ML20056D271
| ML20056D271 | |
| Person / Time | |
|---|---|
| Site: | Vermont Yankee File:NorthStar Vermont Yankee icon.png |
| Issue date: | 06/30/1993 |
| From: | Ransom C EG&G IDAHO, INC. |
| To: | NRC |
| Shared Package | |
| ML20056D272 | List: |
| References | |
| CON-FIN-L-2594 EGG-RTAP-10778, TAC-M85067, NUDOCS 9308110246 | |
| Download: ML20056D271 (50) | |
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ENCLOSURE 2 (to SE)
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EGG-RTAP-10778 i
a TECHNICAL EVALUATION REPORT PUMP AND VALVE INSERVICE TESTING PROGRAM VERMONT YANKEE NUCLEAR POWER STATION Docket Number 50-271
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C. B. Ransom i
Published June 1993 i
i Idaho National Engineering Laboratory EG&G Idaho, Inc.
Idaho Falls, Idaho 83415 Prepared for the U.S. Nuclear Regulatory Commission Washington, D. C. 20555 Under DOE Contract Number DE-AC07-761D01570 FIN Number L2594, Task Order Number 4 TAC Number M85067
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l ABSTRACT i
This report presents the results of our evaluation of the Vermont Yankee Nuclear Power Station Inservice Testing program for safety-related pumps and valves.
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i PREFACE i
This report is part of the " Technical Assistance in Support of Operating Reactors Inservice Testing Relief Requests" program conducted for the U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Mechanical Engineering Branch, by EG&G Idaho, Inc., Regulatory and Technical i
Assistance Programs.
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FIN No. L2594 B&R No. 920-19-05-02-0 Docket No. 50-271 TAC No. M85067 1
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CONTENTS ABSTRACT ij PREFACE.................................
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1.
INTRODUCTION 1
I 1.1 IST Program Description...................
I 1.2 IST Requirements I
1.3 Scope and Limits of the Review 2
2.
PUMP TESTING PROGRAM 3
2.1 Service Water Pumps......................
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2.1.1 Establishing Reference Flow or Differential Pressure..
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2.2 High Pressure Coolant Injection Pumps.............
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2.2.1 Testing the Main and Booster Pumps as a Unit......
8 2.2.2 Full-Scale Range of Pressure Instrument 9
2.2.3 Vibration Acceptance Criteria 10 l
2.3 Core Spray Pumps 12 1
l 2.3.1 Full-Scale Range of Pressure Instrument 12 2.4 Reactor Core Isolation Cooling Pump..............
13 2.4.1 Full-Scale Range of Pressure Instrument 13 l
2.5 Reactor Building Closed Cooling Water Pumps..........
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2.5.1 Establish Reference Flow or Differential Pressure 15 2.5.2 Full-Scale Range of Pressure Instrument 17 2.6 Diesel Fuel Oil Transfer Pumps 18 2.6.1 Flow Rate Measurement 18 3.
VALVE TESTING PROGRAM 22 3.1 Residual Heat Removal Service Water System 22 3.1.1 Category B Valves 22 3.2 Service Water System 23 3.2.1 Category B Valves 23 3.2.2 Category C Valves 25 4
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3.3 High Pressure Coolant Injection System 26 i
3.3.1 Category B Valve 26 i
3.4 Control Rod Drive Hydraulic System 27 3.4.1 Category A/C Valves 27 i
l 3.5 Standby Liquid Control System.................
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3.5.1 Category C Valves 29 5
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3.6 Residual Heat Removal System 30 l
3.6.1 Category A Valves 30 3.7 Reactor Core Isolation Cooling System..
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i; 3.7.1 Category B Valves 33 i
3.8 Diesel Generator Air Start System.
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3 3.8.1 Category B Valves 34 i
i 3.9 Diesel Generator Fuel Oil Transfer System...........
35 3.9.1 Category C Valve 35 3.10 Nuclear Boiler System 37 I
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3.10.1 Category B/C Valves 37 APPENDIX A - IST PROGRAM ANDMAllES A-1 i
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j TECHNICAL EVALUATION REPORT i
PUMP AND VALVE INSERVICE TESTING PROGRAM VERMONT YANKEE NUCLEAR POWER STATION I
1.
INTRODUCTION j
This report provides the results of the technical evaluation of certain relief requests from the pump and valve inservice testing (IST) program for Vermont Yankee Nuclear Power Station submitted by Vermont Yankee Nuclear Power Corporation.
Section 2 presents Vermont Yankee Nuclear Power Corporation's bases foe 4
equesting relief from the requirements for pumps followed by an evaluation and conclusion.
Section 3 presents similar information for valves.
Appendix A lists program inconsistencies and omissions, and identifies needed program changes.
i 1.1 IST Proaram Descriotion t
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Vermont Yankee Nuclear Power Corporation submitted Revision 13 to their
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IST program with a letter to the Nuclear Regulatory Commission (NRC) dated l
November 30, 1992.
The IST program is dated November 1992, and covers the I
third ten-year interval of September 1, 1993 to August 31, 2003.
The licensee's program is based on the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the Code),
Section XI, 1989 Edition and the Code of Federal Regulations (CFR),
The 1989 Edition of Section XI prescribes that pump and valve 3
inservice testing be performed in accordance with the requirements of the i
ASME/ ANSI OMa-1988 Addenda to ASME/ ANSI OM-1987.
The NRC staff approved use of this Edition of the Code in a P. M. Sears letter to L. A. Tremblay dated September 2, 1992.
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1.2 IST Reauiren nli l
j 10 CFR 50.55a(f) states that IST of certain ASME Code Class 1, 2, and 3 4
pumps and valves will be done according to the ASME Code,Section XI, Subsections IWP and IWV, except where relief is granted by NRC in accordance with 10 CFR 50.55a(a)(3)(i), (a)(3)(ii), or (f)(6)(i).
Vermont Yankee Nuclear Power Corporation requests relief from the ASME Code testing requirements for i
specific pumps and valves.
Certain of these requests are evaluated in this i
technical evaluation report (TER) using the acceptance criteria of the
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Standard Review Plan, Section 3.9.6, NRC Generic letter No. 89-04 (GL 89-04),
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" Guidance on Developing Acceptable Inservice Testing Programs," and 10 CFR j
50.55a.
Other requests in the licensee's IST program that are not evaluated in this TER, may be granted by provisions of GL 89-04, addressed in previously j
issued NRC Safety Evaluations, or solely involve non-Code Class 1, 2, or 3
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components.
In rulemaking to 10 CFR 50.55a effective September 8, 1992 (See 57 Federal Reoister 34666), the 1989 Edition of ASME Section XI was incorporated i
in 1 (b) of 9 50.55a.
The 1989 Edition of Section XI provides that the rules for IST of pumps and valves are as specified in ASME/ ANSI Operations and Maintenance Standards Part 6 (OK-6), inservice Testing of Pumps in Light-Water l
Reactor Power Plants, and Part 10 (OM-10), Inservice Testing of Valves in
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Light-Vater Reactor Power Plants.
Pursuant to 1 (f)(4)(iv), portions of editions or addenda may be used provided that all related requirements of the respective editions or addenda are met, and therefore, relief is not required for those inservice tests that are conducted in accordance with OM-6 and GM-10, or portions thereof.
Whether all related requirements are met is subject to NRC inspection.
1.3 Scope and Limits of the Review i
The scope of this review includes, but is not limited to, the cold l
shutdown justifications, refueling outage justifications, and relief requests l
for safety-related Code Class 1, 2, and 3 pumps and valves submitted with the licensee's IST program. Other portions of the program, such as general discussions, pump and valve test tables, etc., are not necessarily reviewed.
d Endorsement of these aspects of the program by the reviewer is not stated or implied.
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The evaluations in this TER are applicable only to the components or i
groups of components identified by the submitted requests.
Further, the evaluations and recommendations are limited to the requirement (s) and/or function (s) explicitly discussed in the applicable TER section.
For example, i
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the results of an evaluation of a request involving testing of the containment i
isolation function of a valve cannot be extended to allow the test to satisfy a requirement to verify the valve's pressure isolation function, unless that
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extension is explicitly stated.
Vermont Yankee Nuclear Power Corporation provided several cold shutdown and refueling outage justifications for exercising Category A, B, and C valves during cold shutdowns and/or refueling outages instead of quarterly.
Valves identified to be tested during cold shutdowns need not be tested if testing was performed within three months of the cold shutdowns in accordance with q
OM-10, is 4.2.1.2(f) and 4.3.2.2(f).
These justifications were reviewed and appear to be acceptable except as noted in Appendix A.
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PUMP TESTING PROGRAM The following relief requests were evaluated against the requirements of l
ASME/ ANSI OMa-1988, Part 6, 10 CFR 50.55a, and applicable NRC positions and guidelines. A sutrnary is presented for each relief request followed by the licensee's basis for relief and the evaluation with the reviewer's recommendations.
The evaluations are grouped according to topic or system.
2.1 Service Water Pumos i
2.1.1 Establishino Reference Flow or Differential Pressure d
2.1.1.1 Relief Recuest P01.
P01 requests relief from establishing i
reference flow rate or differential pressure during testing as required by OM-6, 1 5.2, for the station service water (SSW) pumps, P7-1A through -1D.
The licensee proposes to perform a computerized curve fit test using differential pressure quarterly and to measure flow rate and determine differential pressure each refueling outage.
I 2.1.1.1.1 Licensee's Basis for Recuestino Relief--Relief is requested on the basis that compliance with the Code requirements is l
impractical and that the proposed alternatives would provide an acceptable i
level of quality and safety.
During normal operations, neither differential pressure nor flow rate can be fixed or directly measured.
Pump vibration levels may also vary due to the inability to establish a repeatable reference condition.
The four SSW pumps i
are vertical, two-stage, centrifugal-type pumps which are submerged in and take suction from the Connecticut River.
They supply all the SSW system j
requirements.
The SSW system is a dual header system usino two parallel I
headers each containing two pumps.
The two parallel headers supply both the turbine and reactor auxiliary equipment, including the residual heat removal service water (RHRSW) system.
A header interconnection is provided downstream of the pumps.
Normally, the valves in the interconnecting line are open, permitting any of the pumps to supply the cooling water to both headers and to balance system operation.
In addition, a cross-tie is provided to the station i
fire protection system (FPS).
The 12-inch cross-tie valve is normally closed, with a 1-inch cross-tie and a restricting orifice providing pressurization of the FPS header.
The SSW system contains both automatic temperature and flow control i
valves used to independently regulate the cooling provided to the various turbine-and reactor auxiliary equipment.
Due to seasonal variations in 1
Connecticut River water temperature and level and constantly changing heat i
loads, the system resistance and flow rate vary.
The number of SSW pumps in j
operation is also varied dependent on system requirements.
Due to these variations and the necd to maintain proper cooling, it is considered 4
j impracticable to establish repeatable reference values during quarterly IST.
