the safety valve discharge piping loads. Because of the time phasing of the pressure oscillation (during water slug discharge through the safety valve) and the discharge piping loads (subsequent to water slug discharge through the valve) this pressure term and noment term were not added. They do not occur coincidentally. A conparison of the bending noments from the stress evaluation and the allowable mment presented in NCAP-10105 shows that all values are below the allowable. Specifically the maximum allowable noment from Table 4-7 of WCAP-10105 for 6-inch Schalule 160 piping for an internal pressure of 5000 psi is 516 in-kips. The noments for the sum of deadweight and water slug discharge for the conponents listed in Table 6-5 of our submittal at nodes 7280, 5380, and 5370, respectively, are all less than 100 in-kips.
m
Que: tion on PORV Circuitrys QUESTION 11 NUREG 0737, Item II.D.1 requires that the plant-specific PORV control circuitry be qualified for design-basis transients and accidents. Please provide information which denonstrates that this requirement has been fulfilled.
RESPONSE
The PORVs are air-operated valves and the actuator of each PORV is controlled by two solenoid valves. Pressure transmitters on the pressurizer control the solenoids. The control logic requires 2/3 high pressurizer pressure indications frca transmitters PT-RC-455, 456, and 457. These pressure transmitters are part of the reactor protection system and have been replaced with cxmponents which are qualified to IOCA and MSIB environments. The solenoid valves SOV-RC-455C1, 455C2, 455Dl, 455D2, 456-1 and 456-2 and limit switches on the PORVs were also replaced with fully IOCA-and MSIB-qualified conponents during the current refueling outage.
One PORV (PCV-RC-455C) also requires a high-high pressurizer pressure indication from transmitter T'f-RC-444.
The other two PORVs (PCV-RC-455D & 456) require a high-high pressurizer pressure indication from transmitter Pr-RC-445. These transmitters are class lE, safety-related transmitters manufactured by Fischer and Porter Co., and the two circuits are powered from separate trains.
All other conpanents in the control circuitry are located in mild environments.
No credit was taken for the pressurizer relief valves in any accident analysis in the Beaver Valley Unit 1 Updated FSAR except for depressurizing the reactor coolant system after an SGTR with the loss of offsite power. The PORVs are also required for cold overpressure protection. However, neither of these design-basis events creates an adverse environment in the containment.