ML20210T251
| ML20210T251 | |
| Person / Time | |
|---|---|
| Site: | Perry  |
| Issue date: | 04/19/1999 |
| From: | Dibiasio A, Fresco A, Grove E BROOKHAVEN NATIONAL LABORATORY |
| To: | NRC (Affiliation Not Assigned) |
| Shared Package | |
| ML20210T237 | List: |
| References | |
| CON-FIN-J-2402 TAC-MA3328, NUDOCS 9908190039 | |
| Download: ML20210T251 (91) | |
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ATTACHMENT 2 TECHNICAL EVALUATION REPORT I
Perry Nuclear Power Plant First Energy Second Ten-Year Interval Pump and Valve Inservice Testing Program i
i Docket Number: 50-440 l
TACNumber: MA3328 Prepared by l
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A. M. DiBiasio, E. Grove, and A. Fresco Department of Advanced Technology Environmental and Systems Engineering Division i
Brookhaven National Laboratory Upton,NY 11973 l
I April 19,1999 l
Ihyerd for J. Colaccino,NRC Technical Monitor Division ofEngineering Office of Nuclear Reactor Regulation U. S. Nuclear Regulatory Commission Washington,DC 20555 JCN J-2402, Task Order 8 9908190039 990809 l
PDR ADOCK 05000440 P
ABSTRACT This report presents the results ofBrookhaven National Laboratory's evaluation ofthe reliefreguests, cold shutdown and refueling outage justifications, and, for selected systems, a review of the scope of First Energy's Perry Nuclear Power Plant, ASME Section XI Pump and Valve Inservice Testing Pioy.au l
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L TABLE OF CONTENTS
' ABSTRACT -............................................................... iii 1.0 -
INTRODUCTION.................................................... I 2.0
' PUMP IST PROGRAM RELIEF REQUESTS.............................
2 2.1.
Pump Relief Request PR-1, Analysis for all Code Class Pumps........... 2 2.2 Pump Relief Request PR-2, RHR, LPCS, HPCS, and RCIC
- Waterleg Fill Pumps............................................. 3 2.3 _
Pump ReliefRequest PR-3, Use of Analysis in Lieu of Corrective Action for Code Class Pumps....................................
4 2.4 Pump Relief Request PR-4, Smooth-Running Pumps (Continuous Running or Alternate Service Pumps)..............................
6 2.5 Pump Relief Request PR-5, Smooth-Running Pumps (Stand-by Pumps)..............................................
7 2.6 Pump ReliefRequest PR-6, Dig 'tal Instruments for all Code Class Pumps..................................................
9 3.0 VALVEIST PROGRAM RELIEF REQUESTS 10 3.1 Valve Relief Request VR-1, CRD Valves............... _........... I1 3.2 Valve Relief Request VR-2, Deleted (Ref. 3).......................
12 3.3 Valve Relief Request VR-3, Nuclear Boiler ADS and SRVs...........
12 3.4 Valve Relief Request VR-4, LPCS, RHR, and RCIC Keep Fill Pumps Discharge Check Valves 13 3.5
- Valve Relief Request VR-5, Standby Diesel Generator Starting Air Valves..................................................
15 3.6 Valve Relief Request VR-6, Pressure Relief Devices.................. 17 3.7 Valve Relief Request VR-7, Containment Vacuum Breakers...........
18 3.8 Valve Relief Request VR-8, CRD Rupture Disks....................
19 3.9 Valve Relief Request VR-9, RCIC Check Valves....................
21 4.0 VALVE TESTING DEFERRAL JUSTIFICATIONS 23 5.0 IST SYSTEM SCOPE REVIEW.......................................
23 6.0 IST PROGRAM RECOMMENDED ACTION ITEMS...................... 24
7.0 REFERENCES
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APP M N A..................................................... A-1 y
LIST OF TABLES A.1 Evaluation of Peny Refueling Outage Justifications.....
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A.2 Evaluation of Peny Cold Shutdown Justifications........................ A-13 l
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Technical Evaluation Report Pump and Valve Inservice Testing Program Perry Nuclear Power Plant I.0 INTRODUCTION Contained herein is a technical evaluation of the American Society of Mechanical Engineers (ASME)Section XI Pump and Valve Inservice Testing (IST) program reliefrequests and deferral justifications submitted by First Energy for its Peny Nuclear Power Plant. Additionally, this technical evaluation report contains, for selected systems, a review of the scope ofPerry's ASME Section XI Pump and Valve Inservice Testing Program. Perry is a Generd Electric Boiling Water Reactor (BWR) that began commercial operation November 18,1987.
First Ene rgy submitted the second ten-year intervalinservice testing reliefrequests on July 22,1998 (Ref.1). The licensee states that the second interval program is based on the requirements of the
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1989 Eht!on of the ASME Section XI Code. This program revision supersedes all previous subminals. The licensee in the transmittal letter states that the second ten-year interval begins
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November 18,1998. Based on the date of commercial operation, the interval should extend from November 1997 to November 2007. ASME Section XI,1IWA-2430(c) allows each interval to be i
extended or decreased by as much as one year. Adjustments shall not cause successive intervals to be altered by more than one year from the original pattem ofintervals.Section XI,11WA-2430(e) also allows the interval to be extended for units that are out of service continuously for six months or more. The licensee should provide an explanation of the interval dates in future IST program i
submittals. In addition, the licensee submitted revised valve reliefrequest, VR-09, on December 17, 1998 (Ref. 2) and a copy of the second interval IST program directly to BNL (Ref. 3) which deleted one valve relief request, VR-02.
Title 10 of the Code of Federal Regulations, {50.55a 1(f) (Ref. 4) requires that inservice testing of ASME Code Class 1,2, and 3 pumps and valves be performed in accordance with Section XI of the ASME Boiler and Pressure Vessel Code (Ref. 5) and applicable addenda, except where specific relief has been requested by the licensee and granted by the Commission pursuant to {50.55a 1(fX6Xi), or where an altemative has been requested and authorized pursuant to {50.55a 1(aX3Xi) or (aX3Xii). Section 50.55a 1(fX4Xiv) provides that inservice testing of pumps and valves may meet the requirements set forth in subsequent editions and addenda that are incorporated by reference in paragraph (b) ofl50.55a, subject to the limitations and modifications listed, and subject to Commission approval. In rulemmWg to 10CFR50.55a, effective September 8,1992 (see Federal Register. Vol. 57, No.152, page 34666), the 1989 Edition of ASME Section XI was incorporated into paragraph (b) of {50.55a. The 1989 Edition provides that the rules for inservice testing of pumps and valves are as specified in ASME/ ANSI OMa-1988 Part 6 and 10, and OM-1987 Part 1 (Refs. 6-8).
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The review of the IST Program was performed utilizing the Standard Review Plan, Section 3.9.6; Generic Letter 89-04, " Guidance on Developing Acceptable Inservice Testing Programs," the Minutes of the Public Meeting on Generic Letter 89-04, and Supplement to the Minutes; NUREG-1482; NUREG/CR-6396; and the recently published summary of the public workshops j
held in January and February 1997 on IST (Refs. 9-15). The IST Program requirements apply only I
to component (i.e., pump and valve) testing, and are not intended to provide a basis to change the licensee's current Technical Specifications for system test requirements.
Section 2 of this report presents the six pump relief requests submitted by First Energy and Brookhaven National Laboratory's (BNL) evaluation. Similarinfomation is presented in Section 3 for the nine relief requests submitted for the valve testing program. Section 4 contains the evaluation of45 justifications to defer valve testing to cold shutdowns or refueling outages, Results of the IST scope review for selected systems is presented in Section 5. Section 6 summarizes the recommended actions for the licensee, resulting from the relief request and deferred testing justification evaluations, and the review of the IST Program scope for selected systems. BNL recommends that the licensee resolve these items in accordance with the evaluations, conclusions, and guidelines presented in this report.
2.0 PUMP IST PROGRAM RELIEF REQUESTS In accordance with (50.55a, First Energy has submitted six reliefrequests for pumps at Perry which i
are subject to inservice testing under the requirements of ASME Section XI. The relief requests have been reviewed to verify their technical basis and dete mine their acceptability. "Ibe relief requests, along with the technical evaluation by BNL, are summarized below.
2.1 Pump Relief Request PR-1, Analysis for all Code Class Pumps ReliefRequest: The licensee has requested relieffrom the requirements ofOMa-1988, Part 6,16.2, which specifies that all test data shall be analyzed within % hours after completion of a test, for all Code Class pumps.
Licensee'sBasisforRelief. "TheInserviceTesting(IST)personnelarenotalwaysreadilyavailable for the review effort. Test acceptance criteria are contained within the test procedures, and the initial approval ofequipment cperability is by On-ShiA personnel. The On-Shift personnel declare pumps whose measured parameters enter the acceptance criteria required action range inoperable, in a timely manner. The analysis of results for degradation requiring increased testing or engineering evaluation will then occur when the IST personnel are available for reviewing the inservice pump test data. Therefore, compliance with the duration required for performance of the analysis would result in a hardship without a compensating increase in the level of quality and safety."
1 ProposedAlternate Testing: Test data shall be reviewed within four (4) work days following the test, excluding weekends (Saturday & Sunday) and holidays.
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Evaluation: OMa-1988, Part 6,16.2 requires all test data to be analyzed within 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> after completion of a test. As discussed in Generic Letter 89-04, Position 8, the NRC's posidon is that as soon as the data is recognized as being in the required action range, the associated pump must be declared inoperable and the technical specification action time must be started, the % hour grace period may not be applied. The licensee has stated that the acceptance cri eria is contained in the t
test procedures and the on-shift personnel will declare pumps inoperable in a timely manner. The licensee appears to be in compliance with Position 8.
After declaring the pump inoperable or when the pump has entered the alert range, the Code requims the licensee to analyze the data within % hours. This time allowance is to account for instances where holidays or weekends may interfere with the normally expected analysis timeframe.
10CFR50.55a (a)(3)(ii) states that altematives may be authorized when compliance with the requirements of the Code would result in a hardship or unusual difficulty without a compensating increase in the level ofquality and safety. The licensee's proposed altemate to exclude holidays and weekends from the 96-hour requirement could result in a six or seven day delay before the data is analyzed. This may delay appropriate corrective action on degraded pumps for a similar timeframe.
It is recommended that reliefas requested be denied. The licensee should continue to comply with the provisions of the Code, GL 89-04, Position 8, and Technical Specification requirements.
2.2 Pump Relief Request PR-2, RHR, LPCS, HPCS and RCIC Waterleg Fill Pumps ReliefRequest: The licensee has requested relieffrom the requirements ofOMa-1988, Part 6,15.1, which specifies that an inservice test shall be run on each pump nominally every three months, for the RHR, LPCS, HPCS, and RCIC waterleg fill pumps.
Licensee's Basisfor Relief. "The waterleg pumps were designed to be inservice to maintain emergency standby systems pressurized. The waterleg pumps run continuously, with flow established through a recirculation line, in order to provide enough head to keep the applicable systems discharge piping full to the highest elevation. During safety-related pump testing, the waterleg pump normal discharge path must be redirectui through drain lines to provide enough flow to establish the selected Code reference values. This requires taking the system out ofservice and racking out safety-related pump breakers (RHR, LPCS, and HPCS) or isolating the safety-related pump (RCIC) to prevent system damage due to waterhouuuer or cavitation upon receipt of an actuation signal. In addition, all ofthese pumps have adequate margin beyond the capacity required for them to fulfill their function.
Quarterly monitoring of discharge pressure (suction pressure is essentially constant) and bearing vibration in accordance with Position 9 of GL 89-04 will be performed to monitor for pump degradation. The intent ofASME Code,Section XI is not to reduce the reliability ofsafety-related systems. Quarterly full flow testing of the listed safety-related waterleg pumps would result in hardship without a compensating increase in the level of quality or safety."