1 Since the SSW pumps are submerged, and because inlet pressure direct measurement is not provided, it is considered impracticable to directly measure pump inlet pressure or pump differential pressure.
It is also considered impracticable to directly measure pump flow rate on a quarterly basis.
Sufficient straight sections of piping are required to properly j
measure flow rate, through the use of either permanently or temporarily 3
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installed instrumentation, such as non-intrusive flow measurement devices.
The only sufficient straight sections of piping in each of the two parallel headers exist between the intake structure and the entrance to the reactor building.
Use of this piping is censidered impracticable because:
a) These sections of the two parallel headers are buried piping.
b) As discussed above, each parallel header is common to two pumps and is cross-connected to the other header.
Thus, in order to measure flow rate for one pump, the parallel pump in the same header would have to be secured and the valves in the header interconnecting line closed.
This would result in single pump operation for the portion of the SSW system supplied by the pump being tested.
c) All four SSW pumps are required to be operating during power operations and cold shutdowns during approximately 7 months of the year to meet cooling load requirements.
Based on the above, significant recesign and modification of the SSW system would be required to facilitate repeatability or direct measurement of differential pressure and flow rate.
Such redesign and modification would be burdensome to Vermont Yarkee.
Alternate Testina:
Differential pressure will be determined on a quarterly basis as follows:
a) The inlet pressure for each pump will be calculated based on the intake structure water level relative to the pump suction inlet, and the temperature of the inlet water.
b) The calculated inlet pressure will then be used with the directly measured discharge pressure to calculate dif:n antial pressure.
This alternate method of differential pressure measurement will meet the applicable accuracy requirements of OM-6, Table 1, and will provide an acceptable level of quality and safety.
Flow rate will be directly measured each refueling outage utilizing a flow test loop provided in the FPS and temporarily installed instrumentation.
Multiple flow rate and differential pressure readings will be taken.
The test results will be evaluated against both the acceptance criteria of OH-6, Table 3, and the quantitative values provided in Table 4-2 of the third-interval IST program plan.
In addition, the test results will be used to generate a computerized head / capacity curve.
The instrumentation used for this testing will meet the applicable accuracy requirements of OH-6, Table 1.
On a quarterly basis, the flow rate will be determined based on the calculated differential pressure and the computerized head / capacity curve.
The results will be evaluated against the quantitative values provided in Table 4-2 of the third-interval IST program plan and analyzed for trends to the degree possible.
To provide additional data for pump performance evaluation and so provide added assurance of the operational readiness of the SSW pumps, the following actions will also be taken:
a) Full spectrum, rather than overail, vibrational monitoring will be conducted during each quarterly test and analyzed to the degree possible, b) SSW pump motor amperage will be monitored on a once per shift frequency when the pumps are in operation.
c) Results from quarterly inservice testing of the RHRSW pump flow tests, monthly emergency diesel generator surveillance service water flow measurements, and once per shift logs for cooling system heat loads will be monitored. d)
Routine preventive maintenance will be performed on each SSW pump to ensure that no adverse degradation is occurring.
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2.1.1.1.2 Evaluation--0M-6, j 5.2(b) requires that the system
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resistance be varied to establish a reference differential pressure or flow rate and that the other parameter be measured and compared to its reference value.
Evaluating flow rate and differential pressure against their reference values permits assessment of pump hydraulic condition and detection of degradation.
The licensee proposes to determine differential pressure quarterly and compare it and flow rate, which is obtained from comparing the j
calculated differential pressure to a computerized pump characteristic curve, to the values in Table 4-2 of the IST program.
Flow rate will be measured each refueling outage and this measured flow will be evaluated against the calculated dif ferential pressure and compared to the acceptance criteria of OM-6 and the values in Table 4-2 of the IST program.
As can be seen, the licensee's request involves three elements:
- 1) Differential pressure is not directly measured but is determined from t
discharge pressure and inlet pressure that is calculated from the level of water above the pump suction.
- 2) Quarterly test data is taken with the pumps in the as-found condition in lieu of establishing a reference flow rate or differential pressure.
- 3) Pump flow rate is not measured during quarterly testing and the quarterly test data is not evaluated against the Code acceptance criteria.
Regarding determination of differential pressure; the SSW pumps are submerged in and take suction from the Connecticut River.
It is impractical to directly measure the differential pressure of these pumps because there are no installed inlet pressure instruments.
The inlet pressure of these submerged pumps is due to the head of water above the level of the pump suction.
Determining the differential pressure using the measured discharge pressure and the calculated inlet pressure should provide data that is adequate to assess pump hydraulic condition and degradation. OH-6 does not require measurement of pump inlet pressure and allows differential pressure to be determined.
Therefore, the licensee's proposal to determine differential pressure is consistent with the requirements of OH-6 provided that the calculations yield an acceptable level of accuracy and repeatability.
Based on the determination that the licensee's proposal to calculate differential pressure is consistent with the requirements of OH-6, relief is not required and no action is necessary provided that the calculations yield an acceptable level of accuracy and repeatability.
Regarding establishing reference flow rate or differential pressure; the l
SSW pumps supply a system consisting of multiple heat exchangers.
Automatic temperature control valves independently modulate flow through each heat exchanger.
Due to seasonal variations in temperature of the river water and constantly changing heat loads, the pump configuration and system flow rate vary.
Establishing a reference test point could result in either under or i
over cooling of tne supplied components, which could cause equipment damage and premature failure.
Therefore, it is impractical to control this type of system to allow repeatability of reference values during power operation or outages when the heat loads constantly change and remain relatively high.
Where it is impractical to test at a reference value of flow rate or differential pressure, testing in the "as found" condition and comparing values to an established reference curve may be an acceptable alternative.
Pump curves represent an infinite set of reference points of flow rate and
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differential pressure.
Establishing a reference curve for a pump when it is known to be operating acceptably, and basing the acceptance criteria on this curve, can permit evaluation of pump condition and detection of degradation.
There is, however, a higher degree of uncertainty associated with using a curve to assess operational readiness.
Therefore, the development of the reference curve should be as accurate as possible.
Additionally, when using reference curves, it may be more difficult to identify instrument drift or to j
trend changes in component condition.
Establishing a reference test point for the SSW pumps is impractical during power operation and most cold shutdowns due to the impact on the SSW system and the cooled equipment.
Therefore, as-found testing using a reference curve may be the only practical alternative to the Code requirements.
This testing can be acceptable if the following elements are incorporated into the IST program and procedures for developing and implementing the curve (s):
Curves are developed, or manufacturer's pump curves are validated, when a.
the pumps are known to be operating acceptably.
b.
The reference points used to develop or validate the curves are measured using instruments at least as accurate as required by the Code.
c.
Curves are based on an adequate number of data points, with a minimum of
- five, d.
Points are beyond the " flat" portion (low flow rates) of the curve in a range which includes or is as close as practicable to design basis flow
- rates, e.
Acceptance criteria based on the curves does not conflict with Techr.ical Specification (TS) or Facility Safety Analysis Report operability criteria, for flow rate and differential pressure, for the affected pumps.
f.
If vibration levels vary significantly over the range of pump conditions, a method for assigning appropriate vibration acceptance criteria should be developed for regions of the pump curve.
g.
When the reference curve may have been affected by repair, replacement, or routine service, a new reference curve shall be determined or the previous curve revalidated by an inservice test.
Based on the determination that establishing the reference flow rate or differential pressure is impractical and burdensome during quarterly testing, and considering that measuring as-found conditions and using reference curves to evaluate these parameters can permit an adequate assessment of pump operational readiness, relief should be granted from this Code requirement pursuant to 9 50.55a 1 (f)(6)(i) with the following provision.
The licensee should follow the eight guidelines identified above for using reference curves, if practicable.
Where it is not practicable to follow these guidelines, the licensee should identify the specifics of their alternative and justify the deviations and show the adequacy of their proposed testing.
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Regarding not measuring flow rate during quarterly testing; it is impractical to measure pump flow rater because there are no installed pump header flow instruments or test loops.
The only installed flow rate i
instruments are in the branch lines to some of the supplied components, e.g.,
diesel generators.
It is impractical to install flow rate instruments or use portable instruments in the main pump headers because the only sections that 4
are sufficiently straight to provide accurate indication are buried and inaccessible.
Significant system redesign would be necessary to install flow instrumentation to test these pumps.
In addition, measuring individual ficw is impractical during power operation and cold shutdowns for much of the year because the heat loads and river temperature necessitate operation of all four SSW pumps.
Since measuring SSW pump flow rate during power operations and most cold shutdowns is impractical as discussed above, the only practical quarterly test is to determine differential pressure and measure vibration.
This testing has i
l limitations and may not provide meaningful indication of pump performance.
Comparing the differential pressure to the values in Table 4-2 of the licensee's IST program may not permit detection of pump hydraulic degradation or require corrective actions for pumps with significtnt degradation.
Regarding pumps that can be tested only in uninstrumented minimum flow recirculation lines quarterly, the NRC GL 89-04, Position 9, states in part:
l "In cases where flow can only be established through a non-instrumented i
minimum-flow path during quarterly pump testing and a path exists at cold i
shutdowns or refueling outages to perform a test of the pump under full or d
substantial flow conditions, the staff has determined that the increased
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interval is an acceptable alternative to the Code requirements provided that pump differential pressure, flow rate, and bearing vibration measurements are taken during this testing and that quarterly testing also measuring at least pump differential pressure and vibration is continued.
Data from both of these testing frequencies should be trended as required...."
The licensee's j
proposed testing appears to be the best practical testing for the SSW pumps i
given the current system design, and is similar to the GL position.
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proposed testing should allow an adequate assessment of pump operational readiness provided that the Code acceptance criteria is used for the quarterly testing if practicable.
However, if these pumps are subject to frequent failures and the degradation has not been detected by the quarterly testing, J
the licensee should develop a test method capable of detecting degradation j
that can be performed more frequently than the proposed refueling outage test, even if this involves system modifications.
Based on the determination that measuring pump flow rate during quarterly testing is impractical and burdensome, and considering the proposal to evaluate differential pressure and vibration quarterly and flow rate, i
differential pressure, and vibration during refueling outages should allow an adequate assessment of pump operational readiness, relief should be granted from the Code requirement pursuant to & 50.55a 1 (f)(6)(i) with the following provisions.
The Code acceptance criteria should be used to evaluate the quarterly test data if practicable.
Where it is not practicable to use the Code criteria, the licensee should identify the specifics of their alternatives and justify the deviations by showing the adequacy of the alternatives.
In addition, the licensee should perform a study of the 3
maintenance history of these pumps to determine if they are subject to frequent failures where the degradation has not been detected by the quarterly i
shutoff head testing.
If these pumps are subject to such failures, the J
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l licensee should develop a test method capable of detecting degradation that can be performed more frequently than the proposed pump flon test.
2.2.
