ML20238A984
| ML20238A984 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 08/24/1987 |
| From: | Fay C WISCONSIN ELECTRIC POWER CO. |
| To: | NRC OFFICE OF ADMINISTRATION & RESOURCES MANAGEMENT (ARM) |
| References | |
| CON-NRC-87-83, RTR-NUREG-0737, RTR-NUREG-737, TASK-2.D.1, TASK-TM VPNPD-87-359, NUDOCS 8709010020 | |
| Download: ML20238A984 (27) | |
Text
,
l Wisconsin Bectnc vom coupw i
231 W. MICHIGAN, P.O. BOX 2046 MILWAUKEE,Wl 53201 (414)277 2345 VPNPD-87-359 l
i August 24, 1987 U.
S.
NUCLEAR REGULATORY COMMISSION Document Control Desk i
Washington, D.C.
20555 l
{
i Gentlemen:
l l
DOCKET NOS. 50-266 AND 50-301 NUREG-0737 ITEM II.D.1
{
PERFORMANCE TESTING OF RELIEF AND SAFETY VALVES
)
POINT BEACH NUCLEAR PLANT l
)
This is in response to your letter (Reference 1) dated July 2, 1987 which requested additional information from WE in order to complete your review of our analyses and modifications as a i
result of NUREG-0737, Item II.D.1.
Questions identified in your letter and our responses are provided below.
l i
1)
NRC QUESTION j
Please verify the pressure drop values given previously.
)
Present a recalculation of the total pressure drops for the inlet piping of the Point Beach, Units 1 and 2, safety valves and the applicable EPRI inlet piping arrangement.
The total pressure drop should include both the frictional and acoustic wave components evaluated under steam conditions.
Provide a similar comparison for the pressure rise on valve closure.
RESPONSE
The safety valve inlet piping pressure drop values provided in our response to Question 9 of Reference 2 were based on friction losses through the inlet piping under stable flow conditions.
Using the methodology contained in Appendix B of Reference 3, the inlet piping pressure differentials were recalculated.
The results of these calculations and a comparison to Table B-3 of Reference 3 are shown below.
8709010020 870824
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)
NRC Document Control Desk Au"ust 24, 1987 Page 2 1
PBNP EPRI R? port (Reference 3)
Plant-Appendix B, Table B-3 l
Specific Transient Crosby 3K6 Crosby 6M6 AP (psid) w/ Piping "F"
w/ Piping "G"
Valve Opening Case (a) 373
?91 263 Case (b) 229 l
Valve. Closing Case (a) 221 194 181 Case (b) 177 i
Case (a) values for both opening and closing of the safety valves were caletlated for the specific piping inlet i
configuration at PBNP using the valve opening times, acoustic speed, and flow rates taken directly from Appendix B of Reference 3.
These pressure drops compare j
favorably with those determined by EPRI for both the 3K6 and 6M6 valves.
It should be noted that the size and flow rating of the 3K6 valves more closely approximate the 4K26 valve used at PBNP.
Case (b) values were calculated using the same methodology as case (a) values except for the following parameters:
a)
Using the thermodynamic relationships for saturated l
steam at the safety valve setpressure of 2485 psig, the
)
acoustic velocity calculated is 1,973.57 ft/sec.
This j
value was used instead of the Appendix B value of 1100 ft/sec.
b)
A rated flow rate of 288,000 lbm/hr, which is the rated flow of the PBNP safety valves, was used instead of the value of 320,000 lbm/hr in Appendix B.
l i
c)
As previously stated in Reference 4, a 20 msec valve I
opening time is considered conservative based on the l
EPRI test data.
This opening time was used to calculate the valve opening pressure differential instead of 10 msec in Appendix B.
The case (b) values demonstrate that when some of the conservatism is eliminated from the calculations, the pressure differentials are well within the bounds given by the Reference 2 for both valve types.
NRC Document Control Desk hugust 24, 1987 Page 3 As stated in our response to Question.3 of Reference 2, the applicable EPRI Valve Test Program test runs for PBNP are Tests 526, 908, 923, and 929.