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Proposed Alternate Testing: Test in accordance with OM(6) during cold shutdown. In addition, these pumps shall be monitored on a quarterly basis, observing pump discharge pressure and bearing vibration. These parameters will be evaluated to adequately assess the pump's performance.
Evaluation: OMa-1988, Part 6,15.1 requires an inservice test be run nominally every three months.
. Paragraph 5.2 (b) requires the resistance of the pump be varied until the flow rate equals the reference value. The pressure shall then be determined and compared to the reference value.
Altematively, the flowrate can be varied until the pressure equals the reference value and the flowrate is determined and compared to the reference flow rate.
The subject waterleg fill pumps are normally operating to maintain the associated systems' piping full to reduce the likelihood of water h===~. The licensee in the request has stated that during testing,"the waterleg pump normal discharge path must be iebted through drain lines to provide enough flow to establish the selected Code reference values." They further stated that this would require that the pumps be declared inoperable, which would be a hardship during operation. The licensee has proposed to measure discharge pressure and vibration quarterly, but would delay flow rate measurements to cold shutdowns. The Code does not provide any requirements on the reference flow rate (unlike the later OM Code). As discussed by the licensee in the IST Program, 1
Section 2.4, the flowrate is measured in the pumps' suction lines, and approximately 10 gym is
< normally recirculated. The reference flowrates are set at 37.2 gpm (RHR), 41.0 (LPCS),
32.4 (HPCS), and 41.5 (RCIC). However, as dim-d in GL 89-04, Position 9, measuring flowrates at less than full flow would provide less information on a pump's operational readiness.
The licensee's proposal to monitor be.dsg vibration and pump discharge pressure quarterly in accordance with the Code and flowrate during cold shutdov>n will provide an acceptable level of quality and safety for monitoring the pumps and assuring that the pumps are capable ofperforming their safety function.
It is recommended that the attemate be authorized in accordance with 10CFR50.55a(s)(3)(i).
2.3 Pump Relief Request PR-3, Use of Analysis la Lieu of Corrective Action for Code Class Pumps ReliefReguest: The licensee has requested relief from the requirements ofOMa-1988, Part 6,16.1, which requires if deviations fall within the required action range of Table 3, the pump is required to be declared inoperable until the cause of the deviation has been determined and the condition conected for all Code Class pumps.
Licensee's Basisfor Relief "As stated above, OM(6) requires doubling of test frequency or declaring a pump inoperable upon reaching the Alert or Required Action Ranges,ierpectively. In some cases, where a pump has sufficient excess margin to its safety analysis limits and data trending l
and analysis only indicate a gradual decrease in pump performance, the requirements ofOM(6) may result in taking unnecessary corrective action.
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The 1995 ASME OM Code allows the ability to perform an analysis ofthe pump and establish new reference values. Paragraph ISTB 6.2.2 states that ifthe measured test parameter values fall within the required action range... the pump shall be declared ' operable until either the cause of the j
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' deviation has been determined and the condition corrected, or an analysis ofthe pump is perfonned and new reference values are established in accordance with Paragraph ISTB 4.6. Paragraph ISTB 4.6 requires that the analysis include both a pump level and a system level evaluation of
. operational rMa*=s, the cause ofthe change in pump performance, and an evaluation of all trends indicated by available data. If such an analysis supports establishing new reference values in lieu of correcting the condition, then using the requirements of ISTB 6.2.2 and ISTB 4.6 as an attemative to OM(6)-6.1 would provide an acceptable level of quality and safety.
Notes: Where ISTB 4.6 and ISTB 6.2.2 refer to ISTB tables, OM(6) Table 3 would be inserted.
All references to ISTB in the pi=%g paragraphs refer to the 1995 ASME OM Code."
proposed Alternative Testing: If pump test parameters fall within the required action range, as specified by OMa-1988, Part 6, the 1995 OM Code,16.2.2, and related 14.6, will be utilized.
Evaluation: OMa-1988, Part 6,16.1, "AccPace Criteria," specifies actions required to be taken i
if any of the measured pump parameters fall within the alert or required action ranges. For test results in the alert range, the test frequency is required to be doubled until the cause of the deviation is determined and the condition is corrected. For test results in the required action range, the pump shall be declared inoperable until the cause of the deviation has been determined and the condition w & cd.
In ASME OM Code-1995, which is not currently referenced in 10CFR50.55a but is included in the proposed rulemaking without any modification or limitation (Ref.16), Subsection ISTB, l
11 STB 4.6, "New Reference Values," allows that "[i]n cases where the pump's test parameters are either within the alert or required action ranges of ISTB 5.2.1.1, Table ISTB 5.2.1-2, Table ISTB 5.2.2-1, or Table ISTB 5.2.3-1, and the pump's continued use at the changed values is supported by an analysis, a new set of reference values may be established." This paragraph clarifies that, if a pump can be shown to be capable of performing its safety function, it may be returned to service with adjusted reference values. This reflects that there are pumps that have a significant margin over the safety requirements that might degrade from their initial performance, but still are capable ofmeeting their safety function. Pumps which do not have margin would not be retumed to service without repair or replacement. Paragraph ISTB 4.6 also states that the analysis shall include both a pump level and a system level verification of pump operational readiness, the cause of the change in pump performance, and an evaluation of all trends indicated by available data. Paragraph ISTB 6.2.2, which provides awptance criteria for the required action range explicitly states that an analysis may be performed and directly references 11 STB 4.6.
In NRC Generic Letter 91-18 (Ref.17), which concems resolution ofdegraded and nonconforming conditions and operability,16.11, " Technical Specification Operability vs. ASME Code,Section XI Operative Criteria," the NRC indicates that in cases where the required action range limit is more 5
conservative than its corresponding technical specification limit, the corrective action may not be limited to replacement or repair. He corrective action may consist of an analysis to demonstrate that the specific pump performance degradation does not impair operability and that the pump or valve will still fulfill its function, such as delivering the required flow. A new required action range may be established after such an analysis which would then allow a new determination of operability. Approval has been authorized by the NRC to allow licensees to use the OM Code-1995,16.2.2 for pumps in the required action range b= licensees are already allowed to perform an analysis in accordance with Generic I.etter 91-18.
The analysis should at least include a comparison of the current measurements for the particular parameter, i.e., flow rate, vibration, discharge pressure or differential pressure, to the baseline measurements, an evaluation of the trend of available data for the parameter, and a determination of the cause and the need for corrective action. Alternate available methods, such as vibration spectral analysis, are expected to be used to support the analysis. Any analysis performed is subject to NRC inspection and must provide reasonable assurarse that the degradation mechanism will not cause further degradation such that, before the next pump test or before repairs can be performed, i
the pump would fail. Additionally, it should be noted that changes to the vibration reference values l
would affect only the vibration relative alert and required action limits, and not the absolute limits specified by the Code. If the absolute limits are exceeded (i.e.,0.7 ips or 22 mils for the required action range), the licensee would be required to declare the pump inoperable in accordance with the Code.
A use ofthis analysis is ved to be a rare occurrence. This analysis should be used cautiously, as it is not intended to be used regularly to evaluate the operability of all pumps that fall into the i
required action range in order to declare the pump operable and define new reference values where I
significant degradation has occurred. Repeated application of analysis could lead to stair stepping the Code limits downward to the safety limits of the pump. He licensee should have an understanding ofthe margin ofeach pump above its design-basis requirements. This alternative will provide an acceptable level of quality and safety for monitoring the pumps and assuring that the pumps are capable of performing their safety function.
Therefore, given the licensee will perform an analysis in accordance with ISTB 4.6 of the 1995 OM Code, it is recommended that the licensee's proposed alternative be authorized pursuant to 10CFR50.55a(a)(3)(i), based on the acceptable level ofquality and safety that will be provided by the alternative.
i 2.4 Pump Relief Request PR-4, Smooth-Running Pumps (Continuous Running or Alternate Service Pumps)
ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 6, 15.2(d) which specifies that pump parameters be measured and compared to corresponding reference values and 16.1 which specifies the corrective action required if deviations fall within the alert or required action ranges ofTable 3.
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Licensee'sBasisforRelief "Forsmooth-runningpumpswithverylowvaluesofvibrationvelocity, it is possible that using 2.5 and 6 times the reference value to determine the Alert and Required Action ranges can lead to needlessly increasing test frequency or declaring a pump inoperable.
Small indicated changes due to variations in test conditions, instrumentation, or personnel, and not related to machine condition could result in unnecessary testing or maintenance. Fixed minimum reference values for the Alert and Required Action Ranges, if chosen low enough, such as 0.02 inches per second (ips), would still provide for timely corrective action. Data trending and l
l analysis should be able to dcL ine if there is a degraded condition even if the Alert or Required l
Action Ranges have not been reached.
Intemational Research and Development (IRD) characterizes pumps running at 0.01 % (-O.02) ips or less as smooth. 0.02 ips is as low or lower than other vibration instrument manufacturer's cutoff for their comparable category (NUREG/CP-0111). 0.02 ips would thus be an acceptable reference i
I value to base the Alert and Required Action ranges on. For pumps with reference values below 0.02 ips, the Alert range would then be >0.05 to 0.12 ips and the Required Action range would be
>0.12 ips.
The pumps covered by this reliefrequest either run continuously or are in altemating service. The amount of run time that these pumps accumulate allows for excellent prediction of pump performance by analyzing and trending data gathered quarterly. 'Iherefore, use of a fixed minimum reference value for the above-listed pumps would provide an acceptablelevel ofquality and safety."
ProposedAlternate Testing: For pumps with one or more vibration velocity reference values less than 0.02 ips, an Alert Range of>0.05 to 0.12 ips and a Required Action Range of>0.12 ips will l
be applied to those vibration measurements. Actions required by OM(6)-6.1 would take place at these values.
Ewrluation: Pump Relief Requests PR-4 and PR-5 both deal with smooth-naning pumps. The evaluation of both has been combined and is presented in the following Section.
2.5 Pump Relief Request PR-5, Smooth-Running Pumps (Stand-by Pumps)
ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 6, 15.2(d) which specifies that pump parameters be measured and compared to corrapan*ng reference values and 16.1which specifies the conective action required if deviations fall within the alert or required action ranges ofTable 3.
l Licensee'sBasisforRelief "Forsmooth-runningpumpswithverylowvaluesofvibrationvelocity, l
it is possible that using 2.5 and 6 times the reference value to determine the Alert and Required l
Action ranges can lead to needlessly increasing test frequency or declaring a pump inoperable.
Small indicated changes due to variations in test conditions, instrumentation, or personnel, and not related to machine condition could result in unnecessary testing or maintenance. Fixed minimum values for the Alert and Required Action Ranges, if chosen low enough, such as 0.02 inches per 7
second (ips), would still provide for timely' corrective action. Data trending and analysis should be able to determine ifthere is a degraded condition even if the Alert or Required Action Ranges have not been reached.
International Research and Development (IRD) characterizes pumps running at 0.01 % (-0.02) ips or less as smooth. 0.02 ips is as low or lower than other vibration instrument manufacturer's cutoff for their comparable category (NUREG/CP-0111). 0.02 ips would thus be an acceptable reference value to base the Alert and Required Action ranges on. For pumps with reference values below 0.02 ips, the Alert range would then be >0.05 to 0.12 ips and the Required Action range would be
>0.12 ips.
The pumps cover 9d by this reliefrequest are generally in the standby mode. Since these pumps do not accumulate much run time, prediction ofpump performance by analyzing and trending data gathered quarterly will be supplemented by an additional requirement for placing a pump on an increased test frequency. For pumps with Alert and Required Action Ranges based on a fixed minimum reference value, if any vibration measurement increases by a factor of 2.5 from the previous test, the pump's test frequency will be doubled until a trend can be established. This requirement, combined with data analysis and trending, will ensure that corrective action is taken in a timely manner. Therefore, use ofa fixed minimum reference value for the above-listed pumps, combined with the requirement to double a pump's test frequency if a vibration reading increases by a factor of 2.5 from the previous test, would provide an acceptable level ofquality and safety."
