ML18153B955
| ML18153B955 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 10/23/1989 |
| From: | Stewart W VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.) |
| To: | Ebneter S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| References | |
| 89-750, NUDOCS 8911060252 | |
| Download: ML18153B955 (15) | |
Text
VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 Mr. Stewart Ebneter Regional Administrator October 23, 1989 U S Nuclear Regulatory Commission Region II 101 Marietta Street, N.W.
Suite 2900 Atlanta, Georgia 30323
Dear Mr. Ebneter:
VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNIT 1 DISCRETIONARY ENFORCEMENT PRESSURIZER SAFETY VALVE SETPOINTS I
,'\\7 l-
~ n
- 0 \\
,-,.J
- Serial No.
NO/ETS Docket No.
Licenses No.89-750 50-280 DPR-32 Surry Unit 2 was shutdown on October 13, 1989 to repair a leaking pressurizer code safety valve. Concurrently, Westinghouse notified us of a potential generic issue regarding safety valve testing methodology and the allowable setpoint tolerance.
Specifically, the lift setpoint may change by more than the 1 percent from the original set pressure when the valves are installed at temperature conditions different from those used during the setpoint pressure test.
Because of this potential safety issue, we chose to have the Surry Unit 2 pressurizer code safety valves tested to establish the lift setpoint change due to the temperature difference from the condition with steam to the condition with a water loop seal. The valves were tested at both conditions. The setpoint change from steam to a water loop seal condition ranged from +3.5 to +5.0 percent for the three valves tested. The test results are denoted in Table 1.
Since the Unit 1 safety valves were originally tested and their setpoints established using the same test conditions as the Unit 2 safety valves, the potential exists that the Unit 1 valves would also exceed the 1 % Technical Specification tolerance, if tested.
Therefore, to continue operation of Unit 1, discretionary enforcement is requested based on the potential to exceed the tolerance requirement of Technical Specification 3.1.A.3.c. that requires [safety] valves lift settings shall be maintained at 2485 psig
+/- 1 %. We are requesting discretionary enforcement until December 1, 1989, in order to allow time to work toward a resolution of this issue.
Engineering evaluations were performed on the accident scenarios that cause significant pressure transients (i.e., Locked RCP Rotor, Loss of Feedwater, Feedwater Line Break, Rod Ejection, and Loss of Load.)
The analyses showed that the conclusions of the existing licensed safety analysis *remain valid,(i.e., peak RCS
~iJ 10*02s2 091023 p
DOCK 05000280 PNU
e pressure r~mains below the 110% design overpressure limit) for safety valve lift setpoints as high as 5.4% above the nominal setpoint of 2485 psig.
We will also be working with the Westinghouse Owners Group and the NRC staff to resolve this potential generic issue during the requested discretionary enforcement period.
As discussed in telephone conference calls with the NRC staff, we are providing our Justification for Continued Operation of Unit 1.
The Justification for Continued Operation includes a summary of the analysis work and the compensatory measures that will be taken to avoid conditions which could be impacted by relaxed safety valve lift setpoint tolerances. The compensatory measures that will be implemented include taking credit for the reactor trip on turbine trip and the required operability of a power operated relief valve (PORV).
Should you have any further questions or require additional information concerning this action please call.
Very truly yours,
"\\ L ct.. -+-
- w. -~
W. L. Stewart Senior Vice President - Power Attachments:
- 1. Table 1 Safety Valve setpoints
- 2. Justification for Continued Operation 3 Westinghouse Letter - VRA-89-718 cc:
U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, D. C. 20555 Mr. W. E. Holland NRC Senior Resident Inspector Surry Power Station
TABLE 1 PRESSURIZER SAFETY VALVE TEST RESULTS
PRELIMINARY PRESSURIZER SAFETY VALVE TEST RESULTS VALVE NO.
2-RS-SV-2155A 2-RV-SV-21558 2-RV-SV-2155C AS-FOUND Steam Water
-2.1
+2.9
-0.9
+2.7
+0.5
+4.0 DIFFERENCE 5.0 3.6 3.5 The results are in percent change relative to 2485 psig
I i
4 e
ATTACHMENT 1 JUSTIFICATION FOR CONTINUED OPERATION
ATTACHMENT 1 JUSTIFICATION FOR CONTINUED OPERATION Pressurizer Safety Valve Set Pressure Deviation Surry Units 1 and 2 A potential 10CFR50.59 unreviewed safety question is identified in Westinghouse internal memo NS-PL-RCLCL-89-396 (Generic Pressurizer Safety Valve Set Pressure Deviation, dated October 5, 1989.)