Hich Pressure Coolant injection Pumos 2.2.1 Testina the Main and Booster Pumos as a Unit 2.2.1.1 Relief Reouest P02.
P02 requests relief from measuring individual hydraulic parameters as required by OH-6, j 5.2, for the high pressure coolant injection (HPCI) main and booster pumps, P44-1A and -18.
The licensee proposes to measure and evaluate the hydraulic parameters of these i
pumps as a pair and to inspect and repair both pumps if the pair does not meet
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the Code acceptance criteria.
Vibration measurements will be taken on each pump as required.
2.2.1.1.1 Licensee's Basis For Reouestino Relief--Relief is requested on the basis that the proposed alternatives would provide an acceptable level of quality and safety.
There is no means of measuring the differential pressure or the flow rate generated by each of these pumps individually. Installation of independent means of measurement for each pump is considered impracticable and would be burdensome to Vermont Yankee.
Alternate Testina: Differential pressure and flow rate parameters will be measured across both HPCI pumps as an integral unit.
Vibration monitoring will be performed for each pump individually.
Both pumps will be inspected and repaired as necessary if any abnormal conditions in differential pressure or flow rate occur.
2.2.1.1.2 Evaluation--0M-6, j 5.2(b) requires measurement of differential pressure and flow rate for each pump in the IST program.
Evaluating flow rate and differential pressure against their reference values permits assessment of pump hydraulic condition and detection of degradation.
The licensee proposes to measure and evaluate the hydraulic parameters of the HPCI main and booster pumps as a pair.
These pumps are driven by the same turbine.
The low pressure booster and high pressure main pumps act as a unit to provide high pressure makeup capability for the reactor coolant system (RCS). There are no provisions for measuring pressure at the discharge of the booster pump, which is the suction point for the main pump.
Therefore, the differential pressure developed by either pump cannot be measured or determined.
Also, the flow rate is the same i
through both of these series pumps.
System modifications would be necessary to permit individual hydraulic testing of these pumps, i
Testing the hydraulic performance of these series pumps as a unit should i
allow an adequate assessment of pump operational readiness.
Degradation in hydraulic performance of either pump would be seen as a change in the flow rate and/or differential pressure across the combination.
Therefore, the proposal is essentially equivalent to the Code and provides an acceptable level of quality and safety.
Based on the determination that the licensee's proposal is essentially equivalent to the Code and allows an adequate assessment of pump operational I
readiness, the alternative should be authorized pursuant to 5 50.55a 1 (a)(3)(1).
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5 2.2.2 Full-Scale Rance of Pressure Instrument 2.2.2.1 Relief Recuest p03.
P03 requests relief from the instrument full-scale range requirements of OM-6, i 4.6.1.2, for the HPCI main and booster pumps, P44-IA and -18.
The licensee proposes to measure differential pressure using the existing station inlet pressure instruments that have a full-scale range of 85 psig.
2.2.2.1.1 Licensee's Basis For Reouestino Relief--Relief is requested on the basis that the proposed alternatives would provide an acceptable level of quality and safety. Differential pressure across the HPCI i
pumps is determined by the difference between pressure measurements taken at a point in the inlet pipe and at a point in the discharge pipe as allowed by OH-6, j 4.6.2.2.
The installed HPCI pump inlet pressure indicators are designed to provide adequate inlet pressure indication during all expected operating and post accident conditions.
The full scale range, 85 psig, is sufficient for a post accident condition when the suppression chamber is at the maximum pressure. This, however, exceeds the full-scale range limit of three times the suction pressure reference value as required by OH-6, 1 4.6.1.2(a) (Value - approximately 26 psig, limit - 78 psig).
The suction pressure measurement is used to verify prescribed net positive suction head (NPSH) requirements and to determine pump differential i
pressure.
The installed gauges are calibrated to within 1.58% accuracy (FS),
thus the maximum variation in measured suction pressure due to inaccuracy would be 1.34 psi.
This is considered to be suitable for determining that adequate NPSH is available for HPCI pump operation.
Pump discharge pressure during testing is approximately 1170 psig, which results in a calculated differential pressure of approximately 1144 psig. The resulting inlet pressure inaccuracy of 1.34 psi represents an error in y
differential pressure measurement of 0.12% (1.34 psi /ll44 psid - 0.0012).
This is consistent with OM-6, Table 1, which requires that instrument accuracy for differential pressure be better than 2% of full-scale.
a Alternate Testina: Differential pressure will be measured using the existing station system installed inlet pressure indicators.
2.2.2.1.2 Evaluation--The Code requires measurement and analysis of pump differential pressure quarterly. These measurements are evaluated with flow rate measurements to assess pump hydraulic condition and detect degradation.
OM-6, T 4.6.1.2(a) states that the full-scale range of analog instruments shall not be greater than three times the reference value of the parameter.
This requirement is to ensure that the instrumentation used for testing is sufficiently readable and accurate. The licensee proposes to i
determine differential pressure using the existing station inlet pressure instrument that has a full-scale range of 85 psig where the reference value is approximately 26 psig (three times 26 psig is 78 psig).
OM-6 does not require measurement and evaluation of pump inlet pressure.
However, since there is no direct reading differential pressure instrument for the HPCI pumps, inlet pressure must be measured to determine the differential pressure developed across the pumps.
Therefore, the Code quality and range requirements apply to the HPCI inlet pressure instrument to assure that measurements are sufficiently accurate and readable to permit detection of 9
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pump degradation.
The installed inlet pressure instrument full-scale range is greater than three times the test reference value (85 psig in lieu of 178 psig).
The higher range is necessary to prevent instrument damage due to over-ranging during expected plant operating and post-accident conditions, therefore, installing an instrument that meets the range requirements may not be prudent. The accuracy of the installed instrument ( l.58%) is better than is required for pressure instruments in OH-6, Table 1 (12%).
The proposed inlet pressure instrument reading inaccuracy might be as great as 1.34 psi
( 5.17% of the reference value). However, the rated discharge pressure of these pumps is 1170 psig and the inlet pressure is so small in comparison that a slight inaccuracy in inlet pressure is meaningless (the 1.34 psi inaccuracy is only 0.12% of the 1144 psid reference differential pressure).
Use of the installed inlet pressure instrument would have no appreciable impact on the ability to evaluate the condition of these pumps.
Test instruments that meet the Code could have up to a 1.56 psi inaccuracy at the reference value, therefore, installing test instruments that comply with the Code for testing would be a hardship without a compensating increase in the level of quality and safety.
The proposed alternative provides sufficiently accurate data for assessing pump degradation.
Based on the determination that compliance with the Code full-scale range requirements for the HPCI pump inlet pressure instruments is a hardship i
without a compensating increase in the level of quality and safety, the alternative should be authorized pursuant to 5 50.55a 1 (a)(3)(ii).
2.2.3 Vibration Acceptance Criteria 2.2.3.1 Relief Recuest PO4.
PO4 requests relief from the vibration acceptance criteria of OM-6, Table 3, for the HPCI main or high pressure (HP) pump, P44-1A.
The licensee proposes to perform vibration spectrum monitoring quarterly and to extend the Alert Range absolute limit from 0.325 in/sec to 0.675 in/sec.
2.2.3.1.1 Licensee's Basis For Recuestino Relief--Relief is requested on the basis that the proposed alternatives would provide an acceptable level of quality and safety.
Past testing and analysis performed on the HPCI system by Vermont Yankee, the pump manufacturer, and by independent vibration consultants has revealed characteristic pump vibration levels which exceed the acceptance criteria stated in Table 3 of OM-6.
This testing and analysis meets the intent of 14.3 and footnote 1 of OM-6.
The root causes of the higher vibration levels have been determined to be an acoustical resonance in the piping connecting the low pressure (LP) and HP pumps, and the presence of a structural resonance in the horizontal direction on the HP pump.
These resonance conditions are design related and have existed since initial pump installation.
They have been documented aver a number of years of operating experience. An additional past contributor to the higher vibration levels was the excitation resulting from the blade pass frequency from the previously installed four vane impeller in the LP pump.
In an effort to reduce / eliminate this effect, the four vane impeller was replaced with a five vane impeller during the 1989 refueling outage.
This replacement significantly reduced vibration levels in both the LP and HP pumps. However, due to the resonance effects referenced above, the HP pump vibration levels remain higher than the acceptance criteria stated in Table 3 of DH-6.
10
a Although existing vibration levels in the HP pump are higher than standard acceptance criteria, they are acceptable and reflect the unique operating characteristics of the HPCI pump.
It has been concluded that there are no major vibrational concerns that would prevent the HPCI pump from performing its intended function.
Alternate Testina:
To allow for practicable vibration monitoring of the HPCI HP pump, alternate vibration acceptance criteria are required.
Full spectrum vibrational monitoring will be performed during each quarterly test and the following criteria will be used for the HP Pump:
Test Fa*5"ieter ActerteF e Fame A'ert Dance Gew ired Action 8eace V,,
i. 5V,
- 2. 5v, to and
> 6 v, 2
but ect inc hotng 6v, or
- 0.70 in/sec
> 0.675 'n/sec but not
- 0.70 in/sec In addition, the resonance peaks will be evaluated during each test and will have an Acceptable Range upper limit of 1.05 V, and an Alert Range upper limit of 1.3 V,.
2.2.3.1.2 Evaluation--The vibration acceptance criteria of DH-6, Table 3, are established so appropriate corrective actions are taken on pumps with significant mechanical degradation.
The absolute limits are set at levels that signify significant degradation for most pump installations, regardless of the reference vibration value.
The licensee proposes to perform vibration spectrum monitoring quarterly and to extend the Alert Range absolute limit from 0.325 in/sec to 0.675 in/sec.
This proposal was previously covered under Section XI, 1 IWP-3210, which states in-part: "If these ranges cannot be met, the Owner shall specify in the record of test (IWP-6000) the reduced range limits to allow the pump to j
fulfill its function, and those ranges shall be used in lieu of the ranges given in Table IWP-3100-2." However, OH-6 does not permit the owner to expand i
the Code allowable ranges without submitting and receiving approval in a relief request.
The licensee has performed extensive analysis of this pump installation and determined that the high vibration levels are due to effects of acoustical and structural resonance. These high levels do not indicate pump mechanical degradation and do not represent phenomena that could prevent the pump from performing its intended function.
The licensee's proposed vibration acceptance criteria together with their proposal to perform pump vibration spectrum analysis quarterly, with an Alert Range of 1.05 Y, and a Required Action Range of 1.3 V, for the resonance peaks, should result in corrective action being taken on a pump with significant degradation. A spectrum analysis measures a narrow vibration band width over a wide frequency range and indicates the frequency and magnitude of vibration peaks, which permits identification of problems with bearings and other pump mechanical components.
The spectrum analysis allows a more comprehensive evaluation of pump condition than the Code required wide range vibration measurements.
Therefore, the proposal should provide an acceptable level of quality and safety.