?roposedAlternate Testing: For pumps with one or more vibration velocity reference values less than 0.02 ips, an Alert Range of>0.05 to 0.12 ips and a Required Action Range of>0.12 ips will be applied to those vibration measurements. Actions required by OM(6)-6.1 would take place at these values. In addition, for standby pumps with Alert and Required Action Ranges based on the fixed minimum reference value of 0.02 ips, if any vibration measurement increases by a factor of 2.5 from the previous test, the pump's test frequency will be doubled until a trend can be established.
Evaluation: OMa-1988, Part 6,16.1 and Tables 3 and 3a, require increeed testing if the pump's vibration readings exceed 2.5V, or 10.5 mils and the pump to be declared inoperable if the pump's vibration readings exceed 6V, or 22 mils.Section XI previously included requirements for smooth-running pumps, i.e., pumps with a reference value less than 0.5 mils. However, this was deleted in OMa-1988 Part 6 because " absolute criteria can neglect significant changes in a pump which was originally running smooth..." (Ref. I 8). Since then, the ASME Code committees have considered revising the Code to address smooth-running pumps, but have not achieved a consensus on this issue. As discussed in NUREG-1482, Section 5.4, and the IST Workshop Meeting Minutes, Question 3.4.1, the NRC had been reluctant to approve requests for smooth-running pumps due to an occurrence at Catawba where the pump bearing was degraded and required replacement, even though the pump was below the criteria for smooth-running pumps (but above the Code criteria).
Recently, however, the NRC has received similar reliefrequests with low reference values (<0.05).
While these reliefrequests are still being reviewed, the NRC staffconsiders the inclusion of these pumps in a condition monitoring program to be essential. This program may include such activities 8
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as spectral analysis, lube oil analysis, thm-c p.yhy, and motor current signatures. Most, ifnot all, a
plants have rotating equipment condition monitoring programs to ensure the health of this equipment. In addition to including the pumps in a condition monitoring program, the licensee should consider two other significant issues related to smooth-running pumps. The first concems the actual pump bearing measured directions, and whether all of the directions measured must be below the reference value for a pump to be considered smooth-running. The second issue concems
. the overall vibration level at which the pump would no longer be considered smooth-running. The alert and required action limits specified address acute problems with the pumps which would not have been previously ded If the pump's overall vibration is allowed to degrade such that the vibration level is maintained above the reference value for a significant period of time, the pump may be still operable, but the smooth-running classification must be questioned.
The licensee has requested generic relief for all the Code Class puinps and has proposed for
' vibration reference values less than 0.02 ips, imposing absolute limits (0.05 ips alert,0.12 ips required action) only for nonnally operating pumps (PR-4) and, in addition to these absolute limits, a relative limit of 2.5 times the previous test which would cause increased testing for trending, for standby pumps (PR-5). As die =ed these requests lack one essential aspect =~==y for relief, a commitment to a condition monitoring program. Based on the existence ofa condition monitoring program at Peny that could support the determination that the altemative provides an acceptable level ofquality and safety, and the very low levels (i.e., vibration reference value less than 0.02 ips),
compared to approaches considered by the ASME Code committees, that would invoke these relief requests, it is recommended that interim relief be authorized in accoidssce with 10CFR50.55a(a)(3)(ii) for one year. To require compliance with the Code in the interim would cause pumps with very low vibration levels to enter the alert or required action range, which w ould.
be burdensome to the licensee considering that the licensee can use analysis to exit the required action range per ReliefRequest PR-3 (TER Section 2.3). In the interim, the licensee must commit to include these pumps in a condition monitoring program and document their approach to the NRC stafI's concems regarding individual pump vibration parameters. 'Ihis document will be subject to NRCinspectorreview.
2.6 Pump Relief Request PR-6, Digital Instruments for all Code Class Pumps ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 6, 14.6.1.2(b) which requires that digital instruments be selected such that the reference value shall not exceed 70 percent of the calibrated range of the instrument for all Code class pumps.
Licensee 's Basisfor Relief " Plant process computer (ERIS) points are used for instrumentation in numerous IST pump tests. 'Ibe ERIS points are used in lieu of the associated andog indicators in order to meet ASME Code instrument loop accuracy requirements. As well as using ERIS points, temporary digital instruments (M&TE) are also used in IST pump testing. In many cases, the reference values exceed 70 percent of the ERIS point or temporary digital instrument range.
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- According to NUREG/CP-0111, the basis for the 70 percent requirement is to avoid overranging an instrument if an unexpected situation is encountered. However, since the ERIS points utilize permanent plant instrumentation, the ranges are aheady selected to account for all expected operating conditions. Overranging is also not a concern with temporary digital instruments.
Surveillance tests are written such that the temporary instrumentation would not be overranged, whether the instrument is digital or analog. In addition, digital instrumentation is significantly less
--apdble to damage from overranging. Fw6more, reading higher in the instrument range results in greater accuracy since tS instruments are calibrated as a percentage of-full scale.
'Iherefore, use of the ERIS points and temporary digital instrumentation within their full calibrated range would provide an accer.able level of quality and safety."
ProposedAlternate Testing: Digital instruments shall be selected such that the measured parameter does not exceed the calibrated range of the instrument.
Evaluation: OMa-1988, Part 6,14.6.1.2(b), requires that the reference value ofdigital instruments not exceed 70 percent of the calibrated range of the instrument. The ASME OM Code committees recently approved Code Case OM" 5, which will be included in the OMa-1999 Addenda. This~
Code Case allows Owners to use digital instruments such that the reference value does not exceed 90 percent of the calibrated range of the instrument. This Code Case was writted to allow Owners additional flexibility, since the 70 percent was based on previousSection XI requirements for pressure testing equipment, and to ensure that if readings were in the required action range, they could be read. The licensee has proposed that digital instruments shall be selected such that the measured parameter does not exceed the calibrated range of the instrument. Table 3b ofOM Part 6 states that the maximum acceptable value of the measured parameter is 110 percent ofthe reference value. The licensee should ensure that Code ecspmce criterion for the measured parameter is within the calibrated range of the selected instrument. Accordingly, the reference value should not exceed 90 percent of the calibrated range of the instrument. When selecting its digital instrument, the licensee should ensure that 110 percent of the measured parameter's reference value is within the instrument's calibrated range. This attemative would provide an acceptable level ofquality and safety.
Therefore, given the licensee will select and use instruments in accordance with the digital instrument range requirements' for Code Class 2 and 3 pumps, it is recommended that the licensee's proposed altemative be authorized pursuant to 10CFR50.55a (a)(3)(i), based on the acceptable level of quality and safety that will be provided by the altemative.
3.0 VALVEIST PROGRAM RELIEF REQUESTS In mdence with 050.55a, First Energy has submitted nine valve relief requests (VR-2 was deleted) for specific valves at Perry that are subject to inservice testing under the requirements of ASME Section XI. In addition, VR-10 will be reviewed by the NRC and documented in a separate SER. These reliefrequests have been reviewed to verify their technical basis and determine their 10 1-
acceptability. The relief requests are summarized below, along with the technical evaluation by BNL.
3.1 Valve Relief Request VR-1, CRD Valves ReliefReguest: 'Ihe licensee has requested relief from the requirements of OMa-1988, Part 10, 14.2.1 and 4.3.2 which specify the test frequency requirements and require that all power-operated valves shall have their stroke time measured, for the CRD HCU scram valves, ICll-126 and 1C11-127, and scram discharge header and accumulator supply check valves,1Cl1-114 and 115 associated with the 177 HCUs.
Licensee 's Basisfor Relief "These valves operate as an integral part of the hydraulic control unit to rapidly insert control rods. Valves will be tested in accordance with Technical Specifications (TS) (i.e., maximum scram insertion time). 'Ibe TS surveillance required frequency of testing (i.e., all control rods prior to thermal power exceeding 40 percent ofrated thermal power after fuel movement within the reactor pressure vessel, and after each reactor shutdown 2120 days, and testing of a representative sample of the control rods at least once per 120 days of operation in mode 1), assures the necessary quality of the system and components is maintained, that facility operation will be within the safety limits and the Limiting Condition of Operation will be met.
'Iherefore, compliance would result in a hardship without a compensating increase in the level of quality and safety."
ProposedAlternate Testing: Scram insertion timing shall be substituted forindividual valve testing.
Evaluation: OMa-1988, Part 10,14.2.1 requires the stroke time ofall power-operated valves to be measured quarterly ifpracticable, otherwise at cold shutdowns. Iffull-stroke exercising during cold shutdowns is also impracticable, it may be deferred to refueling outages. OMa-1988,14.3.2 requires check valves to be exercised nominally every three months. If full-stroke exercising during operations is impracticable, it may be deferred to cold shutdown, and if that is also impracticable, to refueling outages.
The subject valves have a safety function in ensuring rod insertion during a reactor scram.
Valve ICll-126 opens to vent the control rod drive to the scram discharge volume.
Valve 1C11-127 opens to allow HCU accumulator pressure to exert force to insert the control md into the core. These valves are not provided with position indication, therefore measuring their full-stroke time in accordance with the Code is impractical. Additionally, operation of these valves at power would result in rod insertion and subsequent reactor shutdown, which is impractical.
Valve 1C11-114, the scram discharge header check valve, is exercised open during a rapid rod insertion. Additionally, check valve 1Cl1-115 can only be verified closed by securing the control rod drive pumps and depressurizing the charging water header. Securing the CRD pumps would result in the loss ofcooling water to the reactor coolant pumps during power operation,which would be impractical due to the potential for equipment damage or reactor scram.
I1
As discussed in Generic Letter 89-04, Position 7, the rod scram test frequency identified in the technical specification may be used as the valve testing frequency to minimize rapid reactivity transients and wear ofthe control rod mechanisms. Verifying that the associated control rod meets the scram insertion time limits defined in the Technical Specifications can be an acceptable alternative method ofdataedag degradation of these valves in lieu of valve stroke measurement for valves 1Cl 1-114,126 and 127. Additionally, as discussed in Generic Letter 89-04, Position 7, the HCU accumulator pressure decay test identified in the plant Technical Specifications may be used as the charging water header check valve,1C11-115, alternate testing frequency.
Therefbre, by performing the Technical Specification control rod scram test and HCU accumulator pressure decay test (Ref.19) pursuant to Generic Letter 89-04, Position 7, reasonable assurance of the valves' operational readiness should be provided, and it is recommended that relief be granted in accordance with 10CFR50.55a(f)(6)(i). The licensee should clarify in the attemate testing portion of the relief request that the HCU accumulator pressure decay test will be performed.
3.2 Valve Relief Request VR-2, Deleted (Ref. 3)-
3.3 Valve Relief Request VR-3, Nuclear Boiler ADS and SRVs ReliefReguest: The licensee has requested relief from the requirements of OMa-1988, Part 10, 14.2.1, which requires that valves be tested nominally every three months except as provided by 14.2.1.2,4.2.1.5, and 4.2.1.7 for the solenoid-operated valves which supply air to the air operators for the nuclear boiler automatic depressurization system (ADS) and safety relief valves (SRVs).
Licensee 's Basisfor Relief "These solenoid operated valves are proven operable during testing of the Nuclear Boiler ADS and SRV. Also, in a study (BWR Owners Group Evaluation of NUREG-0737, Item II.K.3.16), the number of ADS and safety relief valve openings should be reduced as much as possible to minimize LOCA risk. Based on this study, and the potential for causing a LOCA condition, exercising these valves is delayed to refueling.