Recent test data indicate that the pressure at whicn a pressurizer safety valve (PSV) will lift may change by more than the allowable setpoint tolerance defined in the Technical Specifications when the valve is tested and reset at conditions different than the as-installed conditions.
This report
.provides a safety evaluation to justify continued operation of Surry Unit 1, and to indicate the measures planned to resolve the issue for Surry Unit 2 in light of identified and potential deviations in the pressurizer safety valve (PSV) lift setpo1nt beyond the allowable tolerance.
Testing of several Crosby 6M6 forged body and cast body pressurizer safety valves was performed by Westinghouse using a
loop seal configuration with 300°F water in the loop.
The loop seal was then drained and the set pressure was checked with steam.
The valve set pressure was observed to drop approximately 4% to 8%.
It was concluded that plants which set their safety valves on steam and install them on hot or cold water l cop seals may have se~ pressures higher than the desired 2485 psig +1% (T.S. 3.1.A.3.c).
Surry Unit 2 was recently shut down so that leakage from the 11 8 11 pressurizer safety valve could be corrected. While the unit was shutdown, the potential unreviewed safety question described above was identified.
It was determined that the most prudent course of corrective action was to ship all three valves to the Westinghouse Western Service Center so that they might be (a) tested at as-found conditions with steam, (b) tested at as-found conditions in a loop seal configuration, and (c) adjusted to the proper setpoint and tolerance for a loop seal configuration. This issue for Surry Unit 2 will be resolved through this action.
The data from these tests will provide information on the expected condition of the Unit 1 v~lves.
For the currently operating Surry Unit l, a Justification for Continued.
Operation (JCO) must be provided which will provide adequate assurance of the safety of the operating*unit under postulated accident conditions.
Toward this end, an evaluation of the impact of potentially deviated PSV lift setpoints on the UFSAR transients has been performed. The transients which are most severely affected by the inoperability of the pressurizer safety valves were reanalyzed.
The results of the transient analysis evaluations and reanalyses provide indicati~n of what compensatory measures, if any, are necessary to assure safe operation of Surry Unit 1 for the remainder of Cycle 10.
Westinghouse provided the results of a sensitivity study applicable to the V.
C.
Summer (SCE&G) and Diablo Canyon (PG&E) plants which SPSJCO
indicates the impact of increased PSV set pressures on each of the following transients:
Loss of Load/Turbine Trip, Main Feedline Break, Locked Rotor, and Rod Ejection. Their results indicate that the transient pressure in each of these transients remains below 120% of design pressure (the faulted condition stress limit).
In a similar study performed by Virginia Power for Surry, the Loss of Load/Turbine Trip, Locked Rotor, Main Feedline Break, RCCA Ejection, and Loss of Normal Feedwater transients were evaluated.
The results of this study are summarized in the following.
EVALUATION OF UFSAR TRANSIENTS Virginia Power has evaluated the UFSAR transients and determined that the Loss of Load/Jurbfne Trip, Locked Rotor, Main Feedline Break, and RCCA Ejection, and the Loss of Normal Feedwater transients are potentially affected by a deviation in the PSV lift setpoint.
The Loss of Load/Turbine Trip and the Locked Rotor were reanalyzed and the remaining transients reevaluated to determine the impact on safety analysis of a PSV lift setpoint deviation as high as +10%.
In the Loss of Load/Turbine Trip and Loc~ed Rotor analyses, it was presumed that the PSV's did not function at all. The conditions assumed in the reanalyses are equivalent to, or are conservative with respect to, the conditions of the current
.licensing analysis unless otherwise noted.
An overpressure safety limit of 2750 psia (110% of design pressure) was assumed for the analyses and evaluations performed in support of this JCO.
LOSS OF LOAD/TURBINE TRIP For the case of the Loss of Load/Turbine trip in which the PSV's are assumed to be inoperable, the maximum reactor coolant system (RCS) pressure exceeds 110% of design pressure.
However, the maximum pressure remains below 120% of design pressure.
If either a Reactor Trip on Turbine Trip or the operation of a single pressurizer PORV is assumed, peak RCS pressure remains below 1101 of design pressure.
