ML20217N938
| ML20217N938 | |
| Person / Time | |
|---|---|
| Site: | Hatch  |
| Issue date: | 08/21/1997 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20217N915 | List: |
| References | |
| NUDOCS 9708260391 | |
| Download: ML20217N938 (11) | |
Text
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- g fife ye UNITED STATES
- Ig NUCLEAR REGULATORY COMMISSION J WAaHINGToN. D.C. acceHoot
- % ...../
SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION FOR THE THIRD 10-YEAR PUMP AND VALVE INSERVlCE TESTING PROGRAM SOUTHERN NUCLEAR OPERATING COMPANY. 1HC.
HATCH. UNITS 1 AND 2 DOCKET NOS. 50-321 AND 50-366
1.0 INTRODUCTION
Title 10 of the Code of Fedent Reculations (10 CFR), Section 60.55a. requires that inservice testing (IST) of certain Amer'can Society of Mechanical i Engineers accordance(ASME) Code Class 1, 2, and 3 pumps and valves are performed in with ASME OM Code 1990 Edition, exce)t where relief has been requested and granted or proposed alternatives lave been authorized by the Commissionpursuantto10CFR50.55a(f)(6)(1),(a)(3)(i),or(a)(3)(ii). In order to obtain authorization or reitef, the licensee must demonstrate that:
(1) conformance is impractical for its facility; (2) the proposed alternative provides an acceptable level of cuality and safety; or (3) compliance would result in a hardship or unusual cifficulty without a compensatir.g increase in the level of quality and safety.
Section 50.55a(f) meet the requireme(4)(iv) provides nts set forth that inservice in subsequent editionstests and of pumpsthat addenda andare valves may incorporated by reference in 10 CFR 50.55a(b), subject to the limitations and modifications listed, and subject to Commission approval. NRC guidance contained in Generic Letter (GL) 89-04, " Guidance on Developing Acceptable Inservice Testing Programs," provided alternatives to the Code requirements determined to be acceptable to the staff and authorized the use of the alternatives in Positions 1, 2, 6, 7, 9, and 10 provided the licensee follows the guidance delineated in the applicable position. When an alternative is proposed that is in accordance with GL 89-04 guidance and is docum6nted in the IST program, no further evaluation is required; however, implementation of the alternative is subject to NRC inspection, in a letter dated September 15, 1995, Georgia Power Company (GPC), lictosee '
for the Edwin 1. Hatch Nuclear Power Plant, Units 1 and 2, submitted its Third 10-Year Interval IST Program for Pumps and Valves. The licensee's submittal included several proposed relief requests, deferred test justifications, and other tactions of the licensee's IST program developed according to the requirements of the ASME OM Code 1990 Edition for pump and valve-testing, with the exception of safety relief valves. Safety relief valve testing was written to the requirements of the ASME OM Code 1995 Edition.
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By letter dated April 12, 1996, the NRC transmitted a Safety Evaluation (SE) that provided the staff's review of the licensee's IST relief requests.
Two relief requests were denied and one relief request was granted on a provisional basis. In addition, four relief requests, which were granted on an interim or provisional basis during the second 10-year interval, did not address the concerns of the staff. Therefore, the licensee was requested to provide a response to the specific issues raised in the evaluation within 60 days of the date of the third 10-year interval SE. In a letter dated June 4, 1996, the licensee addressed the items that were denied, required c.
response within 60 days, or were granted provisionally. Also, the licensec
)rovided an additional responso dated July 24, 1996, in which revisions to Relief Requests RR-V-4, RR-V-8, and RR-V-9 were submitted. On December 2, 1996, the licensee submitted a revised Relief Request RR-P-10, which included its evaluation of test parameters under current operating conditions, due to a recent power uprate. In addition, the licensee submitted new Relief Request RR-P-12 that addresses the use of control room instrumentation for high-pressure coolant injection (HPCI) discharge pressure monitoring during performance of the IST. The results of the staff's review of the licensee's submittals dated June 4s July 24, and December 2, 1996, have been addressed in an SE dated July 7, 1997, i
The discussions below concerns new and revised relief requests that were submitted by the licensee in letters dated January 30 March 7, and March 25, 1997. The January 30, 1997, letter included revised Relief Requests RR-G-1 and RR-V-7 in response to the NRC SE dated April 12, 1996. The March 7 and March 25, 1997, submittals provided two new relief requests, RR-P-13 and RR-P-14, respectively.