The solenoid valves are proven operable by remotely actuating the SRV to verify open and close capability of the reliefvalve prior to resumption ofelectric power generation. The design ofPNPP provides two solenoid valves for each SRV, with divisional separation of the solenoid valves, such that an SRV exercise only exercises one of the two solenoid valves. The solenoid operated valves will be tested at the Technical Specification Surveillance Required frequency of testing (i.e., every 18 months on a STAGGERED TEST BASIS for each valve solenoid). If a SRV fails to meet its
=reapt= ace criteria during cycling, the associated SRV solenoid valves will be evaluated to determine ifcorrective action should be taken. Therefore, the alternative test provides an acceptable level ofquality and safety."
Proposed Alternate Testing: Solenoid-operated valve exercising shall be performed during the exercising of the SRV(s) on a refueling outage frequency, in accordance with the Technical Specification Surveillance Requirements prior to resumption of electric power.
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Evaluation: OMa-1988, Part 10,14.2.1 requires the stroke time ofall power-operated valves to be measured quarterly ifpracticable, otherwise at cold shutdowns. Iffull-stroke exercising during cold shutdowns is also impracticable, it may be deferred to refueling outages. These ASME Class 3 solenoid valves provide air to the ADS and safety / relief valves. It is impractical to exercise these valves quarterly because that would cause operation ofthe ADS or safety /reliefvalves which would cause reactor pressure and power transients during operation. Additionally, it is impractical to exercise these valves during cold shutdowns, because frequent cycling of the ADS or SRVs may damage these valves and increase the probability that they will fail to close.
The ADS and SRW should be exercised when there is reactor steam available to warm the valve seating surfaces and not when the reactoris at low temperature and pressure during cold shutdowns.
OM Part 10,14.2.1.2(e) allows deferral ofexercising to refueling outages based on impracticability.
The licensee's altemative, however, provides for exercising one ofthe two solenoid valves assigned to each SRV at each refueling outage, on a staggered basis. There are two solenoid valves for each main valve. Operation of either solenoid valve will result in operation of the ADS /SRV. Testing of both solenoid valves would require each ADS /SRV to be operated twice each refueling. The licensee's proposal to alternate the tested solenoid valve each refueling outage, as required by the Technical Specifications, would minimize the ADS /SRV cycles and consequent valve damage.
Compliance with the Code would be considered impractical based on the potential for equipment damage. As discussed in the previous interval's NRC Safety Evaluation (Ref. 20), a sampling approach may be appropriate. However, ifone of the tested solenoid valves fails during a refueling outage, the remaining solenoid valves must be tested during that outage. This sampling approach i
would provide reasonable assurance of the valves' operation readiness. The licensee's current proposal does not reflect the provisional relief provided by the April 5,1993 Safety Evaluation.
Therefore, provided that if one of the tested solenoid valves fails during a refueling outage, the remaining solenoid valves are also tested during that outage, reliefis recommended in accordance with 10CFR50.55a(f)(6)(i).
3.4 Valve Relief Request VR-4, LPCS, RRR, and RCIC Keep Fill Pumps Discharge Cheek Valves ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 10, 14.3.2, which requires check valves to be exercised nominally every three months, except as provided by 14.3.2.2,4.3.2.3,4.3.2.4, and 4.3.2.5 for the LPCS, RHR, and RCIC keep fill pump discharge check valves.
Licensee 's Basisfor Relief "These simple check valves are the outboard check of a series pair for the safety-related keep fill pump discharge. They provide the high to low pressure interface to prevent overpressurization of the low pressure portion of the system.
Loth the associated inboard and involved outboard check valves are in close proximity to each other. At cold shutdown, these valves are exercised open by verifying proper keep fill system flow.
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The associated inboard stop check valves can be verified closed using the manual handwheel (in accordance with the guidance provided in September 26,1991, Supplement to the public meetings on Generic Letter 89-04). The system configuration does not include test connections between the involved outboard valves and their associated inboard stop check valves. Hence, the closure of the outboard check valves cannot be individually verified. De system would have to be redesigned and modified to perform the code required testing. Disassembly and inspection of these valves on a sampling basis to assess their closure capability provides a r-kle alternative to the Code test method.
The NRC staff previously accepted valve disassembly and inspection on a sampling basis as an attemative to full flow testing in Generic Letter 89-04, Attachment 1, Position 2. Due to the scope of the activity, the personnel hazards involved and system operating restrictions, this valve disassembly will be perfonned during reactor refueling outages."
ProposedAlternate Testing: A sample disassembly and inspection plan will be utilized. Sample groups may consist of more than four valves; however, all valves within each group must be disassembled within a maximum of four refueling outages. Dese valves are exercised open following their assembly by verifying proper keep fill pump flow.
Evaluation: The Code requires valves to be exercised to the position required to fulfill the valve's safety function. With respect to exercising the valves closed, verification that a valve is in the closed position can be done by visual observation, by an electrical signal initiated by a position-indicating device, by observation of appropriate pressure indication in the system, by leak testing, or by other positive means. Additionally, the Code allows the use of a mechanical exerciser or disassembly every refueling outage. Disassembly and inWon using a sampling program is an acceptable altemative, as discussed in Generic Letter 89-04, Position 2.
These valves have a safety function in the closed direction to prevent overpressurization ofthe low pressure core spray pumps and associated piping. It is impractical to verify the safety function of these valves to close using flow since these are simple check valves with no extemal means for determining obturator position. The only practical means available to verify closure capability of these valves is by disassembly and inspection. To require disassembly and inspection ofall valves each refueling outage would be a hardship without a compensating increase in the level ofquality and safety.
It is recommended the altemative be authorized in accordance with 10CFR50.55a(aX3Xii). The licensee should refer to the guidance provided in Generic Letter 89-04, Position 2. The licensee's proposal indicates that the sample program is consistent with Position 2, including partial-stroke exercising following reassembly. However, the licensee has stated that the valve group may contain i
more than four valves, with all valves within the group disassembled within four refueling outages.
j The request, however, only references four valves and does not specifically discuss the length of i
the refueling cycles.
As discussed in the Generic Letter, extension of the valve 14 1
4
i disassembly / inspection interval to longer than once every six years should be considered in cases of" extreme hardship." The Generic Letter provides the information needed to support an extension.
The NRC considers disassembly and inspection a maintenance procedure and not a test equivalent to the exercising produced by fluid flow. The licensee should investigate the use ofnon-intrusive techniques to verify the valves are closed. Additionally, the licensee has stated that because the valves are in series without intermediate test connections, individual closure of the outboard check valves cannot be verified. The licensee should evaluate if the guidance provided in NUREG-1482, Section 4.1.1 can be used. The licensee should document the evaluation.of nonintrusive testing techniques and the guidance provided in NUREG-1482, Section 4.1.1 in the relief request.
3.5 Valve Relief Request VR-5, Standby Diesel Generator Starting Air Valves.
ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 10, 14.2.1, which requires active Category A and B valves be tested nominally every three months except as specified by 14.2.1.2,4.2.1.5, and 4.2.17 for the standby diesel generator and HPCS standby diesel generator starting air valves 1E22-F541 A&B, IE22-F543A&B, IR44-F010A&B, 1R44-F011 A&B, IR44-F015A&B, IR44-F016A&B, 1R44-F020A&B, IR44-F021A&B, i
1R44-F025A&B, and 1R44-F026A&B.
Licensee 's Basisfor Relief "It is impractical to measure the stroke ti nes of these valves ha--
they are totally enclosed solenoid / air operated valves which have no externally visible indication of valve position. Failure of a valve to perform the required function will result in an increase in the starting time of the diesel generator or failure to secure starting air.
Division 3 HPCS requires both air start solenoids to open to satisfy its' starting time for operability, thus normal monthly timing verifies operability. Therefore, the proposed altemative provides an equallevel ofquality and safety.
Division 1 and Division 2 Standby Diesel Air Starting Systems have two independent air banks with each air bank having two parallel starting air solenoid valves. All four starting air solenoid valves are verified operable on a monthly basis during performance ofthe monthly diesel surveillance tests.
During performance ofmonthly diesel surveillance tests, a pre-start air roll and a post-shutdown air roll are performed on each standby diesel. During performance of the pre-start air roll, both air banks are operated and only one parallel starting air solenoid valve in each air bank is energized to roll the diesel. The two energized starting air solenoid valves (one in each air bank) are (1) verified open, by verification of a pressure decses in each air bank accumulator and (2) verified closed by verification of air being secured upon termination of the air roll. Likewise, the alternate solenoid valves (i.e., the other of the two parallel starting air solenoids in each air bank) are tested in the same manner during performance of the post-shutdown air roll.
In accordance with plant procedures, the air roll portion ofthe monthly surveillance is not permitted to be performed on an operable standby diesel if the other standby diesel is inoperable, since 15
performance of the air rolls on the operable diesel requires declaring the operable diesel inoperable, thus rendering both emergency diesel generators inoperable. Consequently, an extended diesel outage (i.e., greater than quarterly) may cause the operable diesel air start solenoids to exceed the quarterly test requirements. In such cases, the diesel starting air solenoid valves shall be verified operable by satisfactory performance of the monthly diesel runs.
i i
In summary, performance of monthly diesel air rolls provides an acceptable means of verifying diesel starting air solenoid valve operability. In those situations where conformance to the Code is impracticable for the facility, such as where monthly diesel air rolls cannot practicably be performed, monthly diesel runs shall adequately demcastrate diesel air start solenoid valve operability. Therefore, the proposed alternatives provide an equivalent level ofquality and safety.
l ProposedAlternate Testing: Diesel starting air valves shall be verified operable during monthly i
diesel generator surveillance testing.
The operability ofHPCS starting air valves shall be determined by monitoring HPCS diesel strrting time.
Normally, the operability of Div. I and Div. 2 starting air valves shall be determined during performance of monthly air rolls by using one solenoid from each air bank and verifying pressure decrease. However, air roll testing is not permitted to be performed on an operable standby diesel 1
if the other standby diesel is already inoperable. Therefore, ifone diesel remains inoperable for an j
extended period of time, the diesel starting air solenoid valves shall be verified operable by satisfactory performance of the monthly diesel run.
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Evaluation: The licensee has requested relief from OMa-1988, Part 10,14.2.1 because it is impractical to measure the stroke times of the starting air solenoid valves on the Division 1 and 2,.
j ami'11PCS diesel generators because of a lack of valve position indication. The valves are ccanpletely enclosed, with no extemal means to determine valve position.
OMa-1988, Part 10,14.2.1.3 states that "the necessary valve obturator movement shall be determined by exercising the valve while observing an appropriate indicator, such as indicating lights which signal the required change of obturator position, or by observing other evidence, such as changes in system pressure, flow rate, level or temperature, which reflect change of obturator position." Failure or significant degradation of these rapid-acting solenoid valves would be l
l indicated by sluggish diesel starting times or failure to secure starting air. However, measurement of the diesel start times does not directly indicate the valves' stroke time, as required by the Code.
In order to comply with the Code, system modifications would be required, such as replacement of the valves, which would be burdensome to the licensee.
Because the proposed testing provides a quantitative measure with a limit imposed (the diesel start l
time for the HPCS diesel generator and verification of air accumulator pressure decrease and that the air is secured for the Div. I and 2 Standby diesel air starting system) and the licensee proposes 16
I i
to test the valves monthly, unless impractical due to the other diesel being out of service, which is more frequent than required by the Code, the altemate test method provides an adequate level of quality and safety. Therefore, it is recommended that the alternative be authorized in accordance with 10CFR50.55a(a)(3)(ii).
3.6 Valve Relief Request VR-6, Pressure Relief Devices ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 10, 14.3.1 and 4.3.4 which require safety and relief valves and rupture disks to meet the requirements of OM-1987, Part I for all Code class pressure relief devices.
Licensee's Basisfor Relief "OM Part I has evolved over the past decade; such that itis now a Code (ASME OM Code-1995 Appen' dix I) as opposed to a Standard (ASMF/ ANSI OM Part 1-1987), and now provides guidance on establishing acceptance criteria, grouping of valves, and additional testing. Perry Nuclear Power Plant has evaluated the Standard OM Part 1-1987 versus OM Code 1995 Appendix I and determined that the requirements ofASME OM Code, Edition 1995 are preferred for performance ofinservice testing of nuclear power plant pressure relief devices.