11
Based on the determination that the licensee's proposal should provide an acceptable level of quality and safety, the alternative should be authorized pursuant to 5 50.55a 1 (a)(3)(1).
2.3 Core Soray Pumos 2.3.1 Full-Scale Ranae of Pressure Instrument l
2.3.1.1 Relief Recuest P05.
P05 requests relief from the instrument full-scale range requirements of CH-6, i 4.6.1.2, for the core spray (CS) pumps, P46-1A and -18.
The licensee proposes to measure differential pressure using the existing station inlet pressure instruments that have a full-scale range of 60 psig.
2.3.1.1.1 Licensee's Basis For Recuestina Relief--Relief is requested on the basis that the proposed alternatives would provide an acceptable level of quality and safety.
Differential pressure across the CS pumps is determined by the difference between pressure measurements taken at a point in the inlet pipe and at a point in the discharge pipe as allowed by OH-6, i 4.6.2.2.
The installed CS pump inlet pressure indicators are designed to provide adequate inlet pressure indication during all expected operating and post accident conditions.
The full scale range, 60 psig, is sufficient for a post accident condition when the suppression chamber is at the maximum pressure.
This, however exceeds the full-scale range limit of three times s
the suction pressure reference value as required by OH-6, i 4.6.1.2(a)
(v::ue - approximately 7.5 psig, limit - 22 psig).
The suction pressure measurement is used to verify prescribed HPSH requirements and to determine pump differential pressure.
The installed gauges are calibrated to within 2.0% accuracy (full-scale), thus the maximum variation in measured suction pressure due to inaccuracy would be 1.2 psi.
This is considered to be suitable for determining that adequate NPSH is available for CS pump operation.
Pump discharge pressure during testing is approximately 240 p:,ig, which results in a calculated differential pressure of approximately 232.5 psig.
The resulting inlet pressure inaccuracy of 1.2 psi represents an error in differential pressure measurement of 1 5%
0 (1.2 psi /232.5 psid - 0.0052).
This is consistent with OM-6, Table 1, which requires that instrument accuracy for differential pressure be better than 2%
of full-scale.
Alternate Testino:
Differential pressure will be measured using the existing station system installed inlet pressure indicators.
I 2.3.1.1.2 Evaluation--The Code requires measurement and analysis of pump differential pressure quarterly.
These measurements are evaluated with flow rate measurements to assess pump hydraulic condition and detect degradation.
OM-6, j 4.6.1.2(a) states that the full-scale range of analog i
instruments shall not be greater than three times the reference value of the parameter.
This requirement is to ensure that the instrumentation used for testing is sufficiently readable and accurate. The licensee proposes to determine differential pressure using the existing station inlet pressure instrument that has a full-scale range of 60 psig where the reference value is i
approximately 7.5 psig (three times 7.5 psig is 22.5 psig).
I 12
OM-6 does not require measurement and evaluation of pump inlet pressure.
However, since there is no direct reading differential pressure instrument for the CS pumps, inlet pressure must be measured to determine the differential pressure developed across the pumps.
Therefore, the Code quality and range requirements apply to the CS inlet pressure instrument to assure that measurements are sufficiently accurate and readable to permit detection of pump degradation.
The installed inlet pressure instrument full-scale range is greater than three times the test reference value (60 psig in lieu of 122.5 psig). The higher range is necessary to prevent instrument damage due to over-ranging during expected plant operating and post-accident conditions, therefore, installing an instrument that meets the range requirements may not be prudent.
The accuracy of the installed instrument ( 2%). The proposed inlet pressure instrument reading inaccuracy might be as great as 11.2 psi
( 16% of the reference value).
However, the rated discharge pressure of these pumps is 240 psig and the inlet pressure is so saall in comparison that a inaccuracy in inlet pressure would not have a large impact on differential pressure accuracy (the 1.2 psi inaccuracy is only 0.52% of the 232.5 psid reference differential pressure). Use of the installed inlet pressure instrument would have no appreciable impact on the ability to evaluate the condition of these pumps.
Test instruments that meet the Code could have up to a 0.45 psi inaccuracy at the reference value, therefore, installing test instruments that comply with the Code for testing would be a hardship without a compensating increase in the level of quality and safety.
The proposed alternative provides sufficiently accurate data for assessing pump degradation.
Based on the determination that compliance with the Code full-scale range requirements for the CS pump inlet pressure instruments is a hardship without a compensating increase in the level of quality and safety, the alternative should be authorized pursuant to j 50.55a 1 (a)(3)(ii).
2.4 Reactor Core Isolation Coolino Putrp 2.4.1 Full-Scale Rance of Pressure Instrument 2.4.1.1 Relief Recuest P06.
P06 requests relief from the instrument full-scale range requirements of OH-6, j 4.6.1.2, for the reactor core isolation cooling (RCIC) pump, P47-1A. The licensee proposes to measure differential pressure using the existing station inlet pressure instruments that have a full-scale range of 85 psig.
2.4.1.1.1 Licensee's Basis For Reouestino Relief--Relief is requested en the basis that the proposed alternatives would provide an acceptable level of quality and safety.
Differential pressure across the RCIC pump is determined by the difference between pressure mensurements taken at a point in the inlet pipe and at a point in the discharge pipe as allowed by OH-6, 1 4.6.2.2.
The installed RCIC pump inlet pressure indicators are designed to provide adequate inlet pressure indication during all expected operating and post accident conditions.
The full scale range, 85 psig, is sufficient for a post accident condition when the suppression chamber is at the maximum pressure.
This, however, exceeds the full-scale range limit of three times the suction pressure reference value as required by OM-6, 1 4.6.1.2(a) (value - approximately 20 psig, limit - 60 psig).
13
l The suction pressure measurement is used to verify prescribed NPSH requirements and to determine pump differential pressure.
The installed gauges are calibrated to within 1.58% accuracy (full-scale), thus the maximum 4
variation in measured suction pressure due to inaccuracy would be 1.34 psi.
This is considered to be suitable for determining that adequate NPSH is i
available for RCIC pump operation.
Pump discharge pressure during testing is approximately 1130 psig, which results in a calculated differential pressure of approximately 1110 psig.
The resulting inlet pressure inaccuracy of 1.34 psi represents an error in differential pressure measurement of 0.12%
(1.34 psi /lllo psid - 0.0012). This is consistent with Table 1 of OM-6, which requires that instrument accuracy for differential pressure be better than 2%
of full-scale.
l Alternate Testina: Differential pressure will be measured using the existing station system installed inlet pressure indicators.
2.4.1.1.2 Evaluation--The Code reauires measurement and analysis of pump differential pressure quarterly.
Ther measurements are evaluated with flow rate measurements to assess pump hydraulic condition and detect degradation.
OH-6, j 4.6.1.2(a) states that the full-scale range of analog instruments shall not be greater than three times the reference value of the parameter.
This requirement is to ensure that the instrumentation used for i
testing is sufficiently readable and accurate.
The licensee proposes to determine differential pressure using the existing station inlet pressure instrument that has a full-scale range of 85 psig where the reference value is approximately 20 psig (three times 20 psig is 60 psig).
CM-6 does not require measurement and evaluation of pump inlet pressure.
However, since there is no direct reading differential pressure instrument for i
the RCIC pump, inlet pressure must be measured to determine the differential pressure developed across the pumps. Therefore, the Code quality and range requirements apply to the RCIC inlet pressure instrument to assure that i
measurements are sufficiently accurate and readable to permit detection of pump degradation.
The installed inlet pressure instrument full-scale range is greater than three times the test reference value (85 psig in lieu of 160 psig).
The higher range is n2cessary to prevent instrument damage due to over-ranging during expected plant operating and post-accident conditions, therefore, installing an instrument that meets the range requirements may not i
be prudent.
The accuracy of the installed instrument ( l.58%) is better than j
is required for pressure instruments in OM-6, Table 1 ( 2*.).
The proposed inlet pressure instrument reading inaccuracy might be as great as 1.34 psi d
(i6.7% of the reference value). However, the rated discharge pressure of this pump is.1130 psig and the inlet pressure is so small in comparison that a slight inaccuracy in inlet pressure is meaningless (the 1.34 psi inaccuracy is only 0.12% of the 1110 psid reference differential pressure).
Use of the installed inlet pressure instrument would have no appreciable impact on the i
ability to evaluate the condition of this pump.
Test instruments that meet the Code could have up to a 1.2 psi inaccuracy at the reference value, i
therefore, installing test instruments that comply with the Code for testing would be a hardship without a compensating increase in the level of quality and safety.
The proposed alternative provides sufficiently accurate data for assessing pump degradation.
i Based on the determination that compliance with the Code full-scale i
range requirements for the RCIC pump inlet pressure instruments is a hardship 14 i
without a compensating increase in the level of quality and safety, the alternative should be authorized pursuant to 6 50.55a 1 (a)(3)(ii).
2.5 Reactor Buildina Closed Coolino Water Pumo 2.5.1 Establish Reference Flow or Differential Pressure 2.5.1.1 Relief Reauest P07.
P07 requests relief from establishing reference flow rate or differential pressure during testing as required by OM-6, 1 5.2, for the reactor building closed cooling water (RBCCW) pumps, P59-1A and -18.
The licensee proposes to measure as-found pump vibration, 4
inlet pressure, differential pressure, and flow rate during quarterly testing i
and to measura all Code parameters at a reference condition once a year as climatic conditions permit.
2.5.1.1.1 Licensee's Basis for Recuestino Relief--Relief is requested on the basis that compliance with the Code requirements is impractical.
During normal operations, neither differential pressure nor flow rate can be fixed.
Pump vibration levels may also vary due to the inability to establish a repeatable reference condition.
The RBCCW system c.cnsists of a closed loop containing two 100 percent capacity pumps and two 100 percent capac;ty heat exchangers, which are cooled by the SSW system.
The RBCCW systein supplies cooling water to reactor auxiliary equipment.
The RBCCW system contains automatic temperature control valves used to independently regulate the cooling provided to the various reactor auxiliary equipmeat.
There is no flow test loop nor flow instrumentation installed.
Due to seasonal variations in the SSW system temperature and flow rate and constantly changing heat loads, the system resistance and flow rate vary.
Due to these variations and the need to maintain proper cooling, it is considered impracticable to establish repeatable reference values during quarterly IST. The installation of a flow test loop would require significant system redesign and modification, which would be burdensome to Vermont Yankee.
Alternate Testina:
Flow rate and differential pressure will be measured on a quarterly basis at the operating conditions present at the time of the test.
4 The measurements will be performed utilizing nonintrusive (ultrasonic) flow rate instrumentation and ir stalled pressure gauges.
Vibrational monitoring will also be conducted in conjunction with these tests. The test results will be analyzed for trends to the degree possible.
Once per year, when climatic conditions perinit a reference condition to be established, flow rate and differential pressure will be measured and vibrational monitoring conducted, with the test results evaluated against the acceptance criteria of OM-6, Table 3.