No excessive valve chatter was observed in any of these tests.
In each case, the valves performed their pressure relief function and reclosed.
Based on the above discussion, including calculated inlet pipe pressure drops and applicable EPRI test runs, it can be reasonably expected that the 4K26 valves installed at Point Beach will perform their intended function without valve chatter.
2)
NRC QUESTION Identify the fluid transient used in the Point Beach piping analysis and give the assumed fluid parameters, such as the fluid state, peak pressure, temperature, pressurization rate and justify that the fluid condition selected would result in the highest stresses in the piping system.
RESPONSE
'l The most severe reactor coolant system overpressure i
condition requiring operation of the PORVs, or of the PORVs and the safety valves for Point Beach Nuclear Plant would occur as a result of an instantaneous seizure of a reactor coolant pump rotor--: " locked rotor" accident.
The transient analysis for a locked rotor accident conservatively assumes that the PORVs do not. operate and j
that the pressure relief is through the safety valves only.
The peak pressure in this case is 2778 psig with a maximum pressure ramp rate of 297 psi /sec.
The initial fluid conditions of the liquid in the lgop seals upstream of the safety valves are 2778 psig and 300 F.
As the safety valve opens and the loop seal contents begin to clear, some of the liquid is flashed as it passes through the valve.
Since all of the loop seal liquid is not flashed, two-phase flow occurs downstream of the safety valves.
This two-phase flow continues until all the loop seal liquid has cleared.and then only steam is passed through the valves.
The two-phase flow imparts very'high stresses on the piping.
The piping analysis shows that the highest stresses result from the loop seal liquid passing through the piping system.
Since the locked rotor transient
I 1
i NRC Document Control Desk August 24, 1987 Page 4 l
creates the highest peak pressure and highest pressure ramp rate of the transients reviewed, this transient creates.the highest pipe stresses due to the'high peak transient pressure driving the loop seal water through the safety valves and down the piping.
3)
NRC QUESTION In the Point Beach piping thermal hydraulic analysis, only one valve actuation case was considered (Reference 3).
In this analysis, the PORV's were assumed to have the same opening setpressure as the safety valves.
Thus, all four j
valves in the system (two safety valves and_two PORV's) would actuate simultaneously.
The licensees pointed out that since the PORV's were assumed to have a higher setpoint of 2485 psig instead of the actual setpressure of 2334 psig, this analysis should produce conservative results.
Generally, the piping discharge analysis is conducted by 3
]
assuming three valve actuation conditions, namely.(a) the simultaneous actuation of all safety valves with the PORV's closed, (b) the simultaneous actuation of all PORV's with safety valves closed, and (c) the actuation of all PORV's and safety valves in accordance with their setpresbares.
Please verify whether the separate safety valve or PORV discharge conditions described in cases (a) and (b) above have been investigated and provide evidence to justify that the simultaneous safety valve and PORV discharge condition assumed in the Point Beach thermal hydraulic analysis is the limiting condition which produces the maximum loading on the piping and supports.
RESPONSE
When initially determining the assumptions to be selected for the rigorous piping thermal hydraulic analysis, all three valve actuation conditions identified in the question were evaluated as to their potential for generating maximum piping stresses and loads.
It was recognized that actuation of the safety valves would produce high stresses and loads based on the opening time of.the valves (20 milliseconds),
- ke water hammer effect of the fluid contained in the upstream loop seals, and the large AP across the valve.
In contrast, since the.PORVs are slow opening (0.8 seconds) and pass only steam, effects of their actuation on the piping system were considered small in comparison.
- Further, because the pressurization rate for the locked rotor transient for PBNP was high and in order to maximize the AP across the values (and thereby maximize piping system 1
l NRC Document Control Desk August 24, 1987 Page 5 loads), we modelled the PORVs and safety valves as. opening at the peak transient pressure of 2778 psig rather than j
their respective setpressures.
We recognize that the 2778 psig value does not agree with that presented in Reference 4 which states that the analysis assumed both the safety valves and PORVs actuating at the safety valve setpressure of 2485 psig.