Therefore, PNPP is requesting the use of the mandatory appendix, ASME OM Code-1995 Appendix I, Inservice Testing of Pressure Relief Devices in Light-Water Reactor Power Plants.
The use of this mandatory appendix is supported by the Proposed Rule Change to 10 CFR Part 50, dated December 3,1997. The proposed amendment for IST would require licensees to implement the 1995 Edition of the ASME Code for Operation and Maintenance ofNuclear Power Plants (OM Code) for Class 1, Class 2, and Class 3 pumps and valves prior to the start of a new 120 month interval."
ProposedAlternate Testing: Adopt the mandatory appendix, ASME OM Code-1995 Appendix I, Inservice Testing ofPressure ReliefDevices in Light-Water Reactor Power Plants as the mandatory Code for testing pressure relief devices.
Evaluation: This relief request is generic to all pressure relief devices in the licensee's IST program. The pressure relief devices include safety valves, relief valves, pilot operated pressure relief valves, power actuated pressure relief valves, non-reclosing pressure relief devices, and vacuum reliefdevices. These devices provide pressure reliefor overpressure protection in systems that are subject to IST. OMa-1988, Part 10,14.3.1 and 4.3.4 require safety and relief valves and rupture disks to meet the requirements of Part 1. As discussed in NUREO-1482, Section 4.3.9, OM-1987, Part I has numerous editorial errors. The NUREG provides guidance on the use of clarifications provided in later editions and addenda of the OM Code. The licensee has requested to use Appendix I of the 1995 Edition of the OM Code in its entirety. This Edition includes clarifications, as well as technical changes, to the requirements of OMa-1988 Part 1. The ASME OM Code-1995 is not currently referenced in 10CFR50.55a(b), but is included in the proposed rulemaking without any modification or limitation (Ref.16). The NRC staff, as part of the 17
rulemaking, reviewed the 1995 Edition of the OM Code and has found that the use of Appendix I provides an acceptable level ofquality and safety. Therefore, it is recommended that the licensee's proposal to use Appendix I cf the 1995 OM Code in its entirety for the testing of pressure relief devices be authorized in accordance with 10CFR50.55a(a)(3Xi).
3.7 Velve Relief Request VR-7, Containment Vacuum Breakers ReliefRequest: The licensee has requested relief from the requirements of the OM Code-1995, 11.3.7(b) which requires leak tests to be performed every two years unless historical data indicates I
a requirement for more frequent testing. 'Ihis request applies to containment vacuum breakers 1M17-F010,20,30, and 40.
\\
Licensec 's Basisfor Relief "These vacuum breakers are functionally tested every 31 days (i.e., full exercise) as required by Technical Specifications. In addition, Technical Specifications require that the opening pressure differential be verified for the vacuum breakers every 18 months. This testing ensures that the vacuum breaker valves will perform their intended function when required, which is to prevent a negative pressure inside the containment in relationship to the outside environment.
In addition to their primary function ofprotecting the containment from an underpressure condition, these valves also serve as primary containment isolation valves and are required to be tested for leakage on some periodic basis. 10CFR50 Appendix J, which sets forth the rules and conditions for containment leakage rate testing, has a section designated Option B - Performance Based Requirements. 'Ihis section permits leakage rate testing to be performed at intervals of up to five years, based on the valves performance history. Option B eliminated the prescriptive requirements that were deemed marginal to safety and allowed a components past performance to be the determining factor for the testing interval."
ProposedAlternate Testing: Leakage rate testing of the containment vacuum relief valves will be in accordance with the requirements of 10CFR50 Appendix J Option B (Performance-Based Requirements).
Evaluation: These valves open as required to limit containment intemal vacuum and close for containment isolation. OM Code-1995,11.3.7(b) (which is identical to OM-1987 Part 1, 11.3.4.3(b)) requires leak tests to be performed every two years unless historical data indicates a requirement for more frequent testing. In addition, these valves are required to be tested in accordance with 10CFR50 Appendix J. 10CFR50, Appendix J specifies both the frequency and method for testing various types of CIVs.
'Ibe ASME Code Committee recently approved an action to revise paragraph 1 1.3.7 (b) of the OM Code to clarify that leak test frequency is in accordance with Table 1 ( i.e., leakage test requirements for Category A valves are in accordance with 14.2.2) (ROM 97-10). Paragraph 4.2.2 requires containment isolation valves to be tested in accordance with Appendix J. No additional leak tests are required other than Appendix J, since these valves are not reactor coolant system pressure j
18
s isolation valves, nor have a leskage requirement based on other functions. Here are no other related mquirements. This change will be included in the 1999 Addenda of the OM Code. ne guidance in NUREG-1482, Section 4.3.9, states that the use of code clarifications may be used without further NRC approval if they are determined to be clarifications only and are documented in the IST program, nerefore, the proposal to test in accordance with Appendix J is acceptable.
The licensee should continue to hanant the use of this clarification in the IST Program.
The staff is ciomdly engaged in rulam= Mag to delete the limitation contained in 10CFR 50.55a(b)(2)(vii) that CIVs "must be analyzed in acevidance with paragraph 4.2.2.3(e) of OMa-1988, Part 10, and corrective actions for these valves must be made in accordance with paragraph 4.2.2.3(f) of Part 10 of ASME/ ANSI OMa-1988 Addenda to ASME/ ANSI OM-1987."
He licensee must, however, continue to meet this limitation on CIVs until the rulemaking is final.
Additionally, it should be noted that the Valve Test Table does not indicate that the valves will be exercised every 31 days per the Technical Specifications, ne licensee should revise the table to reflect that this testing fulfills the Code exercising requirements.
3.8 Valve Relief Request VR-8, CRD Rupture Disks J
ReliefRequest: He licensee has requested relief from the requirements of the OM Code-1995, Appendix I,11.3.6 which requires that all Class 2 and 3 non-reclosing pressure relief devices be replaced every five years, unless historical data indicates a requirement for more frequent replacement.
Licensee's Basisfor Relief "ne rupture units supplied with the Control Rod Drive (CRD),
Hydraulic Control Unit (HCU) Accumulator have an active safety function to provide overpressure protection to the HCU accumulator. He rupture units also have a passive safety function to maintain the nitrogen charge in the HCU accumulator, which in tum maintains the control rod scram (rapid insertion) capabilities. The rupture unit is designed to burst at 2000 to 2200 psig at 400*F, or 2550 to 2900 psig at 72*F, and has a normal operating pressure of 1750 psig.
If the rupture unit were to burst during normal plant operation, a CRD HCU low pressure alarm would annunciate in the control room. With a low pressure condition, the associated control rod would remain operable, but the control rod scram time would be declared " slow." The Perry Technical Specifications allow no more than 13 operable control rods to be declared " slow," and no operable control rod that is " slow" shall be adjacent to another operable control rod that is " slow" or a withdrawn control rod that is stuck. Hus, the increase in control rod insertion time would have a negligible effeet on the capability to safely shutdown the reactor. He affected rupture unit would then be replaced and the control rod retumed to service.
Dese rupturI discs are not subjected to operating conditions that cause degradation, as they are an inert environment (nitrogen blanketed) and remain at a relatively constant pressure. These devices also have a qualified life of 40-years as identified in the environmental qualification 19
[
program. Due to the high degree of reliability (only one reported failure in 1984 was recorded in the Nuclear Plant Reliability Data System) of these devices, replacement every five years would provide no significant increase in quality and safety but would present a hardship to the Owner, both in cost and radiation exposure."
l l
ProposedAlternate Testing: RepW~at ofthe Hydraulic Control Unit Rupture Discs will be at l
the Owners Discretion but not to exceed 40 years ofin-service life.
l l
Ewaluation: OM Part 10,14.4.2 requires rupture disks, that protect systems which perform a l
l required function in shutting down the reactor, in maintainir.g the cold shutdown condition, or in mitigating the consequences of an accident from overpressure, meet the requirements of Part I for l
non-reclosing pressure reliefdevices. Part 1,11.3.4.2, requires Class 2 and 3 non-reclosingpressure reliefdevices to be replaced every five years, unless historical data indicates a requirement for more frequent replacement.
At the March 1995 ASME O&M Committee Meeting,it was reported to the OM-1 Working Group that the BWR Owner's Group has reviewed the function of these rupture disks and h hed that their active function to rupture is not safety related. The Working Group has since then produced l
a white paper submitted with ASME Main Committee Letter Ballot #209 that describes the function and consequences ofthe rupture disk failing, and recommends that these rupture disks be excluded from testing in OM-1. This ballot has not been approved by the ASME. However, as discussed in Section 4.3.1 of NUREG-1482, if the rupture disks do not perform accessary safety or overpressure protection function, such that they are not naca-ry, they may be removed from the l
scope of the IST program.
l A number of utilities have removed these rupture disks from their IST program (e.g., Duane Arnold). Although they have determined that thee rupture disks at their facilities are not required i
to be replaced in accordance with Section XI,10CFR50.55a requires components to be tested and l
inspected to quality standards commensurate with the impunece of the safety function to be l
performed, in this case the passive pressure retaining function, and 10CFR50.65 would apply.
Each licensee must make the safety and/or code class determination for their specific facility. If the licensee has determined that these disks are within the scope of the regulations (i.e., are ASME l
Code Class) and are necessary for the protection of the nitrogen system from overpressure, then additional information is required to support the request.
To authorize approval under l
10CFR50.55a(a)(3)(ii), which states that attematives may be authorized when compliance with the requirements of the Code would result in a hardship or unusual difficulty without a compensating l
increase in the level of quality and safety, the licensee must provide information conceming the i
specific hardship ofcomplying with the Code, and a discussion of the safety function of the rupture l
disks including the conseque.nces ofpremature rupture during operation and failure to rupture when required.
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l l
It is recommended that relief as requested be denied. The licensee should review the classification l-and function of the control unit rupture disks and revise, if appropriate, the IST Program scope or resubmit the relief request to include information on how compliance with the Code requirement is'a hardship with'out a compan==+ing increase in the level ofquality and safety or comply with the provisions of the Code.
3.9 Valve Relief Request VR-9, RCIC Check Valves ReliefRequest: The licensee has requested relief from the requirements of OMa-1988, Part 10, 143.2, which requires each check valve to be exercised nominally every three months, except as provided by 143.2.2,43.23,43.2.4, and 43.2.5 for the RCIC check valves 1E51-F079 and F081.
Licensee 's Basisfor Relief: "The exercise and normal (closed) position verification ofIES 1-F079 and IE51-F081 will be performed during refueling outages due to restrictions on system operability and area radiation levels. The RCIC Vacuum Breaker Check Valves act as an integral unit (i.e.,
series pair) thus ensuring the turbine exhaust steam line pressure remains eq=lir*A and ensuring isolation ofthe containment atmosphere from the turbine's exhaust steam. Both the open and closed position exercise require significant test durations for equipment; installation, testing and removal.
Additionally, these check valves meet the NRC staff's position for series pair. Valve redundancy j
is provided due to the harsh / volatile operating environment and closure of only one valve assures satisfactory performance of their intended safety function. These valves are category "C" (no seat j
l leakage test) because any seat leakage is directed into the controlled containment environment.
Finally, the failure of both valves to pass the closure verification would require both valves to be repaired or replaced, as necessary.
' Each test method requires personnel to be located in high radiation fields for prolonged periods l
r while the plant is operating at power and requires the RCIC system to be removed from service for I
the duration ofthe test. Therefore, compliance with the quarterly exercise requirement would result in unusual difficulty and hardship without a compensating increase in the level ofquality and safety l
due to the increased exposure ofpersonnel to radiation and the prolonged period ofinoperability j
of a system required for safe shutdown."
l ProposedAlternate Testing: Exercise the series-pair, IE51-F079/F081, during refueling outage.