It may be concluded that with no action to compensate for potentially inoperable PSV's, the maximum RCS pressure remains below 120% of design pressure in a Loss of Load transient. If a Reactor Trip on Turbine Trip or operation of a single PORV can be assured, peak RCS pressures will remain below 110%
of design pressure in the Loss of Load transient.
LOC<ED ROTOR For the case of the Locked Rotor transient in which the PSV's were assumed to be inoperable, peak RCS pressure remained below 1101 of design pressure.
The inoperability of the PSV's negligibly impacts the RCS overpressure results of the current licensing analysis.
MAIN FEEDLINE BREAK The Main Feedline Break (MFLB) transient.is not a part of the formal licensing basis for Surry.
However, the MFLB transient was analyzed to permit comparison of the thermal/hydraulic conditions at the PSV inlets to condition~ employed in valve tests conducted by EPRI. It was concluded SPSJCO
e that the pressurizer safety valves can be expected to perform adequately under MFLB conditions, even with a deviation in PSV lift setpoint pressure as high as +10%, since the thermal hydraulic conditions that would be experienced in the applicable MFLB scenario with these PSV lift setpoints are within the EPRI test conditions.
LOSS OF NORMAL FEEDWATER The evaluation of the Loss of Normal Feedwater (LONF) transient concluded that a +10% deviation in the PSV lift setpoint would result in a peak RCS pressure during a LONF of less than or equal to 2750 psia.
If either a single PORV or the high pressurizer pressure reactor trip is actuated, the maximum pressure attained in this transient is not high enough to cha 11 enge the nominal PSV 1 i ft setpoi nts.
Because the high pressurizer pressure reactor trip is a safety-grade reactor trip, it may be concluded that the peak pressure in a LONF transient will remain below the nominal PSV lift setpoint of 2500 psia.
ROD EJECT ION The evaluation of the Rod Ejection transient concluded that the peak pressure attained in a Rod Ejection transient will remain well below the nominal. PSV setpoint of 2500 psia.
A high PSV setpoint, or even inoperabla PSV's, does not impact the results of the Rod Ejection transient analysis.
CONCLUSIONS It may be concluded from the results of the UFSAR transient evaluations and reanalyses that the maximum overpressure attained in any UFSAR transient will remain below 2750 psia (110% of design pressure) wtth PSV setpoint deviations up to +10%.
This conclusion is based on the assumption that operation of either the Reactor Trip on Turbine Trip or a single pressurizer PORV can be assured. Peak RCS pressures in all UFSAR transients will remain below 120% of design pressure under current UFSAR
. assumptions for setpoint deviations up to +20%
RECOMMENJATIONS Should the test results of the Unit 2 PSV lift setpoints indicate that the Unit 1 PSV setpoints may be deviated beyond the tolerance allowed by T.S. 3.1.A.3.C, discretionary enforcement of the Technical Specification requirement will be required.
It is recommended that administrative procedures be implemented for the remainder of Surry Unit 1 Cycle 10 which insure the availability and operability of the Reactor Trip on Turbine Trip and a single pressurizer PORV.
Both systems should be maintained available and operable since the pressurizer PORV's are not required to be available at power, and since the Reactor Trip on Turbine Trip is not a safety-grade trip.
These compensatory measures wi 11 insure that transient pressures under postulated accid.ent conditions will remain below 110% of design pressure for PSV setpoint deviations up to +10%.
The pressure integrity of the primary system components is thereby assured.
SPSJCO
e ATTACHMENT 2 WESTINGHOUSE LETTER PRESSURIZER SAFETY VALVE SET PRESSURE DEVIATION
Westinpouse EJectrlc Corporation Eneru Systems Mr. W.R. Cartwr\\ght. v;c, President Nuclear Operations Virginia Power Innsbrook T*chnical Center 5000 Dominion Boulevard Glen Allen, Virg1n1a 23060
Dear Mr. Cartwright:
Virginia Power e
- Box 356 P1Ttsour,i Pennsy1van1a 15230-03~~
October 16~ 1989 VRA-89-718 Surry Units 1 and 2, North Anna Units 1 and 2 Pressurizer Safety Valve Set Pr1s1ur1 Deviation This letter is to provide you with information related to a potential deviation of the pressurizer safety valve set pressure from the ASME Code and the plant technical specification raquirements. This information is being provided for your evaluation following review by the Westinghouse Safety Review Caamitt*
(SRC). Based on an evaluation of th* available information, the SRC concluded that this issue does not constitute a substantial safety hazard and, 11 such is not reportable by Westinghouse to the NRC undar 10CFR Part 21.