This inconsistency was identified as our consultant was reviewing the RELAP model and results while preparing input to these responses.
i We intend to revise Reference'4 to correct this discrepancy and will submit the report to the NRC for your. record.
Although the report is in error, the analysis model assuming all four valves actuate at 2778 psig generates higher system piping loads than for 2485 psig or the.PORV and safety valve setpressures of 2334 psig and 2485 psig, respectively.
As such, the load case we analyzed is conservative with respect to (a), (b) and (c).
To demonstrate this further, a discussion of the loadings on the pressurizer relief piping is provided below. identifies the piping system reference points used in the discussion.
Although Attachment 1 depicts specifically the Unit.2 piping configuration, the systems are essentially mirror images of each other and the discussion below applies to both Units 1 and 2.
a)
Piping Upstream of the Safety Valves (Points A to Points B)
The loads on this portion of piping are induced by actuation of the safety valves and would be identical for the case analyzed and the case of the safety valves I
opening alone.
Actuation of the PORVs alone could not generate higher loads in this portion of the piping system.
b)
Safety Valve Discharge Piping Including the Safety Valve Common Discharge Header (Points B to Point C)
Loads on this portion of the piping are induced by both safety valve and PORV actuation.
The maximum loads are reached within.075 seconds of initiation of the transient.
At this time in the transient, the PORVs are less than 10% open and their discharge has little influence on the system.
Since the loads decrease as the PORV continues to open, the safety valve actuation produces significantly higher loads than would result
NRC Document Control Desk August 24, 1987 l
Page 6 l
from PORV actuation alone.
The loads generated by the safety valve actuation alone would be comparable to those generated by the analyzed case for this portion of piping.
c)
Piping Upstream of the PORVs (Point D to Points E)
During opening of the PORVs, the discharge flow rate of steam is linearly proportional to the flow area and choked flow conditions exist throughout the transient.
Therefore, the case of the PORVs actuating alone would not generate higher piping. loads in this region than those determined by simultaneo's safety valve and PORV actuation.
Actuation of the safety valves alone would not impart higher loads on this region than the case analyzed which included PORV actuation.
d)
Piping Downstream of the PORVs up to the 3
Relief System Common Discharge Header
(
(Points E to Pojnt C)
The peak load in this portion of the piping system occurs approximately.119 seconds from initiation of the transient.
At this time, the PORV is less than 15 percent open.
The timing of the maximum load is consistent with and directly attributable to the safety valve actuation and loop seal clearing and is not significantly influenced by PORV actuation.
Therefore, the peak loading induced in this region of piping as a result of the actuation of the slow opening PORV is not significant when compared to the forces from the safety valve discharge piping.
If PORV loads had been significant, a higher load would have been identified later in the transient as the PORV continued to open.
Because of the relatively low pressures in the PORV discharge line following PORV actuation, the load determined from the analyzed case would not be significantly different from that calculated for actuation of the safety valves alone.
e)
Relief System Common Discharge Header (Point C to Point F)
The loadings on this region of piping are higher for the analyzed case than for either the PORVs actuating alone or safety valves actuating alone.
During the simultaneous actuati.on, the combined discharge of all valves is considered as opposed to either set of valves discharging alone.
l 1
l l
.s i
NRC Document Control Desk August 24, 1987 Page 7 Based on the discussions presented above, we believe that the Point Beach pressurizer relief line system hydrodynamic L
loads from simultaneous actuation of the PORVs and safety valves envelope the loads that could be generated from actuation of the PORVs or safety valves alone.
'l 4)
NRC QUESTION The licensee should verify the' flow rate used in their analysis and modify the analysis to include the effect of safety valve derating if necessary.
RESPONSE
A review of the RELAP analysis indicates that flow through the safety valves ranges from 122 to 111 percent of rated flow during the first 0.11 seconds.. The loop seals fully clear the safety valves in 0.09 seconds and the momentum imparted on the loop seal liquid by-the steam flow through the safety valve carries it down the valve discharge piping (Points A and B to C) and the common header (Points C to F).