Evaluation: OMa-1988, Part 10,143.2.2 requires each check valve to be exercised in a manner l
which verifies obturator travel to the position required to fulfill its function nominally every three months. When check valves are located in series with no provisions for verifying that each valve can close, the NRC has provided guidance in NUREG-1482, Section 4.1.1. Reliefmay be granted to test pairs of valves in series provided that the licensee's safety analysis does not require both valves, and both valves are included in the IST program and are subject to equivalent quality assurance criteria. If the valve pair exceeds the acceptance criteria, both valves would be required to be declared inoperable, and corrective action taken for both valves, as necessary, before retuming them to service.
21
Dese check valves are located in series without intermediate test locations to test the valves individually. They are not equipped with position indication or external operators. De function of the RCIC vacuum breaker valves is to close to prevent steam from entering the suppression chamber vapor space and to open to break the vacuum created by condensing steam in the turbine exhaust line to prevent damage to the RCIC pump discharge piping. The penetration pressurization valves are located in the instrument air supply to the door seal accumulators, and have a safety function to close to maintain adequate seal pressure upon a loss ofinstrument air.
He licensee is unable to individually verify closure of these valves. Requiring installation of instrumentation to verify valve position would involve system redesign and modifications. These modifications would be burdensome to the licensee. However, the closure capability of the valve pairs in series could be verified by reverse flow leak testing or a pressure decay test. De RCIC valves are both classified as Code Class 2. The licensee has stated that only one RCIC valve is required to fulfill its safety function. Testing the pair would give reasonable assurance of operational readiness and supply a reasonable alternative to the Code test method provided that both i
valves are declared inoperable and repaired or replaced if excessive leakage is noted. This position is consistent with the guidance provided in Section 4.1.1 of NUREG-1482.
The penetration pressurization check valves are class MC per the IST program. The P&ID, D-302-762, Rev. H, Note 3 identifies the valves as Class 2 per ASME Section III. The licensee should review the Code Classification of the valves and revise the drawing or IST program accordingly. The licensee has not provided any information on the valves' treatment in the safety analysis, as discussed in NUREG-1482. This position in the NUREG can only be used if the safety analysis does not require both valves. Additionally, the licensee has not discussed the corrective actions that would be taken if the pressure decay test fails.
With regards to the test frequency, it is impractical to perform the closure verification or open exercise for the RCIC valves quarterly due to the need to remove the RCIC system from service for the duration of the test. Due to the importance of the RCIC system function and the lack of a redundant train, it is not prudent to perform this testing during plant operation at power. The licensee has discussed that the exercise would require significant test durations for equipment; installation, testing and removal. The need to set up test equipment would make this testing impractical to perform during cold shutdowns. Theref arc, the deferral of testing of the RCIC valves is in accordance with Part 10,14.3.2.2(e). (Note: HPCI valves at Fitzpatrick are tested at cold shutdowns.) The deferral of closure testing for the penetration pressurization check valves is addressed in Refueling Outage Justification RO-30. Based on the need to setup test equipment to perform a leak test, which the NRC has determined to be adequatejustification to defer testing until a refueling outage (Section 4.1.4, NUREG-1482), testing at refueling outages is in accordance with 14.3.2.2(e).
Therefore, it is recommended that the proposed alternative for the RCIC valves be authorized pursuant to 10CFR50.55a(a)(3Xii), on the basis that the licensee's proposed alternative provide reasonable assurance ofoperational readiness and that imposition of the Code requirements would 22
result in hardship without a compensating increase in the level ofquality and safety. The licensee should update the IST program with regards to the penetration pressurization check valves to address all the issues discussed in NUREG-1482, Section 4.1.1.
4.0 VALVE TESTING DEFERRAL JUSTIFICATIONS First Energy has submitted 15 justifications for deferring valve testing to cold shutdowns and 30 justifications for deferring testing to refueling outages. These justifications document the impracticality of testing 297 valves quarterly, during power operation. These justi6 cations were reviewed to verify their technical basis.
As discussed in Generic Letter 91-18 (Ref.17), it is not the intent ofIST to cause unwarranted plant shutdowns or to unnecessarily challenge other safety systems. Generally, those tests involving the potential for a plant trip, or damage to a system or component, or excessive personnel hazards are not considered practical. Removing one train for testing or entering a Technical Specification limiting condition ofoperation is not sufficient basis for not performing the required tests, unless the testing renders systems inoperable for extended periods of time (Reference NUREG-1482, Section 3.1.1). Other factors, such as the effect on plant safety and the difficulty of the test, may be considered.
Valves, whose failure in a non-conservative position during exercising would cause a loss ofsystem function, such as non-redundant valves in lines (e.g., a single line from the RWST or accumulator discharge), or the RHR pump discharge crossover valves for PWRs whose licensing basis assumes that all four cold legs are being supplied by water from at least one pump, should not be exercised during conditions when the system is required to be operable. Other valves may fall into this category under certain system configurations or plant operating modes, e.g., when one train of a redundant ECCS system is inoperable, non-redundant valves in the remaining train should not be cycled because their failure would cause a total loss of system function, or when one valve in a containment penetration is open and inoperable, the radund=t valve should not be exercised during this system configuration.
BNL's evaluation ofeach deferraljustificationisprovided in Appendix A, Tables A.1 and A.2. The anomalies associated with the specificjustifications are provided in Section 6.0 of this TER.
5.0 IST SYSTEM SCOPE REVIEW The review performed for this TER did not include verification that all pumps and valves within the scope of 10CFR50.55a and Section XI are contained in the IST Program and did not ensure that all
. applicable testing requirements have been identified. The IST Program's scope was, however, reviewed for selected systems. The pumps and valves in the Reactor Core Isolation Cooling, Low Pressure Core Spray, and the Emergency Closed Cooling Systems were reviewed against the requirements of Section XI and the regulations. The UFSAR was used to determine ifthe specified 23
valve categories and valve functions were consistent with the plant's safety analyses. The review results showed compliance with the Code, except for the items discussed in 6.D-1 through 6.D.4.
The licensee should review these items and make changes to the IST Program, where appropriate.
Additionally, the licensee should verify that there are not similar problems with the IST Program for other systems.
6.0 IST PROGRAM RECOMMENDED ACTION ITEMS Inconsistencies, omissions, and recommended licensee actions identified during the review of the licensee's second interval Inservice Testing Program are summarized below. The licensee should resolve these items in accordance with the evaluations presenteA in this report.
A.
GeneralRecommended Actions 1.
The page numbers provided in the Valve Testing Index do not reference the correct Valve Test Table pages and should be revised as appropriate.
B.
Recommended Actions For Relief Requests 1.
The licenwe has requested deferring flowrate measurements for the RHR, LPCS, HPCS, and RCIC waterleg fill pumps (PR-2, TER Section 2.2) because quarterly testing at the selected flow rate would result in the pumps being declared inoperable. The licensee should consider selecting a pump reference value which would not require taking a system out of service (i.e., at the normal flow running rates). Although, measuring flowrates at minimum flow would provide less information on the pump's operational readiness compared to those taken at full or substantial flow, it does not appear to be a hardship or impractical to comply with the Code requirements.
2.
In PR-4 and -5 (TER Sections 2.4 and 2.5), the licensee has requested generic relief for all smooth-running Code Class pumps (standby and normally operating). The NRC staffhas been reluctant to approve these requests due to the pump degradation experience at Catawba, but has reviewed a similar request from anotherlicensee which committed to including these pumps in a condition monitoring program. In this relief request, the licensee has not made a similar commitment in the proposed alternate testing, which the NRC staffhas determined to provide an acceptable level of safety. Based on the existence of a condition monitoring program, the licensee should ensure that the CM program would identify pump degradation demonstrating that the proposed altemate provides acceptable levels of quality and safety.
Interim reliefhas been recommended. The licensee must commit to including these pumps in the condition monitoring program and revise the reliefrequest to reflect this commitment in the interim period. The licensee must also discuss whether all vibration directions measured must be below the reference value for a pump to be considered smooth-running.
The licensee should also discuss the overall vibration level at which the pump would no longer be considered smooth-running.
24
3.
In PR-6 (TER Sect. 2.6), the licensee proposed to use digital instruments which would not have been adequate to monitor measured values in the alert or required action range. When selecting and using digital instruments for Code Class 2 and 3 pumps, the licensee should I
ensure that 110 percent of the measured parameter's reference value is within the instrument's calibrated range.
4.
The licensee should clarify the proposed alternate testing portion of VR-1 (TER Sect. 3.1) to state that the HCU accumulator pressure decay test will be performed.
l 5.
In VR-3 (TER Section 3.3), the licensee proposes to exercise the solenoid valve for one of the two ADS /SRV each refueling outage per the Technical Specifications. As discussed in the previous interval's NRC Safety Evaluation (April 5,1993), provisional re, lief was j
provided if a sampling approach was used whereby if one valve failed testing, the other l
would be tested during the same outage. The licensee's current proposal does not reflect l
that provisional relief and should be revised accordingly.
l 6.
The licensee has proposed a disassembly and inspection plan for the LPCS, RHR, and RCIC keep fill pump discharge check valves (VR-4, TER Section 3.4). The licensee has stated that the valve group may contain more than four valves, though the relief request only references four valves. The licensee has not provided information on the length of the refueling cycles. As discussed in Generic Letter 89-04, extension of the disassembly /
inspection interval to longer than once every six years should be considered in cases of
" extreme hardship " Additionally, the licensee should clarify in the request the inspection interval. The licensee should investigate the use ofnon-intrusive techniques to verify valve closure. The licensee should also evaluate the guidance provided in NUREG-1482, Section 4.1.1. This evaluation should be documented in the relief request.
7.
The licensee has proposed that the CRD Rupture Discs be replaced at the discretion of the licensee, and not in accordance with the Code (VR-8, TER Sect. 3.8). If the licensee has determined that these discs are within the scope ofthe regulations (i.e., ASME Code Class),
and are necessary for overpressure protection o'the nitrogen system, then additional information is r. quired. The licensee should provide information conceming specific hardship for complying with the Code, and a discussion of these components' safety function, including the consequences of premature rupture during operation or failure to i
rupture when required. The licensee should review the classification and function of the disks and revise the IST program, resubmit the request with the information requested, or comply with the provisions of the Code.
8.
The RCIC penetration pressurization check valves are Code Class MC per the IST Program (VR-9, TER Sect. 3.9). The P&ID, D-302-762, Rev. H, Note 3 identifies the valves as Class II per ASME Section III. The licensee should review the Code Classification for the valves and revise either the drawing or IST program accordingly. In addition, the proposed alternate testing is consistent with the guidance provided in NUREG-1482, Section 4.1.1.
25
However, the licensee has not provided any information on the valves' treatment in the safety analysis, as discussed in the NUREG. His position can only be used if the safety analysis does not require both valves. He licensee has also not discussed the corrective actions which would be taken if the pressure decay test fails.
C.
Recommeaded Actions For Deferral Justifications 1.
In CS-7, the licensee has stated that valve closure for the RCS pressure isolation testable check valves will be verified at cold shutdowns by verifying a position indication signal.
Dese normally closed valves <% not require flow to verify closure, and closure verification should be performed quarterly in accordance with the Code.
2.
The Valve Test Table indicate that the Nuclear Boiler Head Vent Lines valves are active.
Thejustification for CS-9 states that these valves are passive. He licensee should clarify j
the program.
1 3.
The licensee has stated that testing the motor-operated Reactor Water Cleanup CIV's (CS-10) would cause " prolonged system inoperability" and that the transients may be potentially damaging to the RWCU pump seals. Several BWRs (i.e., Susquehanna, Hope Creek, and Monticello) exercise the RWCU motor operated valves quarterly. The test of a MOV is momentary and does not appear to cause prolonged system inoperability. The I
licensee should evaluate if their specific situation is unique, such that testing during operation is impractical.
4.