The SRC then evaluated the significance of this issue utilizing the criteria of 10CFRS0.59.
From this evaluation, the SRC concluded that the information should be connun1cated to various utilities for their evaluation.
SYNOPSIS ASME Section III defines set pressure and provides an opening pressure tolerance that 1s spec1f11d in parcent of the sat pressure for pressures above 1000 psi. Typically, the 11t pressure for the pressurizer saftty va1v11 is
- 2485 psig +1% in plant Technical Specifications. Recant plant operating experience-and test data 1ndicat1 that the opening pressure changes by 1DOra than one percent fram the original set pressure when the valve is 1nsta11ed at temperature conditions different from tho11 used during the set pressure test. It has been observed that a shift of 4 to 8 percent can occur. Thia
. potentially plaeia th.; pllflt 1n v1o1at1on of Technical Spacification1. ASME Codi Sections III/XI requ1reaents, and thus, outside the bounds of the plant lieens1ng basis cr1ter1a.
IDENTIFICATION OF ISSUE In 1989 two ut111t1es. South Carolina Electric and 611 (SCE&G) and Pacific Gas and Electric (PG&E). conducted Crosby pre11uriz1r 11fety valve tasting at the Westinghouse Western Strv1ce Center (WSC).
The valve testing included Crosby 6M6 forged body (V.C. SU11111r) and cast body (Dia.blo Canyon) valve de1i9ns.
October 16, 1989 Page 2 The set pressure tests were performed using a loop seal conf1gurat1on. Test conditions included the control of ambient air temperature to simulate as-insta11ed plant conditions and 1etting the valves to 2485 paig +1% using approximately 300°F hot water in the loop. The loop seal was subsequently drained and the set pressure checked with steam.
The valve set pressure dropped approxi1nately 4% to~.
Based ~n the testing performed at the WSC, it has been determinld that set pressure changes as a function of temperature. Plants setting their valves on steam and installing them on hot or cold water loop 11111 have a resultant set pressure higher than 2485 psig +ll. Since the trend is for the set pressure difference to increase as the temperature difference increases, setting valves on steam and installing them on a cold loop seal will result in the largest set pressure increase.
The FSAR licensing basis analyses were evaluated s;nce pressurizer safety valve set points above th1 nominal 2500 psia +li value could have a potential adverse impact on the FSAR licensing basis criteria, where credit i1 taken for safety valve re111f,.1pec1f1cally the Loss of Load/Turbine Trip, Feedline Break, Locked Rotor and RCCA Ejection analyses were examined.
Typica.lly, in 1ac:h of the1a analy111, th1 pressurizer aafety valves (PSVs) are actuated and provide sufficient relief capacity which limits the peak pressure in the RCS to an acceptable value. Should the PSV 1et pre11ur1 be increased.
the 1111rgin to the 1111x1mum allowed pressure for each of these events would be potentially reduced to a point where th, lic1n1ing*b11i1 criteria would no longer be satisfied.
Westinghouse has performed sensitivity studies on the impact of increased PSV set pressures for each of the four potentially affected transients. Th*
results of thesa analy11s are contained 1n the Justification for Continued Operation section of this letter.
Similarly, the effect of I lost loop seal during normal plant operation and
. Pressurizer Safety relief transient conditions have been reviewed for the c11*
in which a Pressurizer Safety Valve has been set and is installed in a loop
- seal configuration.
If the loop 1111 1s loat 11 a result of a transient lifting the PSV, the PSV is QXposcd to =~am at the valve seat ind I r@duction in.. t pr111ur1 due to
- th1 increase in temperature is experienced. The reduction of the v1lv1'1.. t pressure from the nominal value of 2500 ps1a to the PORV,~t pressure and actuating at that point, does not affect the licensing basis criteria since no credit is taken for the PORV1 in the licen1in;_ba1i1 &naly1i1. A further set pressure reduction to the maximua 8S below 2500 psia ia not expected to violate the licensing criteria, however, confinaation would require plant specific analysis or evaluation.
October 16, 1989 Page 3 If the loop seal 11 lost during normal,plant operation, the PSV is exposed to steam at the valve seat and a reduction in set pre11ure due to the increase in temperature is experienced.
The reduction of the valve's set pressure fr0111 the nominal value of 2500 psia to a level which opens during normal plant operation is bounded for one PSV as defined by the current analysis of an inadvertent opening of a PSV.