2.0 REVISED RELIEF REQUEST RR-G-1 RR-G-1 proposes to use ASME OM-1990 for inservice testing of pumps and valves, with the exception of safety relief valves, for which ASME OM-1995 will be used. The NRC's SE dated April 12, 1996, stated that this proposed alternative is authorized sursuant to 10 CFR 50.55a(a)(3)(1) but that the licensee should indicate t1at the requirements of Appendix I augment the rules of Subsection ISTC in its IST program. In the submittal dated January 30, 1997, the licensee revised RR-G-1 in accordance with the NRC's SE dated April 12, 1996. This issue is therefore resolved.
Thus relief is oranted because the alternative provides assurance of component integrity.
3.0 REVISED REllEF RE0 VEST RR-V-7 RR-V-7 requests relief from the exercising requirements of ASME OH-1990, Paragraphs ISTC 4.S.1 and 4.5.2, for the HPCI suppression pool pump suction check valves 1(2)E41-f045. The licensee has proposed to disassemble and inspect the valves every second refueling outage. This revised relief request is in response to the SE dated April 12, 1996, which stated that the testing and inspection plan for these valves should be clarified.
l 3.1 Licensee's Baris for RtA Rstina Relief 1he licensee stated the following:
This normally closed check valve is located on the HPCI pump suction line
.from the suppression pool. The valve does not experience flow during any normal mode of reactor operation or shutdown conditions or during HPCI pump surveillance testing. The normal suction source for the HPCI pump is the condensate storage tank (CST) for periodic surveillance testing and ECCS { emergency core cooling system? injection. The pump suction transfers to the suppression pool upor. 'ndication of a low water level in the CST which would only occur during an extended HPCI injection because 100,000 gallons of water are always maintained in the CST for ECCS usage.
Forward flow exercising this valve would require aligning the HPCI pump >
suction to the suppression pool and discharging to the CST. This flow path would significantly degrade the water quality in the CST.
3.2 Alternate Testini The licensee proposed the following: (as stated)
For each unit (1 valve / group / unit), every other refueling outage [,)
the valve will be disassembled, manually exercised and visually inspected to confirm that it is capable of full stroking and that its internals are structurally sound (no loose or excessively corroded parts). This frequency is considered adequate to detect degradation which would orevent the valve from meeting its safety function. The valve remains in the closed position in a torus water environment and does not ex)erience flow which could cause wear.-
Additionally, past disassem)1ies and inspections have shown little, if any, degradation other than the expected minor corrosion.
Generic Letter 89-04 requires that a partial flow test be performed on check valves that are disassembled prior to their return to
. service. There is no possible flow path available for partial flow testing this check valve that would not introduce suppression pool water into the HPCI system piping or back to the CST. This is a simple swing check valve (Powell Fig.1561-WE) which does not require removal of the valve internals to perform a manual stroke test or visual inspection. Even if eFerCising/ inspection resulted in valve repairs, the valve could still be manually stroked after the internals were reinstalled in the valve.
Therefore full stroke capability cf the valve is ensured prior to installatlon of the bonnet cover.
This relief request is required.because all of the requirements (partial exercise after reassembly, and frequency of disassembly (every other outage)) of GL 89-04, Position 2, are not practicable.
3.3 Evaluation The guidance in M 89-04, Position 2, allows licensees to establish :; ample disassembly and inspection programs for valves which cannot be verified to full-stroke open or closed as required by the Code. If the guidance is used, l
the valves in each group must be of the same design (manufacturer, size, model i number, and materials of construction) and must also be exposed to the same !
service conditions. Where aossible, a partial stroke exercise with flow should be performed after tie valve is reassembled.
Partial. stroke exercise with flow following reassembly would result in a hardship for the licensee because such a test could significantly degrade the water quality in the CST by introducing suppression pool water into the CST.