2.5.1.1.2 Evaluation--0M-6, 1 5.2(b) requires that the system resistance be varied to establish a reference differential pressure or flow rate and that the other parameter be measure and compared to its reference value.
Evaluating flow rate and differential pressure against their reference values permits assessment of pump hydraulic condition and detection of degradation.
The licensee proposes to measure as-found pump flow rate, differential pressure, and vibration during quarterly testing and to measure all Code parameters at a reference condition once a year as climatic conditions permit.
i 15 1
The RBCCW system has automatic temperature control valves for individual cooling loads.
These control valves modulate flow to control the temperature of the cooled components.
It is impractical to control this type of a system to allow repeatability of reference values because doing so could result in overcooling or undercooling supplied components, depending on the heat toad and ambient temperature.
Significant redesign and modification of the system would be required to provide this capability.
Performing the necessary modifications would be burdensome to the licensee.
Where it is impractical to test at a reference value of flow rate or differential pressure, pump testing at as-found conditions can be acceptable if performed in a manner that allows adequate monitoring of pump hydraulic and mechanical condition and detection cf degradation. The licensee's proposed quarterly testing does not appear to be capable of performing these functions.
The licensee has not identified a method of evaluating the measurements taken during quarterly tesling that permits an adequate assessment of pump condition to ensure that corrective actions are taken when appropriate.
Deferral of a meaningful pump test until once every year may be found to be acceptable, however, insufficient information is provided to support using this test frequency.
To determine the adequacy of a yearly test frequency, more information would be necessary about the pump failure rates, maintenance history, and types of degradation.
In addition, more detailed information would be necessary about the yearly test and its ability to detect pump degradation.
One means of evaluating pump condition when reference conditions cannot be established during pump testing, is to compare measured test parameters to reference pump curves.
However, this testing must be performed in a manner that permits adequate evaluation of pump operational readiness.
Pump curves represent an infinite set of reference points of flow rate and d'fferential pressure.
Establishing a reference curve for a pump when it is known to be operating acceptably, and basing the acceptance criteria on this curve, can permit evaluation of pump condition and detection of degradation. There is, I
however, a higher degree of uncertainty associated with using a curve to assess operational readiness. Therefore, the development of the reference curve should be as accurate as possible. Additionally, when using reference curves, it may be more difficult to identify instrument drift or to trend changes in component condition.
If a reference curve is used to test these pumps it should be established in accordance with the guidelines given in Section 2.1.1.1.2 of this report.
While not acceptable for the long term, measuring and trending pump flow rate, differential pressure, and vibration in the as-found condition quarterly and all Code required parameters during yearly testing, should allow an adequate assessment of pump operational readiness for one year or until the next refueling outage.
Based on the determination that establishing the reference flow rate or differential pressure is impractical and burdensome during quarterly testing, and considering that measuring as-found parameters quarterly and all required parameten s at reference conditions once each year can permit an adequate assessment of pump operational readiness during the interim period, interim relief should be granted from the Code requirement pursuant to i 50.55a j (f)(6)(i) for one year or until the end of the next refueling outage, 16 4
whichever is longer. At the end of this interim period, the licensee should implement a test method that adequately evaluates the condition of these pumps quarterly or they should have submitted for approval technical basis demonstrating the adequacy of the proposed yearly testing.
2.5.2 Full-Scale Rance of Pressure Instrument 2.5.2.1 Relief Recuest P08.
P08 requests relief from the instrument full-scale range requirements of OM-6, 1 4.6.1.2, for the RBCCW pumps, P59-1A and -18.
The licensee proposes to measure differential pressure using the existing station inlet pressure instruments that have a full-scale range of 30 psig.
2.5.2.1.1 Licensee's Basis For Reauestino Relief--Relief is requested on the basis that the proposed alternatives would provide an acceptable level of quality and safety.
Differential pressure across the RBCCW pumps is determined by the difference between pressure measurements taken at a point in the inlet pipe and at a point in the discharge pipe as allowed by OH-6, 1 4.6.2.2.
The installed RBCCW pump inlet pressure indicators, with a full-scale range of 30 psig, are designed to provide adequate inlet pressure indication during all expected operating and post accident conditions.
This, however, exceeds the full-scale range limit of three times the suction pressure reference value as required by OM-6, 1 4.6.1.2(a) (value - approximately 6.5 psig, limit - 19 psig).
The suction pressure measurement is used to verify prescribed NPSH requirements and to determine pump differential pressure.
The installed gauges are calibrated to within 10.4% accuracy (full-scaie), thus the maximum variation in measured suction pressure due to inaccuracy would be 0.12 psi.
This is considered to be suitable for determining that adequate NPSH is available for RBCCW pump operation.
Pump discharge pressure during testing is approximately 80 psig, which results in a calculated differential pressure of approximately 73.5 psig.
The resulting inlet pressure inaccuracy of 0.12 psi represents an error in differential pressure measurement of 0.16%
(0.12 psi /73.5 psid - 0.0016).
This is consistent with OH-6, Table 1, which requires that instrument accuracy for differential pressure be better than 2%
of full-scale.
Alternate Testino:
Differential pressure will be measured using the existing station system installed inlet pressure indicators.
2.5.2.1.2 Evaluation--The Code requires measurement and analysis of pump. differential pressure quarterly.
These measurements are evaluated with flow rate measurements to assess pump hydraulic condition and detect degradation.
OH-6,14.6.1.2(a) states that the full-scale range of analog instruments shall not be greater than three times the reference value of the parameter.
This requirement is to ensure that the instrumentation used for testing is sufficiently readable and accurate. The licensee proposes to determine differential pressure using the existing station inlet pressure instrument that has a full-scale range of 30 psig where the reference value is approximately 6.5 psig (three times 6.5 psig is 19.5 psig).
0H-6 does not require measurement and evaluation of pump inlet pressure.
However, since there is no direct reading differential pressure instrument for the RBCCW pumps, inlet pressure must be measured to determine the differential 17
pressure developed across the pumps.
Therefore, the Code quality and range requirements apply to the RBCCW inlet pressure instrument to assure that measurements are sufficiently accurate and eadable to permit detection of pump degradation.
The installed inlet pressure instrument full-scale range is greater than three times the test reference value (30 psig in lieu of 519.5 psig). The higher range is necessary to prevent instrument damage due to over-ranging during expected plant operating and post-accident conditions, therefore, installing an instrument that meets the rangs requirements may not be prudent.
The accuracy of the installed instrument ( 0.4%) is better than is required for pressure instruments in OH-6, Table 1 (12%).
The proposed inlet pressure instrument reading inaccuracy might be as great as 20.12 psi
( l.85% of the reference value).
However, the rated discharge pressure of.
these pumps is 80 psig and the inlet pressure is so small in comparison that a slight inaccuracy in inlet pressure is meaningless (the 0.12 psi inaccuracy is only 2 16% of the 73.5 psid reference differential pressure).
Use of the 0
installed inlet pressure instrument would have no appreciable impact on the ability to evaluate the condition of these pumps.
Test instruments that meet the Code could have up to a 1 39 psi inaccuracy at the reference value, 0
therafore, installing test instruments that comply with the Code for testing would be a hardship without a compensating increase in the level of quality 4
and safety. The proposed alternative provides sufficiently accurate data for assessing pump degradation.
i Based on the determination that compliance with the Code full-scale range requirements for the RBCCW pumps inlet pressure instruments is a hardship without a compensating increase in the level of quality and safety, the alternative should be authorized pursuant to 50.55a 1 (a)(3)(ii).
2.6 Diesel Fuel Oil Trrnsfer Pumps 2.6.1 Flow Rate Measurement 2.6.1.1 Relief Reouest P09.
P09 requests relief from the flow rate measurement requirements of GM-6, j 5.2, for the diesel fuel oil transfer pumps, P92-1A and -18.
The licensee proposes to observe that each pump provides flow greater than is used by the operating emergency diesel generator (EDG), measure pump discharge pressure, and perform full spectrum vibration analysis quarterly.
In addition, once every operating cycle the licensee will determine flow rate by measuring the change in day tank level over time, measure pump discharge pressure, and perform full spectrum vibration analysis.
2.6.1.1.1 Licensee's Basis for Reouestino Relief--Relief is requested on the basis that compliance with the Code requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety and that the proposed alternatives would provide an acceptable level of quality and safety.
During quarterly inservice testing, pump flow rate cannot be directly measured.
The EDG fuel oil supply system consists of two parallel trains, one for each diesel.
Fuel oil is supplied directly to the diesel fuel block from the 800-gallon day tank.
Makeup to each diesel day tank is accomplished automatically from the 75,000 gallon storage tank by operation of the diesel fuel oil transfer pumps.
The diesel day tank is sized for three hours of continuous full load operation, based on a diesel fuel oil consumption rate of 18
approximately 3.4 gpm.
The diesel fuel oil transfer pumps are posit ve displacement pumps with a design capacity of approximately 8.7 gpm.
i It is considered impracticable to directly measure pump flow rate on a quarterly basis.
There is no flow rate instrumentation installed in the fuel oil transfer system.
Sufficient straight sections of piping are required to properly measure flow rate, through the use of either permanently or temporarily installed instrumentation, such as non-intrusive flow measurement devices.
The only sufficient straight sections of piping exist in the buried sections of the supply headers.
Installation of flow rate instrumentation or a pump test loop would require significant system redesign and modification, which would be burdensome to Vermont Yankee.
Diesel fuel oil transfer pump flow rate can be determined indirectly by measuring the level change in the diesel day tank versus the pump operating time required to make that change. However, in order to allow for evaluation of the test results against the acceptance criteria of OM-6, Table 3, the test must be performed with the respective EDG secured.
This eliminates the unknown variability of the diesel fuel oil consumption rate.
In addition, in arcer to provide measurement accuracy comparable with OH-6, Table 1, the automatic pump start feature on low diesel day tank level must be disabled and the diesel day tank volume reduced prior to the test through operation of the respective EDG.
Disabling the automatic start feature of the diesel fuel oil transfer pump on low diesel day tank level lessens the ability of the EDG to i
operate automatically without operator assistance, reduces the availability of an engineered safety system, and requires entry into a Vermont Yankee TS Limiting Condition of Operation, with the required alternate testing requirements.
\\
Alternate Testina:
During quarterly inservice testing of each diesel fuel oil transfer pump, it will be verified that the pump is capable of supplying fuel oil to the respective diesel day tank at a flow rate greater than that required by the operating EDG.
This is verified by an increase in diesel day tank level during the EDG surveillance testing.
In addition, full spectrum vibrational monitoring and measurement of pump discharge pressure will be performed with the results evaluated against the acceptance criteria of OM-6, Table 3.
Once each operating cycle the flow i ate of each diesel fuel oil transfer pump will be determined indirectly by measuring the level change in the diesel day tank versus the pump operating time required to make that change.