SAFETY ISSUE The pressurizer safety valve is classified 11 a Safety Class l component and is required to prevent the pressure in th* reactor coolant system from exceeding its design condition, typically 110 percent of 2485 psig (2500 psia). The deviation of the set pressure varies froa 4 to 8 percent as seen under various loop seal conditions. This set pressure deviation is outside the bounds of ASME Code Section III and XI requirements and should be reviewed by each utility in conjunction with their Techn;cal Specification.
ASME Code Section III is not met since the iet pressure of the pressurizer safety valves is outside the opening tolerance specified. Likewise, ASME Code Section XI for inservic* tasting requires valves not exceed the stamped.. t preasure criteria by more than 31.
CONCLUSION As a result of the tests conducted at the Westinghouse Western Service Center, it has b.. n determined that the pressurizer safety valve aet pressure will vary based on the methodology used 1n setting the valves.
The variance occurs when the valve is set at conditions other than 1a1*in1tall1d 1
That is, when either the test media or u*>ient tlq)er1tur1s differ from the operating media and lllbient t~ratures a set pressure shift ii possible. Crosby 6M6 desiwn valves set with hot water and ambient air ~r1ture1 of approxiaately 300 F and 13o*F, respectively. experienced a set pressure shift of 41 to 8S when the test media was changed to saturated st1111. Thus, setting a valve at plant ambient air with steam as a Melia and installing it on a loop IHl filled with 300*F water can result in a set pr111ur1 41 to 81 higher than ant;cipated.
Note that similar data doea not exist for other 11f1ty v1lv1 sizes, designs, or other plant specific tllllperatures.
Crosby Valve and Gage Co. a;r.. 1 that the valve **t pressure should be established at temperatYntl representing 1s-inst1lled aedia and ambient
- temperatures.
RECCMitENDA TI CNS Utilities should review the existing 11ethodologi11 that are currently in practice at their plants relative to settin; and testing of pre11urizar safety
October 16, 1989 Page 4 valves, their current FSAR analyses and the licensing bases for the plant to determin* their compliance with safety valve set pressure tolerances as specified in thetr Technical Specification.
The FSAR licensing basis analyses were evaluated since pre11urizar 1afety valve-set points above the nominal 2500 psia +li value could have a potential adverse impact on the FSAR licensing basis criteria, where credit is taken for safety valve relief, specifically the Loss of Load/Turbine Trip. Faedline Break, Lacked Rotor and RCCA Ejection analyses were examined.
Typically, in each of these *analyses, the pressurizer safety valves (PSVs) are actuated and provide sufficient relief capacity which limits th* peak pressure in the RCS to an acceptable value. Should the PSV set pre11ure be increased, the margin to the max1IIUIII allowed pressure for each of these events would be pot1ntially reduced to a point where the licensing ba1i1 criteria would no longer be satisfied.
Westinghouse has performed sensitivity studie1 on the impact of incr*ased PSV set pressures for each of the four potentially affected transients.
The following s1nsitivity studies were performed on the impact of ;ncreased PSV set pressures for each of the four potent1111y affected transients:
Loss of Load/Turbine Trip For the loss of load/turbine trip analysi1, sensitivity studies show that with no credit taken for any relief capacity frcm lither the PSV1 or thl PORVs, the peak RCS pressure exceeds 11()1 of design (the licensing basis 11m1t for this Condition II event).
- However, the pressure r1111in1 below 120% of design and thus, the peak RCS pr*11ur1 does not cau.. 1trea111 to exceed the faulted condition stre1s limits. This 1n1ly1i1 is baaed u;,on the analysis documented 1n the FSAR, and all of the conservative bounding assumptions are applied.
Fffdlina Break For the feed11ne break event, Westinghouse has perforaed 1n1ly111 which demonstrate that withal~ incr1111 1n the PSV sat pressure, from 2500 psia to 2750 psi1, the 11111.. RCS pr111ure remain, below 120S of design.
In add1t1on, the core reaa1ns covered throughout the transient and no ov1rprossuriz1tion of the s.condary 1idt occurs. This 1nily111 does not take credit for beat e1t1111te oparat1on or PORVa. ind retains the conservative 111Uiii)t1on1 which art pro1sntad in the FSARe Thu1 9 the peak RCS pressure does not cause stresses to exceed the faulted condition stress limits.