The licensee has stated that it is impractical to exercise the RHR Containment Pool Cooling MOVs (CS-12) qur.rterly because if open, flow would be diverted from the reactor vessel.
Testing each of these MOVs would require removing one train of RHR from service and entering a LCO for a short period of time. As discussed in NUREG-1482, Section 3.1.2, entry into a LCO alone is not sufficientjustification for deferring testing. If the purpose of the referenced reactor pressure interlock is to protect equipment from overpressurization, testing that could potentially damage the equipment would not be practical. The licensee should review the testing for these valves and revise the IST Program accordingly.
5.
The licensee has proposed testing the ECCS waterleg pump check valves (CS-13) at cold shutdowns. These pumps are tested both quarterly and cold shutdowns (PR-2). The licensee should evaluate if the quarterly lower flow test is adequate to full-stroke exercise these check valves or if the quarterly test is a partial-stroke exercise, and revise the justification accordingly.
6.
De licensee has stated that a reverse flow test ofvalve 1 E21-F0501 (LPCS minimum flow and test retum to suppression pool check valve) (RO-2) during refueling outages is possible, but " requires expenditure of significantly more resources than simple removing the valve for exercise testing." The Code allows disassembly and inspection as an alternative to l
1 26
]
J
l exercising with flow or a mechanical exerciser. The intent of the Code is that disassembly and inspection can only be used if exercising with flow or a mechanical exerciser is impractical. The licensee should reverse flow test this valve at refueling outages and revise thejustification accordingly.
7.
The licensee has proposed disassembly and in=~4_ ion for valve IE22-F007, the inboard valve of a series pair (RO-2). The licensee should consider the guidance provided in NUREG-1482, Section 4.1.1 to detennine if a leak test could be used to verify the closure of the valve pair in lieu of disassembly and inspection.
8.
The licensee has stated that disassembling valve IE51-F047 (RCIC turbine exhaust drain line check valve) (RO-2) is required for system maintenance. Disassembly and inspection is a option where exercising with flow or a mechanical exerciseris impractical. The' licensee should evaluate whether there are other means (e.g., leak testing) to verify valve closure.
Convenience is not a sufficientjustification for not exercising with flow.
9.
The RWCU system does not serve a safety-related function, except for the valves that isolate the containment penetrations. In RO-4, valves 1G33-F052A and B appear to only have a safety function to close. The licensee should review the safety function ofthese valves and revise the IST Program accordingly.
4 10.
In RO-9, the licensee has stated that the RHR valves provide no safety function. However, per the Valve Test Table, they are exercised open. If the licensee is optionally exercising these valves open, it should be noted in the Program as an augmented inspection. The licensee has discussed the impracticality ofusing non-intrusive techniques to verify closure.
However, there is no discussion of the use of a leak test during refueling outages. The licensee should investigate the use ofleak testing and revise thejustification accordingly.
I 1..
The licensee should alternate the shutdown cooling loop chosen during cold shutdowns, so both shutdown cooling loop valves are exercised (RO-11 and RO-12).
12.
The licensee has implied in RO-12 that testing at cold shutdown is impractical based on generation of radwaste. The upmem MOV, IE12-F023 is exercisd at ccid shutdowns (CS-3). It appears that exercising this valve would also require flushing the head spray lines since there are no downstream isolation valves. Although this would generate liquid radwaste, three valves would have their operational readiness verified (IE12-F019, IE51-F065, and 066 (RO-25)). Other plants (e.g., WNP-2) exercise this valve at cold shutdowns. The licensee should reevaluate the testing and determine if Perry has a unique iss'ue which makes testing at cold shutdowns impractical.
13.
In RO-13, it is not npparent why the normally open CRDH check valve C11-F122, with a downstream flow element, cannot be exercised open quarterly. The licensee should also clarify the Basis for Justification and the Altemate Testing sections to indicate that the other i
27
l 1
valves are exercised quarterly, as well as when the systems are placed back in service following a refueling outage.
14.
In RO-17, the airlock check valves are verified open every time the airlock door is used, which is not restricted to refueling outages. The open exercise does not appear to require equipment installation or removal. The licensee should review the testing of these valves and revise the justi6 cation to provide additional information to support testing only at refueling outages.
15.
A review of P&ID D-302-271 indicates that valves 1P57-F572B and 574B are not located inside containment, which is used as a basis for not testing quarterly or at cold shutdowns (RO-19). Additionally, it does not appear that testing these valves would make the MSIVs l
inoperable, as there are additional check valves in series and air is available from the ADS safety-related air storage tank B. The licensee should review the testing performed on these valves and determine and document the basis for the impracticality. Ifleak testing is required to verify the valves' safety function, NUREG-1482, Section 4.1.4 may be referred to for guidance, if the justification is based on ALARA, NUREG-1482, Secticn 2.5.1, should be referenced. In addition, valves 1B21-F024A-D and IP57-F572B and 574B are Code boundary valves which appear only to have a safety function to close. The licensee should review the function of these valves and revise the IST Program accordingly.
16.
Numerous valve deferraljustifications (e.g., RO-19 and RO-22) state that compliance with the exercise requirements would result in unusual difficulty without a compensating increase in the level of quality and safety. In accordance with the Code, testing may be deferred solely based on the impracticality of testing during operation or cold shutdowns. If the deferrals are based on the hardship or unusual difficulty in complying with the Code, without a compensating increase in the level of quality and safety, relief must then be authorized in accordance with 10CFR50.55a(a)(3)(ii).
17.
In RO-20, the valves are described as being the safety interface between the RPV level reference leg and the non-safety portion of the CRD system. These valves appear to have only a safety-related function to close. The licensee should review the function of these valves and revise the IST Program accordingly. In addition, the drawing coordinates referenced in the Valve Test Table for these valves are incorrect.
l l
18.
In RO-22, the licensee has identified the components which would be afrected by exercising air supply valve IP52-F550. There is no discussion of the consequences of securing the non-safety related instrument air to these components (e.g., plant transient or scram). The downstream motor-operated valve,1P52-F200 is exercised quarterly. The licensee should providejustification of the impracticality of exercising the valves quarterly or during cold shutdowns, rather than discussing the hardship.
28 l
i 19.
In RO-23, containment entry alone (unless it is inerted) is not adequate justification for deferring testing. The licensee has stated that testing "could possibly make the associated SRVs inoperative." Check valves IP57-F524A and B are located upstream of the SRV accumulators and associated check valves. It is not apparent why this testing would make the SRVs inoperable. The licensee should provide additional information on why entering containment is impractical and why the SRVs would be inoperable.
20.
The licensee has not provided basis for the determination that it is impractical to exercise the PIVs in RO-25 open at cold shutdowns. With regards to the closure verification, PIV 1E51-F066 is normally closed and has position indication. It appears that the closure ofthis valve can be' verified quarterly. An exercise open is not a prerequisite for the closure verification. The licensee should review the testing of these valves and revise the justification accordingly.
D.
Recommended Actions For System Review I.
Reactor Core Isolation Coolina Svetem 1.
On P&ID D-302-631, the RCIC pump discharge MOV to the reactor vessel (valve 1E51-F013) appears to be normally open. Likewise, the RCIC pump discharge MOV to the
]
suppression pool (valve 1E51-F019) also appears to be normally open. However, the Valve Test Table for both valves indicates that they are normally. closed. The licensee should review the safety function of these valves and revise the IST Program ifnecessary.
2.
Testable check valve (1E51-F066) is located inside the drywell. There is a check valve (1 E51-F547) and a stop check valve (1E51-F548) which appears to supply water for testing of valve F066. These valves appear to form the boundary between safety-related and non-safety related piping. Likewise, downstream, there is a check valve F541and a globe valve F544 which also appear to form the interface between safety-related and non-safety related piping. These four valves do not appear on the Valve Test Tables. The licensee should review the function of these valves and modify the IST Program if m'y.
II.
Lpw Pressure Core Sorav 3.
On P&ID D-302-705, there is a stop check valve (E21-F526) and check valve E21-F525 which appear to supply water for the testing ofvalve E21-F006. Neither of these valves are included in the Valve Test Table. The licensee should review the function of these valves to ensure they do not have a safety function in the closed direction to prevent RCIC flow diversion and revise the IST Program if necessary.
29
L 1
l l
IIL Nuclear Closed Cooline Svetam 4.
On P&ID D-302-613 (Nuclear Closed Cooling System), valves P43-F783 and IP43-F722 are located on the containment side ofpenetration 2039. Neither of these valves are listed in the Valve Test Table though they appear to serve as the bound::ry between safety related and non-safety related piping. "Ihe licensee should review the safety function of these l
valves and revise the IST Program if ma===y. Valve IP43-F215 is listed in the IST l
Pivy.= and appers to serve as boundary Mries safety and non-safety related piping.
i However, the P&ID does not show this boundary. The licensee should review this valve on I
the P&ID and revise as m y.
7.0 REFERENCES
1.
L. Myers, First Energy, to USNRC, " Submittal of Inservice Pump and Valve Relief l
Requests for Second 120-month Interval," PY-CEI/NRR-2290L, July 22,1998.
1 2.
- L. Myers, First Energy, to USNRC, " Supplemental Submittal of Inservice Pump and Valve ReliefRequests for Second 120-month Interval," PY-CEI/NRR-2350L, December 17,1998.
3.
Perry Operations Manual, " Pump and Valve Inservice Testing Program Plan," Revision 4, Effective November 18,1998.
4.
Title 10, Code of Federal Regulations, Section 50.55a, Codes and Standards.
l 5.
ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components,1989 Edition.
6.
ASME/ ANSI OM-1987, Part 1, " Requirements for Inservice Performance Testing of Nuclear Power Plant Pressure Relief Devices."
7.
ASME/ ANSI OMa-1988, Part 6, " Inservice Testing ofPumps in Light-Water Reactor Power Plants."
8.
ASME/ ANSI OMa-1988, Part 10, " Inservice Testing of Valves in Light-Water Reactor Power Plants."
l 9.
Standard Review Plan, NUREG-0800, Section 3.9.6, Inservice Testing of Pumps and Valves, Rev. 2, July 1981.
10.
NRC Generic Letter 89-04, " Guidance on Developing Acceptable Inservice Testing Programs," April 3,1989.
I 1.
Minutes of the Public Meetings on Generic Letter 89-04, October 25,1989.
30 i
i 12.
Supplement to the Minutes ofthe Public Meetings on Generic Letter 89-04, September 26, i
1991.
1-13.
NUREG-1482, " Guidelines for Inservice Testing at Nuclear Power Plants," April 1995.
I 14.
NUREG/CR-6396, " Examples, Clarifications, and Guidance on Ibyering Requests for Relief from Pump and Valve Inservice Testing Requirements," February 1996.
15.
Memo to File, "Summ=y of Public Workshops held in NRC Regions on laspection Procedure 73756, ' Inservice Testing ofPumps and Valves,' and Answers to Panel Questions on Inservice Testing issues " from J. Colaccino, NRC, July 18,1997.
16.
Federal Register, Volume 62, Number 232, Page 63892, " Proposed Rule on Industry Codes and Standards," D~+=M 3,1997.
17.
NRC Generic Letter 91-18, "Information to Licensees regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability," November 7,1991.
18.
Sage, L., " Introduction to ASME/ ANSI OMa-1988, Part 6, Basis of the New Vibration Measurement Criteria and Requirements of Part 6," Published in NUREG/CP-Olli, Proceedings of the Symposium on Inservice Testing of Pump and Valves," August 1990.
19.
Perry Technical Specifications.
20.
" Safety Evaluation oftheInsenice Testing Program ReliefRequests For Pumps and Valves-Perry Unit 1," TAC No. M61257, April 5,1993 21.
Regulatory Guide 1.26, " Quality Group Classifications and Standards for Water, Steam,
and Radioactive-Waste Containing Components ofNuclear Power Plants," Rev. 3, February 1976.
l.