Previous inspections have not shown significant degradation because the valves do not experience flow during any normal mode of reactor operation or during HPCI pump surveillance testing that could cause wear. The valves are of a simple design which allows manual stroke test and visual ins 3ection without removing the valve internals. Under these conditions, an enianced quality assurance measure during reassembly in lieu of partial stroke exercise I
provides a reasonable alternative. Thus the licensee should respond to the l HRC within 12 months with a revised request indicating the actions that have been taken with regard to an enhanced quality assurance program that would verify operability of these check valves during reassembly. This 12 months
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' interim period is less than the refueling outage frequency allowed by the Code for disassembly and inspection of check valves and degradation can be adequately monitored during this period. Compliance during the interim period, would result in a hardship or unusual difficulty without a i
t compensating increase in the level of quality and safety.
With regard to the extension of the disassembly and inspection interval to one valve every other refueling outage, the licensee's proposal does nct conform to the guidance in GL 89-04, Position 2, and the supplemental guidance in NUREG-1482, Section 4.1.
GL 89-04 states in Position 2 that extension of the valve disassembly / inspection interval to one valve every other refueling outage should only be considered in cases of extreme hardship. Regarding the definition of extreme haroship, the staff's response to Question Group 19 (see NUREG-1482, pages 13 to 14) states that the existence of extremo hardship that would allow extension of the schedule is de)endent on the aarticular circumstances at the plant. To determine w1 ether extreme aardship exists, the staff's response to Question 19 states that the licensee should conduct a detailed evaluation of the various competing factors:
First, the licensee should determine the effect on plant safety that would result for the proposed schedule extension. The maintenance history of the component and other information relevant to its reliability should be reviewed to determine whether the decrease in assurance of plant safety resulting from the schedule extension is justified. A need to off-load the reactor core, such as when testing the combined injection header check valves at some plants, or to operate at mid-level of the reactor coolant loops may be considered. The radiation
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exposure that .would result from disassembly and inspection is a factor to be considered under the ALARA [as low as reasonably achievable) principle, but it should be judged in combination with all of the other factors.
Condi.tions involving extreme hardship would have to be documented in the IST program in order to justify inspecting one valve on an every-other-refueling-outages frequency. The documentation should be detailed enough so that it is 4 evident that disassembly and inspection involve extreme hardship, if personnel radiation exposure concerns form part of the argument, then information about-the general area radiation field,-local hot spots plant radiation limits and stay times, and the amount of exposure personne,l performing ~the test would receive should-be included. Bases should include ;
actual plant data from previous examinations and show that the longer testing interval will provide adequate assurance of continued valves operational readiness,
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Alternatively, if disassembly / ins section does not involve extreme hardship, 9rouping valves 1(2)E41-F045 in tie two units and disassembling / inspecting a valve every refueling outage on an alternating basis may be pe:missible under the-following conditions:
i (1) the units are "identicci;" 4 (2) the valves are of the same design (manufacturer, size, model number and materials of construction);
(3) the valves are exposed to the same service conditions; and (4) if-a generic > problem is found during an inspection of one of the two valves, the other valve in the other unit must be inspected at the next- ,
refueling outage.
Although the SE dated April 12, 1996, alled for a clarification of the testing and inspection plan for-these valves, the-licensee's response does not t address the four areas identified above or the extreme hardship of disassembling and inspecting the valves. Relief from the Code-required
. frequency of every refueling outage is, therefore,-denied.
3.4 Conclusion For an interim period of 12 months from the date of the SE, the part of the nroposed alternative pertaining to partial stroke exercise following v.sembly is approved pursuant to 10 CFR 50.55a(a)(3)(ii), based on a finding
-t'n=t compliance during this interim period would result in a hardship or unusual safety. difficulty without a compensating increase in the level of quality and The licensee should respond to the NRC within 12 months with a revised request indicating the actions taken with regard to an enhanced
-quality assurance program that would verify operability of these check valves during reassembly. This 12 months interval is less than the refueling outage frequency allowed by the Code for disassembly and inspection of check valves.
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- Relief from the Code-required frequency of every refueling outage is denied.