October 16, 1989 Page 5 Locked Rotor Westinghouse h11 perforaed locked rotor analyses for a t,YJ:1ical 2 loop plant, which bounds 3 and 4 loop plants. This analysis makts similar conservative assumptions to those found in the FSAR analysis.
No credit was taken for any relief capacity from the PSVs or PORVs.
The maximum RCS pr111ur1 remains below 120S of design. Thus, the peak RCS pr111ure does not cause stresses to exceed the fau1ted condition stress limits. There 11 no adverse impact upon the rods-1n-DNB or the peak clad t.._,.ratur1 analyses documented in the FSAR.
RCCA Ejection Westinghouse has perfor1111d a bounding ov1rpr1s1uriz1tion analy1i1 for the RCCA ejection event which is documented in WCAP-7588.
This analysis is performed under BOL HFP conditions and mak*t ~xtrGliily con;erv=tivs ass~tions regarding ejected rod worth.
The PSVa are 11suaed operable with a.et pressure of 2500 psia. The peak pressure 11 calculated to be less than 2800 psia. A 10% increase (250 psi) in th* PSV set pressure would increase the peak pre11ure by no more than 250 psi. resulting in a peak RCS pressure of 3050 psia. This 11 greater than 120% of design pr111ure. However, 11 discussed in WCAP-7588. a more detailed, but still conse,-.,at1ve analysis, using 3D methodology calcu1ated a peak RCS pressure less than 2600 psia. Thus. even with the additional 250 psi bias due to the 10S setpoint shift, the pressure.will r11111in le11 than 2850 psi1 which 1s below 120% of design.
In addition, this analysis used an extr1111ely conservative *J*ctad rod worth esti.. ted at 2 to 3 times greater than the conservative values typically pr,.. nttd 1n the FSAR.
Lower, but still conservative, ejected rod worths would yield low,r RCS pr111ur11.
- Thu1, 1v1n under conservative 111umption1 1 the ~k RCS pressure will not exceed that which would c1u1t 1tre11ts to exceed the faultld condition stress 11*1 ta.
Based on the results of theae sens1t1v1ty studies, the calculated pressure spikes for these tr1n1iant1 do not ch1ll1ng1 the pressure integrity of the pri111ry system camponenta.
Similarly, the effect of a 1oat loop aeal during noraal plant operation and Prasiuriz~r Safety relief tr1n1ient conditions have been reviewed for the case in which a Pre11ur1zer Safety Valve has been set and 11 1n1t1111d in a loop seal configuration.
If the loop seal is lost 11 a result of a tranaient liftin; the PSV. the PSV is exposed to steam at the va1ve seat and a reduction in Ht pressure due to the increase in temperature 11 experienced.
The rlduct1on of the valve's set pressure fram the nominal value of 2500 psia to the PORV set pre11ure and actuating at that point, does not affect the 11cansing ba1i1 criteria since no
(
October 16, 1989 Page 6 credit 11 taken for the PORV1 in the licensing basis analysis. A further set pressure reduction to the aax1mum 8S below 2500 psia is not expected to violate the licensing criteria. however. confirmation would require plant specific analysis or evaluation.
If the loop seal is lost during normal plant operation, the PSV is exposed to st1111 at the valve seat and a reduction 1n.. t pressure due to the increase in temperature 11 experienced.
The raduction of the valve's set pressure fram the nominal v1lu. of 2500 pa1a to a level which opens during normal plant operation is bounded for on1 PSV as defined by the current ana1y1i1 of an inadvertent opening of I PSV.
Should you hav1 any questions or require further inforaation on this matter.
please contact ae.
HT)5303G cc: W. R. Matthews W. M. Adus R. M. AnderHn W R.H. Blount M. L. Bowl 1ng D. J. Burke R. W. Calder D. A. Christian W. D. Corbin R. O. Enfinger E. S. Gr1chack R. J. Hardwick. Jr.
D. A. Heacock J. Headden W G. E. Kane -
D. A. Sonars J. D. Hegner Very truly yours~
- ..J)..,JJ~~
D
- R. Beynon. Jr.
- Manager Customer Projects Department Virginia Area M, R. Kinsler J. N. McCarthy H. L. Mi 11tr J. W. ~ren J.P. 0 Hanlon
- 6. L, Pannel 1 R, W, Riley L. H. Robarts W W.R. Runner, Jr.
R. F. Saunders J, A. Stall T. B. Sowers W.W. Wigley J. L, Wilson E.W. May T. E. Shaub