Peak loads from Points A to F occur between 0.09 seconds to 0.24 seconds.
Even though the flow reduces below 111 percent of rated flow after 0.11 seconds, the loop seal liquid has reached a maximum velocity and the momentum sill be relatively unaffected by the small decrease in driving pressure.
Additionally, at Point F, where the peak load occurs at approximately 0.24 seconds, the influence on driving force imparted from the PORV more than compensates for the reduction in driving force from the safety valves.
Therefore, we believe that the model sufficiently predicts loads for the pressurizer relief system piping.
5)
NRC QUESTION The load combinations for the piping and support analysis listed in Reference 3 do not include an upset condition in which an operating basis earthquake is combined with a PORV discharge transient.
Therefore, the upset load combination should still be considered as recommended by EPRI.
NRC Document Control Desk August 24, 1987 Page 8
RESPONSE
Reference 2 recommends the following upset load cases for seismic piping.
Upstream of Safety Valves and PORVs:
N + OBE + SOT S
- u h
Downstream of Safety Valves and PORVs:
N + OBE + SOT S1*8 S u
h where SOT is a PORV discharge transient.
These load cases were presOnted generically for plants with and without loop seals and without regard for plant specific piping configurations or valve opening times.
As described in the response to Question 3, a PORV actuation without safety valve actuation load case was not rigorously analyzed.
The load condition selected by WE, which bounds the load cases specified by EPRI, was the faulted load case:
N + SSE + SOT s2.4 S f
h where SOT is the most severe overpressure condition of the g
Since the'PBNP thermal hydraulic l
analysis conservatively assumed the safety valves and PORVs oper, simultaneously, this faulted load case essentially includes both a PORV and safety valve transient.
The following are provided as justification of our approach:
a)
The safety valve loop seal discharge dominated the design of the pressurizer relief piping and supports.
To illustrate this point, reaction time histories for critical Unit 2 supports are shown in Attachment 2.
These plots clearly show that the safety valve discharge of the loop seal excites the PORV and safety valve piping systems such that peak support loads are incurred within.34 seconds of the start of the transient.
At this point, the PORVs are less than half open with choked flow.
Support loads at times greater than.34 seconds decrease as the system damps out.
This indicates that the PORV piping is not strongly influenced by the continued opening of the PORVs.
NRC Document Control Desk August 24, 1987 Page 9 Although only Unit 2 reaction time hiestories have been provided in Attachment 2, given the similarity in configuration, the Unit 1 piping would behave the same way.
The systems are basically mirror images of each other as can be seen by reviewing Appendix B of Reference 4.
b)
A review of the piping stresses upstream of the PORV from the analysis performed for PBNP was completed to further evaluate the acceptability of the system against the EPRI Criteria.
This review actually compared N + OBE + SOT stresses to the 1.2S allowable.
The SOT btresses were used as Nn extremely conservative estimate of the SOT stresses-that would occur as a result of PORV actuaEion alone.
The results show that the PORV upstream piping for Units 1 and 2 could meet the 1.2S all wable using h
these extremely conservative loads except for the area near the PORVs.
The higher stresses in this region can be directly attributed to the safety valve loop seal discharge influence on the piping near the PORVs.
Although the Point Beach analysis did not explicitly evaluate actuation of PORVs alone, a review of the available analysis information concludes that the PORV upstream piping would meet the 1.2S cll wable recommended by EPRI for the h
N + OBE + SOT 1 ad case.
u l
6)
NRC QUESTION Reference 3 (Section 3.4.6) classifies the portion of the piping between the safety valves /PORV's and the pressurizer relief tank as non-seismic class piping.
For this piping, the earthquake 1 cads and internal pressure are not considered in the load combinations and the high allowable stress of 2.4S is used for all load combinations except the h
normal condition.
This means that in case of an earthquake, the integrity of the downstream piping is not assured.