The licensee shouid clarify the disassembly and inspection slan for these valves, as called for in the SE dated April 12, 1996. If tie disassembly program meets the guidance in GL 89-04, Position 2, and NUREG-1482, Section 4.1, a specific a > proval for relief is not required. When an alter. native is proposed t1at is in accordance with GL 89-04 guidance and is documented in the IST program, no further evaluation is required; however, implementation of the alternative is subject to NRC inspection.
4.0 RELIEF REQUEST RR-p-13 RR-P-13 requests relief from the Code requirements for vibration monitoring of
-the plant service water pumps 1(2)P41-C001A-D. ISTB 6.1 specifies, in part, that the ) ump toting frequencies be-doubled from every 3 months to every 6 weeks wienever the measured vibration levels fall within the alert range of '
Table ISTB 5.2-2. RR-P-13 requests that the lower limit on the axial
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vibration alert-range be relaxed from 0.325 in/see to 0.5 in/sec.
l 4.1 Licensee's Basis for The Relief Reauest The licensee-stated the following:
GPC installed a GE [ General Electric) Canada electric motor, serial number 1047430, on plant service water (PSW) pump.2P41-C0018. The resultant axial vibration measurements exceeded the ASME OM Code acceptance criteria resulting in the pump being placed on increased testing frequency. The axial vibration measurements exceeded the 0.325 in/sec limit per Table ISTB 5.2-2.-
GPC evaluated the vibration data and determined that the axial vibration is due to a motor condition, not a problem with the pump. The motor has 76 rotor bars and a running speed of_approximately 1180 rpm (19.8 Hz) which results in a rotor pass frequency of 1505 Hz. A 1505 Hz peak.is evident:in the vibration spectrum as well as a 120 Hz side band (1625 Hz). -This 1625 Hz side band peak (0.47 in/sec) was evaluated and determined to be an indication of- a potential motor rotor bar problem.
GPC requested GE Electrical Services to evaluate the vibration data and recommend a potential solution. After evaluation of the vibration data, GE agreed with the GPC determination that'the vibration amplitude is influenced by- the pump motor. ' GE concluded that vibration-of this -
magnitude is not detrimental to-long term motor operation and that the
' pump.an:t motor are capable of performing their intended safety functions for an extended period of time with an axial vibration of 0.5 in/sec.
This same motor was installed on PSW pump IP41-C001D which al'o s exhibited a 1625 Hz axial vibration-peak. The motor was removed and shipped to the GPC motor service center where it was inspected and tested. The service
i center issued a report which stated that no significant problems existed with the motor and that it was acceptable for continued operation.
4.2 Pronosed Alternate Testina l The 1.icensee proposed the following:
The axial vibration Alert Range for the PSW pump on which the GE Canada Motor, serial number 1047430, is installed shall be 0.50 in/see to 0.70 in/sec. If the axial vibration measurement exceeds the 0.5 in/sec limit, the associated pump will be placed on increased frequency testing in accordance with ISTB 6.1. If the axial vibration measurement exceeds (the)the until 0.7cause in/seco[ limit,) the associated pump will be declared inoperable f the condition is determined and corrected in accordance with ISTB 6.1.
4.3 Evaluation ISTB 6.1 requires that, for pumps with vibration levels between 0.325 in/sec and 0.700 in/sec, the testing frequency be doubled (from quarterly to every 6 weeks) until the cause of the vibration is determined and the condition corrected. The licensee proposes to relax the alert level for the axial vibration measurement to 0.500 .,700 in/sec for the following reasons:
(1) the licensee and the motor vendor (GE) determined that axial vibration previously measured in the alert range is due to a motor condition, not a problem with the pump; and (2) GE concluded that vibration previously measured in the alert range is not detrimental to long term motor operation and that the pump and motor are capable of performing their intended safety function for an extended period of time with an axial vibration of 0.5 in/sec.
The basis provided by the licensee effectively states that ISTB 6.1 was met in the case of the motor rotor bar nroblem because the cause for the high vibration levels was determined and the condition was corrected by an analysis. Therefore, a relief would not be required to exit the alert range i
and resume the quarterly testing frequency for vibration measurements up to 0.5 in/sec for the motor rotor bar problem. The relief request, however, proposes the application of 0.5 in/sec to axial vibrations in general and not t
specifically to the motor rotor bar problem.