This will be performed with the respective EDG secured, the automatic pump start feature-on low diesel day tank level disabled, and the diesel day tank volume reduced prior to the test through operation of the respective EDG.
This testing will provide measurement accuracy comparable with OH-6, Table 1, and the results will be evaluated against the acceptance criteria of OM-6, Table 3.
As with the quarterly testing, full spectrum vibrational monitoring and measurement of pump discharge pressure will be performed with the results evaluated against the acceptance criteria of OH-6, Table 3.
Such testing is considered commensurate with the pump type and service and prevides an acceptable level of quality and safety, based on the following:
1 a)
A review of the pump design flow rate versus the diesel fuel oil l
consumption rate indicates an excess capacity of approximately 60 percent.
As such, operational readiness of the pumps is still assured 19
j i
j i
l I
l with up to 60 percent degradation, provided that pump bearing vibration 1
is not excessive.
Assurance of acceptable pump bearing vibration levels is provided through the full spectrum vibrational monitoring.
i b)
A review of Vermont Yankee maintenance records and industry experience, as documented in NPRDS, indicates that the pumps are highly reliable and 3
i that the above testing methods are acceptable for assessing pump operational readiness and determining potential degradation. At Vermont
]
Yankee, four failures have occurred in twenty years of plant operations.
Of these failures, three were related to electrical components and one j
was related to high bearing vibrations.
In addition, minor shaft seal leakage has been noted and corrected.
The industry experience is i
i consistent with Vermont Yankee.
For similar pumps in similar applications, fifteen failures have been reported via NPRDS. Of these failures, nine were related to excessive seal leakage, four were related to electrical components and two were related to high bearing i
vibrations.
Each of the above failure modes is adequately monitored during the i
quarterly inservice testing through visual inspection of the pump seals, proper starting and operation of the pump upon low diesel day tank j
level, and full spectrum vibrational monitoring.
2.6.1.1.2 Evaluation--0M-6, is 5.1 and 5.2, require the quarterly measurement of pump test quantities to detect hydraulic and mechanical degradation and to evaluate pump operational readiness.
The licensee proposes to observe that each pump provides flow greater than is used by the operating EDG, measure pump discharge pressure, and perform full spectrum vibration analysis quarterly.
In addition, once every operating cycle the licensee will determine flow rate by measuring the change in day tank level over time, measure pump discharge pressure, and perform full spectrum vibration analysis.
The parameters required to be measured for these constant speed positive displacement pumps are flow rate, discharge pressure, and vibration.
There are no installed instruments in the diesel fuel oil transfer system that allow direct measurement of pump flow rate.
The current system configuration does not have any accessible straight sections of piping that are sufficiently long to permit installation of flow instrumentation or use of portable flow instruments that meet the Code requirements.
The only piping sections that would be adequate are buried and inaccessible. Major system modifications would be required to install flow instruments that meet the Code requirements.
Pump flow rate can be calculated by measuring the change in day tank volume and the pump operating time required to make that change.
This method yields a value for pump flow rate that can be used to evaluate pump hydraulic condition.
If flow rate is calculated with sufficient accuracy to allow detection of pump degradation, installation of flow rate instrumentation would be burdensome because it would provide only a minimal improvement in the abHity to monitor pump condition. Accurately determining flow rate is impractical during quarterly testing because it would be necessary to make these measurements with the diesel stopped, the day tank low level automatic start feature disabled, and the day tank below the minimum level.
Establishing these conditions quarterly for pump testing reduces the availability of an engineered safety system and requires entry into a TS LC0 Action Statement with prescribed alternate testing requirements.
20
l The discharge pressure of the positive displacement fuel oil transfer 1
pumps is dependant on the pressure of the system into which they are pumping and is not significantly affected by either inlet pressure (providing adequate NPSH exists) or flow rate.
The discharge pressure for these pumps is I
relatively small since they pump directly into the day tanks which are vented to the atmosphere.
Changes in flow resistance should not significantly affect i
the flow rate of these positive displacement pumps unless the rated discharge pressure is exceeded.
Therefore, the primary parameter for evaluating the hydraulic condition of these pumps is the pump flow rate.
Flow rate is subjectively determined for the quarterly testing but is not measured in a way that allows detection of pump degradation.
The licensee indicated that these pumps have an excess capacity of 60 percent.
However, it has not been demonstrated that these pumps would have an acceptable level of operational readiness (assurance that they would be capable of performing their safety function during an accident) if they a
suffered degradation that reduced the flow rate by 10 to 60 percent.
Therefore, the proposed quarterly testing is limited in its ability to detect hydraulic degradation and provide assurance of pump operational readiness.
The proposed vibration spectrum analysis is much better than the Code required wide range measurement and provides significant information about pump condition.
This testing could detect most of the mechanical degradation mechanisms that may affect these pumps.
3 The proposed quarterly testing verifies pump operation but provides i
little information to permit detection of pump hydraulic degradation.
However, the testing performed once every cycle should permit detection of hydraulic degradation provided the flow rate determination is sufficiently 4
j accurate.
The licensee indicated that the accuracy of the flow rate determination would be comparable to the OH-6 accuracy requirements.
i Therefore, it is assumcd that the flow rate determination is as accurate as i
data that could be obtained from instruments meeting the Code requirements.
If the determination is less accurate, the adequacy of the less accurate information should be justified in the IST program. The proposed hydraulic testing, coupled with the quarterly vibration full spectrum analysis, should allow an adequate assessment of pump operational readiness.
Based on the determination that compliance with the Code requirements is impractical and burdensome, and considering the adequacy of the licensee's proposed testing, relief should be granted from the Code requirements pursuant
]
to 9 50.55a 1 (f)(6)(1).
i 1
21
3.
VALVE TESTING PROGRAM The following relief requests were evaluated against the requirements of ASME/ ANSI OHa-1988 Part 10,10 CFR 50.55a, and applicable NRC positions and guidelines. A sumary and the licensee's basis for each relief request is presented followed by an evaluation and reviewer's recommendation.
Relief requests are grouped according to system and Code Category.
3.1 Residual Heat Removal Service Water System 3.1.1 Qieacry B Valves 3.1.1.1 Relief Recuest V10.
V10 requests relief from the exercising and stroke time measurement requirements of OH-10, is 4.2.1.3 and 4.2.1.4(b),
for the RHRSW flow control valves, V10-89A and -89B.
The licensee proposes to observe that the valves open to pass 2700 gpm and properly regulate flow through the heat exchangers during cyarterly testing.
3.1.1.1.1 Licensee's Basis For Reouestino Relief--Relief is requested on the basis that compliance with the Code requirements is impractical.
These valves have no position indication or manual control switches. These valves are controlled by the respective RHR service water pump start circuitry and the flow control position modulator. This makes obtaining accurate stroke times for these valves very difficult.
Alternate Testino:
Adequate assessment of the operational readiness of these valves will be performed during normal quarterly testing by ensuring that the maximum design basis flow of 2700 gpm is achieved and properly regulated through the respective RHR heat exchanger.
3.1.1.1.2 Evaluation--j 4.2.1.3 requires that the necessary valve obturator movement be determined by exercising the valve while observing an appropriate indicator.
Exercising verifies that valves are capable of stroking through their required travel without binding.
This testing is to provide assurance that valves will be capable of performing their required safety function (s).
The RHRSW flow control valves do not have manual control switches or position indication to facilitate full-stroke exercising. The licensee proposes to verify the maximum design basis flow of 2700 gpm through these valves quarterly and to observe proper flow regulation.
It is unclear if these valves are exercised closed or verified in that position during quarterly testing.
If the valves are not exercised closed, it would be possible for the flow controller to move them to a position that is not experienced during routine testing.
If a valve is placed in a position where it is seldom moved, there is a possibility that it could bind and fail to open when required to perform its safety function.
Therefore, the licensee should ensure th:st these valves are exercised through the entire range of travel to which they may be subjected during any plant operating mode where the RHRSW system is required to be in operation.
1 4.2.1.4(b) requires measurement of the full-stroke times of power-operated valves to monitor for changes that could be indicative of valve deg adation.
This allows retesting of degraded valves and corrective action to repair seriously degraded valves prior to their reaching the point where they are incapable of performing their function.
The licensee proposes to verify valve operational readiness by observing that flow is properly 22
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l 1
i 1
regulated through the heat exchangers, however, full-stroke times are not I
i measured. Observing the valves regulating flow is a very subjective test that
]
provides little information about valve condition or degradation.
The RHRSW flow control valves do not have position indicators or manual control switches.
They are controlled by the respective pump start circuitry and flow controller.
Using conventional means, it is impractical to measure j
the stroke times of these valves because there is no way to determine when a i
valve gets an actuation signal or reaches the open or closed position.
These valves may be indirectly verified open by observing flowmeter indication, but accurate stroke timing using conventional techniques is impractical.
System modifications, such as replacing these valves with valves that have position indication and installing manual switches, would be necessary to directly measure their stroke times.
Making these modifications would be burdensome to i
the licensee.
t a
l It is not acceptable for the long term to not have an objective means to i
monitor valve condition and detect degradation.
The licensee's proposal j
should provide an acceptable level of quality and safety during an interim i
period of one year or until the end of the next refueling outage, whichever is longer.
However, the licensee should develop a means to obtain meaningful l
stroke times or to otherwise monitor for degrading conditions of these valves.
j This testing should be performed quarterly if practicable, however, if l
quarterly testing is impractical the alternate frequency should be justified i
in the IST program.
This testing might involve non-intrusive diagnostic
}
techniques such as acoustics, magnetics, ultrasonics, thermography, or radiography.
If it is determined that it is impractical to use testing methods effectively, an enhanced maintenance program may be acceptable.
Based on the determination that complying with the Code requirements is impractical and burdensome and considering the licensee's proposed alternate i
testing, interim relief should be granted pursuant to @ 50.5Sa 1 (f)(6)(i) for
(
one year or until the end of the next refueling outage, whichever is longer.
At the end of the interim period the licensee should implement a method of stroke timing these valves, an alternate method of monitoring for valve
)
degradation, or an enhanced maintenance program.
4
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3.2 Service Water System i
l 3.2.1 CateoorY B Valves 3.2.1.1 Relief Reouest V01.
V01 requests relief from the stroke time s
measurement requirements of OM-10, 1 4.2.1.4(b), for the RHRSW pump cooling l
coil supply isolation valves, SE-70-4A, -48, -4C, and -40.
The licensee proposes to verify valve operational readiness by observing that proper i
cooling water flow is established upon RHRSW pump start.
I 3.2.1.1.1 Licensee's Basis For Recuestino Relief--Relief is requested on the basis that the proposed alternatives would provide an j
acceptable level of quality and safety.
These valves are 3/4 inch solenoid operated gate valves.
The valves are rapid acting valves with no local or 4
J remote position indication. The valves have no manual control switches, but instead are controlled by the respective RHRSW pump start circuitry. This j
makes obtaining accurate stroke times for these valves very difficult.