Since the non-seismic class piping is connected directly to the safety valves and PORV's, the arrangement raises the following concerns in the case of an earthquake:
a)
Even if no pipe rupture occurs, the downstream piping could be deformed to such an extent that the discharge flow is restricted and the safety valve operability is affected.
i NRC Document Control Desk August 24, 1987 o
Page 10 b)
In case a pipe snaps, it may in turn cause damage to the connecting valves.
c)
If a pipe rupture occurs, the radioactive release to 3
the containment could pose a potential safety problem.
1 I
Provide a discussion to address the above questions and explain how these problems can be resolved.
RESPONSE
In accordance with established nomenclature for Point Eeach Nuclear Plant, seismic systems fall into a Category 1 Seismic classification and are considered QA Scop 6 covered by the WE Quality Assurance Program.
Designating the piping downstream of the safety valves and POnVs as non-seismic only signifies that they are not included in the QA Scope category for PBNP.
The non-seismic class piping discussed in Section 3.4.6, page 23, of Reference 4 does, however, include earthquake and internal pressure in the load combinations.
The load combinations shown in Table 3-5 of Reference 4 are checked against the allowable stresses shown in Table 3-8 of the report.
A discussion of piping-results_is given in Section 5.5, page 27, of Reference 4.
Tables 5.1 and 5.2 of Reference 4 provide a summary of maximum pipe stress and show that all piping meets allowable limits.
Therefore, the integrity of the non-seismic piping is assured for both earthquake loads and internal pressure.
7)
NRC QUESTION l
a)
Identify the governing structural code used for support design and give the allowable stresses used for support evaluation for various load combinations, b)
Explain why the support load combinations do not include a condition in which the normal load is combined with the safety valve or PORV valve discharge transient.
c)
Provide a numerical comparison of the worst support stresses (or loads) against the allowable stresses (or loads) to demonstrate that all existing supports are acceptable.
L
NRC' Document Control Desk August 24, 1987 Page 11 d)
Provide assurance that the factors of safety required by IE Bulletin 79-02 are maintained for all load case combinations for all supports using concrete anchor bolts.
The required factors of safety are 4.0 for.
wedge type anchors and 5.0 for sleeve type anchors.
]
RESPONSE
I a)
AISC 8th Edition is the structural code used for design.
Table 3-6 of Reference 4 provides the support load combinations.
AISC limits are used for normal and occasional loads and 1.33 times AISC limits are used for faulted conditions in accordance with standard industry, practice.
b)
Pipe support load combinations are shown in Table 3-6 of Reference 4.
Load combination number 3 combines normal (gravity + thermal) with OBE and the safety valve /PORV transient loads.
Load combination number 5 combines normal with SSE and the safety valve /PORV transient loads.
The resulting loads are compared to the allowable limits discussed in the response to question 7a.
c)
A numerical comparison of maximum stress interaction for each new and modified support (actual / allowable stress) is provided in the enclosed Figures 7.1 and 7.2.
A number of spring hanger gravity supports are listed without interactions since these supports were qualified by comparison to previously qualified loads.
I Figures 7.1 and 7.2 demonstrate that all existing pipe supports are acceptable.
d)
A numerical comparison of the highest stressed enchor bolt interactions (actual / allowable load) for each support is shown in Figures 7.1 and 7.2.
A factor of safety of 4.0 for wedge type anchors and 5.0 for sleeve type anchors was used to establish allowable loads for i
all load combinations.
Figures 7.1 and 7.2 demonstrate that the factor of safety required by IE Bulletin 79-02 are maintained for all load combinations.
1
NRC Document Control Desk
.l August 24, 1987
.l Page 12 j
'I We trust these responses provide the'information you require'to complete your review of this issue for Point beach Nuclear Plant.
Should you have additional questions regarding this information, please contact us.
Very truly yours,
{
()nA.jl$ /,/
C. W.
Fay i
Vice President Nuclear Power Attachments I
Copy to NRC Resident Inspector NRC Regional Administrator, Region III i
i
REFERENCES 1)
David W. Wagner,. Nuclear Regulatory Commission' letter to C.
W.
Fay, Wisconsin Electric Power Company, " Request for Additional Information - NUREG 0737, Item II.D.1, Performance Testing of Relief;and Safety Valves (TACS44608 &
44609)," July 2, 1987.