For axial vibrations, it is not evident that 0.5 in/sec can be justified since the basis is presented in the context of the motor rotor bar problem. The basis does not clearly show that the pump is capable of continued operation at 0.5 in/sec for axial vibrations in general. Also, the pump manufacturer has not been identified (GE is specified as the motor manufacturer). Other relevant information is not provided, such as an assessment of methods to
reduce-the-vibration levels and spectral analysis of the vibration signature of the pumps. Relief is therefore dentee.
4.4 Conclusion Based. on the determination that the relief request lacks sufficient detail to
. justify the proposed alternative, relief as requested is denied.
5.0 RELIEF REQUEST RR-P-14 RR-P-14 requests relief from the differential pressure (d/p) measurement requirements of ISTB 4.6.2 for the RHR pumps 1(2)EllA-D and the CS pumps
-1(2)E21A&B. The licensee has proposed to measure discharge pressure in lieu
- of differential pressure.
5.1 Licensee's Basis for The Relief Reauest
-The' licensee stated the following:
The RHR and CS pumps are aligned to the suppression pool-during all modes of-normal plant operation which results in a virtually constant suction:
pressure. The pump's IST is performed utilizing a full flow test line which circulates water to and from the suppression pool. The Plant's Technical Specifications require.that tha-suppression pool be maintained
' within a narrow range of: level, _ temperature, and internal pressure during plant oper& tion which results in a normal suction pressure of
- approximately 5 to 7 psig. The Technical Specification operability limits-for the suppression pool =are itemized below.
Unit 1/ Unit 2 Level 2 146" & s 150" Internal Pressure s 1.75 psig Water Temperature s 100*F These Technical Specification operability limits for the suppression pool result in a maximum difference in calculated pump suction pressure of
< 2 psig-(5 to 7 psig). This 2 psig maximum difference is insignificant when performing IST considering the normal: discharge pressure of. the RHR and CS pumps. This 2 psig variance is also insignificant-in the calculation of differential pressure-(AP - Po-Pi) when considering the Code acceptable cperating ran 120% for centrifugal pumps) fromge (i Table 15% for vertical ISTB line 5.2-2b. shaft pumps
-Therefore, and using differential < pressure is of no benefit over the use of discharge pressure for IST.
Reference Discharoe hm Pressure Maximum Variance Unit 1 RHR 180-193 psig 1.11% max.
Unit 1 CS 305-310 ps g 0.66% max.
Unit 2 RHR 172-190 ps g 1.16% max.
Unit 2 CS 285-290 ps g 0.70% max.
Additionally, test gauges are required to be installed to perform IST of these pumps. The permanently installed pump suction pressure encompass a wider range of pressure [] than does IST and thus ex[ ceed gauges) the OM Code allowable range limit (3 times the reference value). The installed RHR pump with the RHR loop in[thegauges) must shutdown account cooling modeforofthe pressure experienced operation. The installed CS pump [ gauges) must account for the pressure experienced with the CS suction aligned to the Condensate Storage Tank. Therefore, test installe)d each time that IST is required.[ gauges , which satisfy the Code range Using pump discharge pressure, in lieu of differential pressure, will allow the IST to be performed with the installed pressure [ gauges) thus lessening the burden on operations personnel responsible for the testing.
Since the test [ gauges] are required to be calibrated both prior to and after usage, it also eiiminates the possibility of invalidating test data due to a delicate [ gauge) that is damaged during transportation, installation, or removal.
Mechanical degradation of centrifugal pumps, which experience significant differences in suction (inlet) pressure, would be indicated by changes in the differential pressure since the discharge pressure varies directly with suction pressure. However, for these pumps, the suction pressure variance is insignificant in comparison to the developed head (pressure) dnd monitoring discharge pressure, as opposed to differentidl pressure, provides an equivalent method to determine operational readiness and detect potential degradation.
5.2 Proposed Alternate Test.ing The licensee proposed the following: (as stated)
The pump suction pressure will be assumed to be zero, since it is insignificant and virtually constant, for the performance of IST. Pump discharge pressure will be measured and compared to its corresponding reference value. The acceptance criteria of Table ISTB 5.2-2b will be applied for assessing pump operational readiness and for monitoring potential pump degradation. This testing method meets the intent of the
[Clode for monitoring pump operational readiness and degradation, and re11 eves the Licensee of the burden associated with the use of temporary test [ gauges).