System 23 e - - ---
-ar
~.
-r
l l
i l
l l
modifications necessary to directly measure the stroke times of these valves j
would be burdensome to Vermont Yankee.
Due to the valve size and configuration, normal stroke time is almost instantaneous.
When these types of valves do not operate properly, they most commonly fail to operate at all or stick in some intermediate position.
In either case, improper valve operation will be identified by a noticeable decrease in the required flow rate to the RHRSW pump motor cooler, thus, trending these valves by measuring the time to rated flow will not provide any significant increase in quality or safety of this system.
Alternate Testino: Adequate assessment of the operational readiness of these i
valves will be performed by visual confirmation that the proper cooling water flow rate is established upon pump start.
Cooling water flow will be read locally from flow indicators FI-104-70A through D.
3.2.1.1.2 Evaluation--1 4.2.1.4(b) requires measurement of the full-stroke times of power-operated valves to monitor for changes that could i
be indicative of valve degradation. This allows retesting of degraded valves and corrective action to repair or replace seriously degraded valves prior to their reaching the point where they are incapable of performing their function.
The licensee proposes to determine valve condition by observing that proper cooling water flow is established upon RHRSW pump start, however, stroke times are not measured. Observing that these valves open to allow flow is a subjective test that provides little information about valve condition or degradation.
The RHRSW pump cooling coil isolation valves are rapid acting solenoid I
valves that do not have position indicators or manual control switches. They are controlled by the respective RHRSW pump start circuitry.
Using conventional mears, it is impractical to measure the stroke times of these valves because there is no way to determine when a valve gets an actuation signal or reaches the open position.
These valves may be verified open by observing flowmeter indication, but accurate stroke timing using flow indication is impractical. System modifications, such as replacing these valves with valves that have position indication and installing manual switches, would be necessary to directly measure valve stroke times. Making these modifications would burdensome to the licentee.
It is not acceptable for the long term to not have an objective means to monitor valve condition and detect degradation. The licensee's proposal should provide an acceptable level of quality and safety during an interim period of one year or until the end of the next refueling outage, whichever is longer.
However, the licensee should develop a means to obtain meaningful stroke times or to otherwise monitor for degrading conditions of these valves.
This testing should be performed quarterly if practicable, however, if quarterly testing is impractical the alternate frequency should be justified in the IST program.
This testing might involve non-intrusive diagnostic techniques such as acoustics, magnetics, ultrasonics, thermography, or radiography (one licensee recently had good success with a test method that combined acoustics with a gaussmeter to accurately stroke time solenoid valves).
If it is determined that it is impractical to use testing methods effectively, an enhanced maintenance program or periodic replacement may be acceptable.
24 l
i Based on the determination that complying with the Code requirements is impractical and burdensome and considering the licensee's proposed alternate testing, interim relief should be granted pursuant to @ 50.55a 1 (f)(6)(1) for one year or until the end of the next refueling outage, whichever is longer.
At the end of the interim period the licensee should implement a method of stroke timing these valves or they should propose an alternate method of monitoring for valve degradation, an enhanced maintenance. ogram, or a periodic replacement program.
3.2.2 Cateoory C Valves 3.2.2.1 Relief Recuest V02.
V02 requests relief from the test frequency requirements of OM-10, 1 4.3.2.1, for the SW pump discharge check valves, V70-1A, -18, -1C, and -lD.
The licensee proposes to exercise these valves quarterly during service water tests, during cold shutdowns, and during refueling outages if operation with three SW pumps is permissible.
3.2.2.1.1 Licensee's Basis For Reouestino Relief--Relief is reluested on the basis that compliance with the Code requirements is impactical. A review of Vermont Yankee's operating, shutdown and refueling history indicates that operation of all four service water pumps is required l
during power operations and at cold shutdowns during approximately 7 months of i
the year to meet operating and shutdown cooling heat load requirements.
Because of ultimate heat sink temperatures and required service water loads, operating three service water pumps during these periods does not provide adequate cooling capacity.
Alternate Testino:
Check valve exercising will be performed during the regularly scheduled quarterly service water tests, and during each cold shutdown and refueling outage, only if operation with three service water pumps is permissible based on the ultimate heat sink temperature and required cooling loads.
The minimum frequency of such testing will be twice per year with a minimum interval between tests of three months.
3.2.2.1.2 Evaluation--The Code requires a full-stroke exercise of safety-related check valves quarterly if practical and provides a hierarchy for part and full-stroke exercising quarterly, at cold shutdowns, or during refueling outages if quarterly full-stroke exercising is impractical.
This testing is to demonstrate that a valve is capable of moving to its safety function position (s) to assess its operational readiness. The licensee proposes to exercise these valves closed quarterly, at cold shutdowns, or during refueling outages if operation with three service water pumps is permissible based on the ultimate heat sink temperature and required cooling loads.
It is impractical to stop one of the four SW pumps each quarter during power operation and during cold shutdowns because the temperature of the Connecticut River and the SW system cooling loads are such that stopping one of the pumps could result in insufficient cooling and possible damage of some of the cooled equipment.
The licensee stated that a review of the plant history indicates that all four SW pumps must be operated during approxfmately d
seven months of the year.
Redesign of the system would be necessary to permit stopping a SW pump during each calendar quarter.
Requiring the licensee to make these modifications would be burdensome. The licensee's proposal appears to conform to the requirements of 1 4.3.2.1, since these valves are full-25
r
>l 4
0 1
stroke exercised closed quarterly when practical, during cold shutdowns when practical, and during refueling outages.
l l
Since the licensee's proposal complies with OH-10, relief is not required.
However, since the SW system historically has a high rate of check i
valve failures due to corrosion, fouling, etc., an extended test interval may not be prudent for these valves.
The licensee should closely monitor the failure rate and problems with these valves, and if the proposed testing does not adequately detect valve condition, they should consider performing enhanced valve surveillance and/or maintenance to ensure an adequate level of operational readiness.
3.3 Hioh Pressure Coolant Injection System 3.3.1 Cateoory B Valve 3.3.1.1 Relief Recuest V06. V06 requests relief from the stroke time acceptance criteria requirements of OM-10, 1 4.2.1.8(b), for the HPCI turbine steam inlet control valve.
The licensee proposes to expand the acceptance criteria for the stroke time measurements to 35% in the open direction and 50% in the closed direction.
The licensee will also measure the time it takes the HPCI system to achieve rated flow once each operating cycle.
)
3.3.1.1.1 Licensee's Basis For Recuestino Relief--Relief is requested on the basis that compliance with the Code requirements is i
impractical and that the proposed alternatives would provide an acceptable level of quality and safety.
The motive force for the HPCI turbine stop and 4
^
control valves is supplied from the turbine force feed lubrication system. A l
review of historical data indicates that variations in valve stroke times exist between tests run with a primed versus an unprimed hydraulic system.
Similar effects have been seen at other plants, as described in General Electric SIL No. 336, Revision 1.
To minimize the amount of variability induced by the degree of hydraulic system priming, the turbine stop and control valves are timed from onset of valve movement as shown by receipt of intermediate position indication to full open indication during valve surveillance testing.
This timing method minimizes the affects that the time required for hydraulic priming would otherwise have on.the valve's stroke time. Although the hydraulic priming affect is reduced, the historical data still indicates average variations in valve stroke times as follows:
HPCI-CONTROL Open 29%
Close 43%
HPCI-STOP Open 13%
Close N/A - Rapid Acting The average variations for the HPCI control valve are greater than the Code acceptance criteria of 125% of the reference value.
Alternate Testino:
The acceptance criteria for the HPCI turbine control valve will be expanded to 35% in the open direction and 50% in the closed direction.
In addition, a time-to-rated flow test for the HPCI system will be performed once each operating cycle to demonstrate satisfactory integrated response of the control, hydraulic, and mechanical components.
26
i I
1 3.3.1.1.2 Evaluation--i 4.2.1.4(b) requires measurement of the full-stroke times of power-operated valves to monitor for changes that could be 1
indicative of valve degradation.
The acceptance criteria of 1 4.2.1.8 are set t
j to require retesting of degraded valves and corrective action to repair or replace seriously degraded valves prior to their reaching the point where they l
are incapable of performing their function.
The licensee proposes to expand i
the acceptance criteria for the stroke time measurements to 35% in the open
{
]
direction and 250% in the closed direction.
The licensee will also measure the 1
time it takes the HPCI system to achieve rated flow once each operating cycle.
{~
As stated above, the Code acceptance criteria are established to require i
corrective actions when there is sufficient valve degradation to be of concern.
It is not the intent of the Code to take corrective actions or declare a valve I
incperable because of normal data scatter when the valve is operating l
acceptably.
Therefore, when the test data for a valve that is operating j
acceptably frequently exceeds the Code acceptance ;riteria, it may be appropriate to relax the acceptance criteria to preclude unnecessary corrective i
actions. However, excessive data scatter coupled with relaxed acceptance j
criteria can compromise the ability of the test to detect valve degradation and j
indicate the need for corrective action when the degradation becomes excessive.
frequently, high data scatter is the result of a poor test procedure that fails i
a to adequately control the variables that can affect test data.
When this is l
the case, the test procedure should be improved if possible instead of relaxing the Code acceptance criteria.
?
i I
f The licensee indicated that the HPCI control valve test has been analyzed and it was determined that the variable with the greatest effect on stroke j
tires is the degree of hydraulic system priming.
The test has been modified to minnize the effects of this variable, however, test data still exceeds the q
Code acceptance criteria.
Since action has been taken to improve the test quality and the proposed acceptance criteria is set a reasonable level above 1
the historical average stroke times, the proposal should provide an acceptable level of quality and safety. Ccmpliance with the Code would require declaring the HPCI system inoperable and performing corrective actions on a non-degraded 1
valve, which would be an unusual hardship on the licensee.
Declaring a non-
]
degraded valve inoperable and performing needless corrective actions would reduce the availability of the HPCI system and increase the likelihood of valve 1
failure due to the wear and tear of the excessive maintenance activities.
l Therefore, compliance with the Code acceptance criteria would not provide a i
compensating increase in the level of quality and safety.
Based on the determination that complying with the Code requirements is a hardship without a compensating increase in the level of quality and safety, i
the alternative should be authorized pursuant to 9 50.55a 1 (a)(3)(ii).
If l
this valve fails in the future and the degradation is not detected because of f
excessive data scatter and the relaxed acceptance criteria, the licensee should j
take action to refine the test to improve their ability to detect valve degradation.
4 3.4.Q_qnjrol Rod Drive Hydraulic Sv$ tem l
3.4.1 Cateoorv A/C Valves 3.4.1.1 Relief Reouest V07.
V07 requests relief from the test frequency j
requirements of OM-10, 1 4.3.2.1, for control rod drive (CRD) scram discharge 1
27
I 1
}
volume vent line check valves, V3-162A and -162B.