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[ Valve Relief Request VR-10, All Category A and AC Valves Requiring Periodic Leakage Rate Testing With the Exception of Containment isolation Valves Relief Request: The licensee has proposed an attemative to the leak rate test frequency requirements for valves other than containment isolation valves of OM-10, Paragraph 4.2.2.3(a). The Code requires that leakage rate testing be conducted once every 2 years. The valves included in the proposed altemative are listed below and are categorized by component function. ACCUMULATOR PRESSURE BOUNDARY LEAKAGE l MSlV (main steam isolation valve) Inboard Accumulator Supply Check valves (1821-F024A/B/C/D) MSIV Outboard Accumulator Supply Check valves (1821-F029A/B/C/D) Safety Related Air "A" Accumulator Supply Check Valves (1P57-F555A & F556A) Safety Related Air "B" Accumulator Supply Check Valves (1P57-F555B & F5568) Outboard MSIV Accumulator Normal Supply Check Valves (1P57-F5728 & F5748) Airlock Door Accumulator Air Supply Check Valves [1P53-F587B & F588B (Upper Inner Door), 1P53-F587A & 1P53-F588A (Upper Outer Door),1P53-F572B & F5738 (Lower Inner Door), 1P53-F572A & F573A (Lower Outer Door)] Airlock Door Accumulator Air Supply Check Valves 1P53-F601B & F6028 (Drywell Inner Door), and 1P53-F601 A & F602A (Drywell Outer Door)] INSTRUMENTATION LEAKAGE ISOLATION ^ i Reactor Vessel Reference Level Backfill Supply Check Valves (1821-RO11 A-F, RO11 A-G, R011B-F, RO11B-G, R011C-F, RO11C-G, RO11D-F and RO11D-G) Containment Atmosphere and Water Level Instrument isolation Valves (1D23-F010A/B, F020A/B, F030A/B, F040A/B & F050,1M17-F055 & F065 and 1G43-F050A/B & F060) REACTOR COOLANT PRESSURE ISOL ATION RHR (residual heat removal) Injection Line inboard Isolation Check Valves (1 E12-F041 A/B/C) and RHR Injection Line Outboard Isolation Motor Operated valves (1E12-F042A/B/C) LPCS (Iow pressure core spray) Injection Line inboard Isolation Check Valve (1E21-F005) and LPCS Injection Line Outboard Isolation Motor Operated valve (1E21-F006) HPCS (high pressure core spray) Injection Line Inboard Isolation Check Valve (1E22-F004) and LPCS injection Line Outboard Isolation Motor Operated Valve (1E22-F005) l
, SLC (standby liauid control) Injection Line inboard and Outboard Check Valves (1C41-F006 & F007) RHR Shutdown Cooling inboard Isolation Valves (1E12-F009 & F550) and Outboard Isolation Motor Operated valve (1E12-FOO8) RCIC (reactor core isolation cooling) Head Spray Inboard and Outboard Isolation Check Valves (1E51-F066 & 1E51-F065) HIGH-TO-LOW SYSTEM INTERFACE PRESSURE ISOLATION RHR Head Spray Inboard Isolation Check Valve (1E12-F019) and Outboard Isolation M'otor Operated Valve (1E12-F023) RHR Shutdown Cooling Isolation Check Valves (1E12-F050A/B) and Isolation Motor Operated Valves (1E12-F053A/B) FWLCS (feedwater leakage control system) Supply Inboard Isolation Check Valves (1N27-F739A/B & 1N27-F742A/B) and Outboard Isolation Motor Operated valves (1N27-F737 & F740) PRIMARY COOLANT LEAKAGE PATHWAY TO ATMOSPHERICALLY VENTED TANKS SYSTEM LEAKAGE INTEGRITY Nuclear Closed Cooling (NCC) System To ECC Cross-Tie isolation valves j (P42-F295A/B & P42-F325A/B) PARALLEL PUMP BYPASS FLOW SLC Pump Discharge Check valves (1C41-F033A/B) Licensee's Basis for Relief: "A Performance-Based Testing Program has been developed which would eliminate the prescriptive test frequency requirements and allow test intervals to be based on system and component performance. Through its own Regulatory Improvement Program, the NRC has institutionalized an ongoing effort to eliminate requirements marginal to safety and to reduce the regulatory burden on utilities. A performance-based testing program, utilizing an 1 extended testing interval based on the successful completion of 2 or more consecutive leakage rate tests, would take advantage of the findings of NUREG-1493, Appendix A. The conclusions drawn by the NUREG suggest that 'if a component does not fail within two operating cycles, further failures appear to be govemed by the random failure rate of the component'. The NUREG also states that any test scheme considered, should require a failed component to pass at least two consecutive tests before allowing an extended test interval. The Performance-Based Testing Program for ASME Section XI valves requiring leakage tests, was developed in much the same manner as the Option B Program for Appendix J testing, which was permitted by amendment of the Code of Federal Regulations on 10-26-95. In the
' studies performed in support of the code change, it was concluded that performance-based testing is feasible without significant risk (NUREG 1493). Also, EPRI Research Project Report l TR-104285, ' Risk Impact Assessment of Revised Containment Leak Rate Testing Intervals,' I reaffirmed this position by stating that changes in leakage testing frequencies are feasible without significant risk impact. The development of this performance-based testing program started with the generation of a leakage test history for each valve that is to be included in the program. Then a review of the test histories for each valve was conducted to establish if a minimum of two (2) consecutive periodic tests had passed and whether any erratic behavior could be detected. All the valves were then placed into a type category (i.e., check, globe, gate, etc.) to establish which types may be more prone to failure. By performing this, a direct comparison could be made of like valves in like systems to determine if some of those valves with good test histories should be monitored more frequently. Valves that pass a minimum of 2 consecutive tests without any erratic behavior and are not considered suspect valves will be put on an extended interval of 4 years or 2 refueling cycles, whichever is longer. Any valve not meeting the minimum threshold requirement will be left on a 2-year test interval until at least 2 consecutive tests are acceptable. In addition, if a failure occurs on any extended interval valve, the initial test frequency of 2 years must be re-established until two consecutive tests pass." Proposed Attemate Testing: Leakage rate testing of Category A and AC valves will be performed in accordance with the ASME Section XI Performance-Based Testing Program. Valves that have met the threshold of passing two consecutive tests will be permitted to be tested every 4 years or 2 refueling cycles, whichever is longer. Valves which fail their acceptance criterion will be tested during each refueling outage until they pass a minimum of two consecutive tests. Evaluation: The Code requires that Category A and AC valves which are not containment isolation valves (CIVs) be leak tested at least once every two years. The licensee has proposed that for certain Category A and AC valves listed above, the leak test interval be extended to once every four years or two refueling outages, whichever is longer, provided that - the valves have passed the previous two leakage tests. Valves that fail leakage testing which are on the extended interval would revert to the Code frequency again until they passed two consecutive leakage tests. The philosophy espoused in the proposed attemative is similar to the requirements specified in 10 CFR 50, Appendix J, Option B, for Type C testing of CIVs. NURER-1493, " Performance-Based Containment Leak-Test Program," discusses the risk impacts of extending the leak test interval for CIVs. Nuclear Energy Institute (NEI) document NEl 94-01, " industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," provides implementation guidance. In its endorsement of the NEl guidance document in l Regulatory Guide 1.163, the staff placed certain conditions on Option B testing including a restriction on the extension of the interval for Type C testing to a maximum of 60 months and to maintain the current leakage rate test interval for main steam and feedwater isolation valves in boiling water reactors and containment purge valves in boiling and pressurized water reactors.
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- The Code requires that CIVs be tested in accordance with 10 CFR 50, Appendix J. The licensee has stated correctly, as discussed in NUREG-1493, that changes in leakage testing frequencies are feasible without significant risk impact for CIVs. An endorsement of the NEl guidance document in Regulatory Guide 1.163 (with limitations) results in a change to the Code testing requirements for CIVs. There was no discussion in the licensee's submittal with respect to the risk significance for extending the test interval of reac%r coolant system (RCS) pressure isolation valves (PlVs). The licensee's technical specifications (TS), which adopt the improved standard TS, state that PlVs should be tested in accordance with the inservice testing program.
The Code test frequency requirements for Category A and AC valves that are not CIVs is 24 months. Previously, the test interval referenced in the TS was 24 months which is consistent with the current Code requirement. Changing the reference in the TS to reference the Code eliminates the need for licensees to submit a TS change request when the Code is changed. However, when there is an application to propose an attemative method of testing, merely suggesting that there is no conflict with the TS does not address the underlying issue of whether a change in the Code testing provides an acceptable level of quality and safety. Evaluation of the licensee's request will be divided into two separate categories: Category A or AC valves which are not RCS PlVs and Category A or AC valves which are RCS PlVs. Using the licensee's valve group designations, the first category of valves includes the following: accumulator pressure boundary leakage, instrumentation leakage isolation, primary coolant leakage pathway to atmospherically vented tanks system leakage integrity, high-to-low system interface pressure isolation (FWLCS valves only), and parallel pump bypass flow. These groups of valves have not been designated as ClVs, and either do not have direct contact with the reactor coolant system or are in systems that are designed for high pressure (standby liquid control system). The staff agrees with the licensee that the findings of NUREG-1493 for leak rate testing of Type C valves can also be applied to valves which are not CIVs. Specifically, as stated in Appendix A of NUREG-1493, that if the component does not fail a_ leakage rate test within two operating cycles, "further failures appear to be govemed by the random failure of the component." The licensee's proposed altemative testing is consistent with the guidance in NUREG-1493 and the leakage test interval extension is four years or two refueling outages as opposed to five years for Type C testing under 10 CFR 50, Appendix J, Option B, and is thus more conservative than was allowed for leakage testing of CIVs. Therefore, the proposed attemative for the valve groups specified above provides an acceptable level of quality and safety. The second category of valves includes the remaining groups of valves: reactor coolant pressure isolation and high-to-low system interface pressure isolation (with the exception of the FWLCS valves). These valves are RCS PlVs. They are associated with interfacing system loss-off-coolant accident (ISLOCA) issues. NUREG-1493 did not specifically address the impact on safety where CIVs were also RCS PlVs. Regulatory Guide 1.163 endorsed the NEl guidance document but placed limitations on certcin valves whose frequencies could not be extended. In discussions with staff on the limitations, additional limitations were not precluded from being imposed on valves that were not within the scope of NUREG-1493. NRC Information Notice 92-36, Supplement 1, "Intersystem LOCA Outside Containment," states, "the susceptibility to an ISLOCA is highly plant specific. ISLOCA contributors important
F I at one plant are not necessarily important at another." The staff encouraged inclusion of ISLOCA issues in individual plant examinations (IPEs). In order to make a determination that the increase in the test interval of RCS PlVs provides an acceptable level of quality and safety, information conceming the risk impact of the extended interval must be evaluated by the staff. The licensee may find useful a recent limited scope, risk-informed evaluation dated July 23,1999, in which the staff approved an extension of test 1 intervals of several CIV check valves approving the extension of test intervals of several check valves for the South Texas Project. The altomative to the leak rate test frequency requirements of OM-10, Paragraph 4.2.2.3(a) for the accumulator pressure boundary leakage, instrumentation leakage isolation, primary, coolant i leakage pathway to atmocpherically vented tanks system leakage integrity, high-to-low system l interface pressure isolation (FWLCS valves only), and parallel pump bypass flow valve groups is I authorized pursuant to 10 CFR 50.55a(a)(3)(i) based on the attemative providing an acceptable i . level of quality and safety. The sitemative from the leak rate test frequency requirements of OM-10, Paragraph 4.2.2.3(a) for the reactor coolant pressure isolation and high-to-low system interface pressure isolation l (with the exception of the FWLCS valves) valve groups is not authorized. The licensee is encouraged to resubmit the proposed attemative and include risk information that would justify the extension of the test interval for these RCS PlVs. l l l l i <}}