1 5.3- Evaluation If variations in pump inlet pressure are small in relation to the discharge 3ressure, discharge pressure could be used in lieu of d/p to evaluate pump lydraulic performance without causin monitor pump operational readiness.Ing such a significant decreasethe cases, requiring in the ability to licensee to measure or calculate inlet pressure may be a hardship without a compensating increase in the level of quality and safety.
l The main considerations for justifying the use of discharge pressure in lieu y of d/p are provided in NVREG/CR-6396, Section 3.3.2:
(1)- The inlet pressure is small in comparison with the discharge pressure (maximum deviation of 2%).
(2) The maximum expected variation in inlet pressure from test to test is relatively small as determined by control procedures and TS
[ technical specification) limits and as verified by historical data.
l (3) The-Code required acceptance criteria are not relaxed.
(4) Even though some uncertainty is introduced by this method, applying the Code acceptance criteria for d/p to discharge pressure for this application should add conservatism.
(5) If a significant blockage occurs at the pump suction, this condition would affect the discharge pressure and/or flow measurement and would not go undetected.
The licensee's submittal appears to meet all of the above criteria provided in NUREG/CR-6396, Section 3.3.2, with the exception of historical data showing -
that the variation in inlet pressure from test to test is relatively small.
The historical data should span several years and include the inlet pressures determined from inservice testing and from the Technical Specification surveillance requirements for the suppression pool.
An interim relief is appropriate to allow the licensee time to assess the NRC guidelines in NUREG/CR-6396, Section 3.3.2. Long-term relief is not warranted at this time because the historical vibration data were not provided in the relief request for staff review. It would be a hardship without a compensating increase in the level of quality and safety if the Code requirements were imposed during the interim period because the licensee has apparently met most of the criteria' identified in NUREG/CR-6396, Section 3.3.2, and because of the hardship associated with the measurement of inlet pressure.
, , a 5.4 Conclusion' For an interim period of 120 days from the date of the SE, the proposed' alternative regarding setting the inlet pressure to zero is approved pursuant to-10 CFR 50.5$a(a)(3) ii) based on the determination.that immediate comp 1.iance with the req (uirements results in hardship without a compensati increase in the level of quality and safety. The interim period will allow the licensee time to-assess the applicable NRC guidelines in NUREG/CR-6396, Section 3.3.2 :If the assessment indicates that long-term relief is 1 a
necessary, the licensee must submit a revised relief.requert within 120 days !
stating-the justification for long-tem relief, including historical- data iverifying minimal variation in the inlet pressures of the RHR pumps 1(2) Ell and CS pumps 1(2)E21.-
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6.0 CONCLUSION
Revised Relief Request RR-G-1, previously coaditionally approved, is authorized pursuant to 10 CFR 50.55a-(a)(3)(1). Revised Relief Request RR-P-13 is denied.
The part of the proposed alternative in RR-V-7 regarding increasing the inspection frequency to every other refueling outage is denied. 4 4= For an-interim period of 12 months from the date of the SE, the part of the proposed i alternative in Relief Request RR-V regarding partial stroke exercise of check valves following reassembly is approved pursuant to 10 CFR 50.55a(a)(3 months with a re)v(11). -The licensee should respond to the NRC within ised request-indicating the actions that have been taken with 1 regard to an. enhanced quality assurance program that would verify operability of these check valves during reassembly.
For an interim period af 120 days from the date of. the SE, the proposed alternative in Relief Request RR-P-14 regarding: setting the inlet pressure to zero is approved pursuant to 10 CFR 50.55a(a)(3)(ii). The interim period will allow the licensea time to assess the applicable NRC guidelines in NUREG/CR-6396, 1
Section 3.3.2. If the assessment indicates that long-term relief is necessary, the licensee must submit a-revised relief. request within-120 days stating the
- justification for long-term relief, including historical data verifying minimal variation in the inlet pressures of the RHR pumps 1(2) Ell'and CS pumps-1(2)E21.
-Principal Contributor: K. Dempsey-Date: ' August 21, 1997
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