2)
R.
W.
Britt, Wisconsin Electric Power Company letter to H.
R.
Denton, NRC, "NUREG-0737, Item II.D.1, Performance Testing of Relief and Safety Valves, Point Beach Nuclear Plant, Units 1 and 2," March 16, 1985.
3)
EPRI PWR Safety and Relief Valve Test Program Guide for Application of Valve Test Program Results to Plant-Specific Evaluations, Revision 2, Interim Report, July 1982.
4)
Impell Corporation, Evaluation of Pressurizer Safety and Relief Valve System, Final Report. No. 09-0870-0014, Revision 0, July 1984 (Attachment 5 to Reference 2).
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[IGURE 7.1 UNIT 1 SUPPORT INTERACTIONS Max. Steel Max. Held Max. Anchor Support Mark No.
DCP Stress Ratio Stress Ratio Bolt Ratio HS-2501R 15 0.68 0.57 0.40 RC-16 21 (2)
(2)
(2)
RC-18 31 (2)
.(2)
(2)
RC-601R-37 37 0.56 0.80 0.86 HS-250lR-43 43 0.68 0.57 0.40 RC-14 C8B (2)
(2)
(2)
RC-15 50 (2)
(2)
(2)
HS-601R-73 73 0.95 0.76 (1)
RC-17 74 (2)
(2)
(2)
HS-601R-80 80 0.37 0.56 (1)
RC-12 82 (2)
(2)
(2)
R S-601 R-86 86 0.20 0.81 0.74
]
H-200 93 0.06 0.12 (1)
)
RC-13A 95 (2)
(2)
(2)
HS-2501R-22A 22A 0.64 0.81 0.71 HS-601R-37A 37A 0.03 0.15 0.29 HS-2501R-51 51 0.64 0.81 0.71 RS-60lR-85 85 0.55 0.88 0.77 RS-60lR-89A 89A 0.87 0.80 0.84 HS-601R-90 90 0.26 0.43 0.75 RS-60lR-92 92 0.97 0.56 0.52 HS-601R-92A 92A 0.59 0.67 0.93 NOTES:
1.
Anchor bolt ratio not shown because concrete anchor bolt not used J
on this support.
2.
Spring hanger supports previously. qualified were not requalified as part of this project if the new loads for these supports were less than or equal to the previously qualified loads.
I 1
ELGURE 7.2 UNIT 2 SUPPART INTERACTIONS Max. Steel Max. Held liax. Anchor Support Mark No.
DCP Stress Ratio Stress Ratio Bolt Ratio HS-2501R-15 15 0.50 0.47 0.77 2RC-14 21 (2)
(2)
(2)
RS-60lR-36 36 0.34 0.84 0.52 HS-2501R-43 43 0.50 0.47 0.77 2RC-15 44 (2)
(2)
(2) 2RC-13 50 (2)
(2)
(2) l HS-30 72 0.30 0.95 0.53 2RC-10 73 (2)
(2)
(2)
HS-29 80 0.30 0.95 0.53 2RC-ll 81 0.99 0.84 0.72 RS-60lR-83 83 0.74 0.996 0.75 i
RS-601R-85 85 0.37 0.90 0.94 1
2RC-12 92 (2)
(2)
(2)
H-200 99 0.74 0.76 (1) l HS-2501R-21A 21A 0.66 0.81 0.91 l
HS-601R-37 37 0.13 0.32 0.57 HS-250lR-49 49 0.66 0.81 0.91 RS-601R-89B 898 0.76 0.96 1.00 RS-60lR-91 91 0.57 0.89 0.87 RS-601R-93 93 0.69 0.74 0.94 RS-60lR-94 94 0.63 0.96 0.94 HS-601R-95B 95B 0.79 0.74 0.76 NOTES:
1.
Anchor bolt ratio not shown because concrete anchor bolt not used on this support.
2.
Spring hanger supports previously. qualified were not requalified l
as part of this project if the new loads for these supports were less than or equal to the previously qualified loads.
,