The licensee proposes to exercise these valves open following each reactor scram and to verify their closure each refueling outage during leak rate testing.
i 3.4.1.1.1 Licensee's Basis For Recuestino Relief--Relief is requested on the basis that the proposed alternatives would provide an acceptable level of quality and safety.
These valves cannot be exercised i
during power operation since this would require taking the CRD system out of service.
Full-stroke exercising of these valves cannot be directly verified.
Operability of these valves is demonstrated by a decreasing scram discharge volume water level upon a reset from a scram.
l The:e valves can only be backflow tested via a leak type test which'would require removing the CRD system from service.
Testing during Cold Shutdowns is impractical due to the significant system and test equipment configurations required.
I Alternate Testino:
These valves will be demonstrated to function properly in the open direction by observing a decreasing scram discharge volume water level upon a reset from each scram. These valves will be backflow exercised each j
refueling outage during leakage rate testing.
(
3.4.1.1.2 Evaluation--The Code requires a full-stroke exercise of j
safety-related check valves quarterly if practical and provides a hierarchy for part and full-stroke exercising quarterly, at cold shutdowns, or during refueling outages if quarterly full-stroke exercising is impractical.
This i
testing is to demonstrate that a valve is capable of moving to its safety function position (s) to assess its operational readiness. The licensee proposes to exercise these valves open following each reactor scram and to l
verify their closure each refueling outage during leak rate testing.
V3-162A and -162B are simple check valves in the vent lines to the scram discharge volumes (V3-162A for the north header and V3-162B for the south j
header).
These valves do not have position indication, therefore, the only practicable conventional. method of verifying that the valves are open is to j
observe a decrease in scram discharge volume level following a scram.
It is impractical to scram the reactor quarterly during power operations to perform i
this testing.
The only practicable conventional method of verifying valve j
closure is leak testing.
It is impractical to leak test these valves quarterly i
during power operations because the CRD system would be removed from operation j
to perform this testing. Taking the CRD system out of service during power operations would result in a reactor shutdown and would be burdensome to the licensee.
It is impractical to leak test these valves during cold shutdowns l
because establishing the required test conditions, setting up the test I
equipment, performing the leak rate test, removing the test equipment, and restoring the system to operation could cause a delay in returning the plant to l
power.
The flow rate through these valves cannot be directly measured because there are no installed flow instruments and portable instruments can not be used to measure air ficw. These valves must open sufficiently to vent the scram discharge volume to allow drainage of water following a scram so there will be an adequate expansion volume for subsequent scrams. The maximum accident flow rate is achieved if the scram discharge volume drains promptly after the scram is reset. The proposed open position test verifies that this 28
e condition is met.
Since it is impractical to exercise these valves open quarterly and to verify closure quarterly or during cold shutdowns, the proposal to verify that they open following each reactor scram and verify closure by leak testing each refueling outage closely conforms to the test frequency requirements of 1 4.3.2.1.
Based on the determination that complying with the Code requirements is impractical and burdensome and considering the licensee's proposed alternate tcsting, relief should be granted pursuant to 5 50.55a 1 (f)(6)(i) as requested.
3.5 Standby Liouid Control System 3.5.1 CateoorY C Valvel 3.5.1.1 Relief Recuest V08.
V08 requests relief from the acceptance criteria requirements of OM-1, 1 1.3.4.1(e)(2), for the standby liquid control (SLC) pump discharge relief valves, SR-11-39A and -39B.
The licensee proposes to test these valves in accordance with the requirements of plant TS.
3.5.1.1.1 Licensee's Basis For Recuestino Relief--Relief is requested on the basis that the proposed alternatives would provide an acceptable level of quality and safety.
Vermont Yankee TS 4.4.A requires testing of valves SR-ll-39A and -398 at least once every operating cycle.
This testing frequency represents a six-fold increase over the testing frequency required by Part 1 (GM-1) of the Code and, as such, yields more accurate valve degradation trending data.
The testing is currently performed at the Vermont Yankee plant site.
The acceptable range of relief valve actuation given in TS 4.4.A is 1400 psig to 1490 psig. The 1400 psig value ensures that a sufficient injection pressure can be established prior to lifting of the relief valve.
The 1490 psig value ensures relief valve actuation prior to reaching the system design pressure of 1500 psig.
1490 psig translates into a maximum relief valve setpoint of 99% of system design pressure as opposed to 110% allowable by the piping code. Applying the OM-1 tolerance of 3% to the cerrent setpoint would unnecessarily reduce the acceptable range to 1400 psig to 1442 psig (1442 psig
- 96% of system design pressure).
The increased testing frequency and present setpoint requirements provide adequate assurance of the operational readiness of valves SR-11-39A and -398 and, as such, no significant increase in the level of safety or quality can be expected if the subject Code requirements are imposed.
Alternate Testino:
In accordance with Vermont Yankee TS 4.4.A, valves SR-ll-39A and -39B shall be tested at least once every operating cycle.
The setting of the valves shall be between 1400 and 1490 psig.
3.5.1.1.2 Evaluation--The set pressure acceptance criteria of OM-1 requires corrective actions on relief valves if their set pressures exceed the stamped set pressure criteria by 3% or greater. This requirement is to ensure that relief valves having excessive set pressure drift be repaired or replaced to provide assurance that they will be able to perform their safety function.
This requirement is based on general relief valve applications in nuclear power plants and may be excessively restrictive for certain relief valve 29
e
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applications.
The licensee proposes to use the acceptance criteria specified by plant TS, 1400 psig to 1490 psig.
i It is not the intent of the Code to take corrective actions or declare a valve inoperable when the valve is operating acceptably.
The plant TS provide
)
a test frequency and acceptance criteria for these valves that are adequate for them to perform their safety function of protecting the SLC system from overpressure while still allowing the system to develop sufficient pressure to inject into the RCS during an accident.
The plant TS have been rcviewed and approved by the NRC staff.
Therefore, when these valves are tested once every operating cycle and the set pressures are within TS limits, these valves are operating acceptably and it is appropriate to relax the Code acceptance 4
criteria to preclude unnecessary corrective actions.
The licensee's proposal to test these valves in accordance with plant TS should provide an acceptable level of quality and safety. Compliance with the Code could unnecessarily require declaring the SLC system inoperable and performing corrective actions on a non-degraded valve, which would be an l
l unusual hardship on the licensee.
Declaring a non-degraded valve inoperable i
j and performing needless corrective actions would reduce the availability of the SLC system and increase the likelihood of valve failure due to the wear and tear of the repair activities.
Therefore, compliance with the Code acceptance 4
criteria would not provide a compensating increase in the level of quality and safety.
Based on the determination that complying with the Code requirements is a j
hardship without a compensating increase in the level of quality and safety, the alternative should be authorized pursuant to @ 50.55a 1 (a)(3)(ii).
l 3.6 Residual Heat Removal System 3.6.1 Cateaory A Valves
)
3.6.1.1 Relief Reouest V09.
V09 requests relief from the leak rate 1
testing requirements of OM-10, 1 4.2.2.1, for the residual heat removal (RHR)
]
shutdown cooling suction and discharge header outboard containment isolation valves, V10-17, -27A, and -278.
The licensee proposes to verify valve leak j
tight closure capabilities by observing downstream pressure indication during i
power operation.
I 3.6.1.1.1 Licensee's Basis for Recuestino Relief--Relief is requested on the basis that the proposed alternatives would provide an i
acceptable level of quality and safety.
In response to the " Technical i
Evaluation Report, Primary Coolant System Pressure Isolation Valves", dated July 21, 1980, and Generic NRC Letter 87-06 (GL 87-06), dated March 13, 1987, i
Vermont Yankee provided a listing of pressure isolation valves (PIVs) by letter dated June 11, 1987.
The NRC stated that the integrity of such valves is
]
adequately assured either by continuous or periodic monitoring of downstream pressure, or by the performance of leak testing (Generic NRC Letter, dated l
February 23, 1980).
Full differential pressure is not imposed on valve V10-17 during normal operations due to the presence of valve V10-18.
Neither valve V10-17 nor valve l^
V10-18 can be opened with reactor pressure greater than 100 psig due to the presence of an interlock.
The continuous monitoring provided by PS-10-Il8 30 l
l
demonstrates the functionally adequate seat leak-tightness for the interface i
between the high pressure RCS and the attached low pressure system.
Full differential pressure is not imposed on valves V10-27A and -27B 4
during normal operations due to the presence of valves V10-46A and -46B.
Monitoring of the downstream pressure for valves V10-46A and -46B is performed utilizing PI-10-100A and -1008. Continuous monitoring of the downstream pressure for valves V10-27A and -27B is provided by PS-10-122A and -1228.
This monitoring demonstrates adequate seat leak-tightness for the interface between the high pressure RCS and the attached low pressure system, thus individual leakage testing of these valves for pressure isolation concerns is not necessary and would not increase the quality or the safety of this system.
Alternate Testina:
None.
3.6.1.1-2 Evaluation--i 4.2.2 establishes the leak rate requirements for valves whose leakage is limited to a specific maximum amount in fulfillment of their function.
These valves are categorized "A" in the IST program and RR-V09 states that they are containment isolation valves (CIVs) and that they provide both a primary containment and pressure isolation function in 4
the closed position.
The Vermont Yankee Nuclear Power Corporation response i
dated June 11, 1987, to GL 87-06. identified these valves as PIVs, however, they are not required by plant TS to be individually leak rate tested as PIVs.
The licensee proposes to verify the leak tight integrity of these valves in pairs with the associated upstream (closer to the RCS) isolation valves by monitoring downstream (see figure 1) pressure instruments in lieu of individually leak rate testing them.
h 1
I T.b" v
v u.c n
u v
Yia-M
" Y15-e7 A
A M
6-7 6-7,
~ N a* - -
-wm m re-am l
Figure I Motor operated valve (MOV) V10-17 is the outboard isolation valve on the shutdown cooling supply line.
MOV V10-18 is the inboard isolation valve on this line.
The licensee's response to GL 87-06 indicated that valves V10-17 and -18 are exempted from leak testing per TS 4.7.2.
Since there are two closed valves in series in this line, observation of a downstream pressure instrument does not provide assurance that each series valve is leak-tight.
31
p 4
j The proposed test method can only show that one of the two valves is leak tight j
or that both leak.
If valve V10-18 is leak tight, there would be no pressure on valve V10-17.
Therefore, V10-17 could leak excessively or fail to close and i
this condit " would not be indicated by monitoring the pressure instrument.
H0Vs V10-27A and -27B are the downstream isolation valves on the low pressure coolant injection lines to the recirculation loops (see figure 2).
l 4
Check valves V10-46A and -46B are the inboard isolation valves in these lines.
'ihe response to GL 87-06 indicates that valves V10-46A and -46B are individually verified closed monthly by observing pressure gauges (PI-100A and PI-1008) installed on the drain lines located between the check valves and the i
downstream isolation valves. However, if these upstream isolation valves are leak tight, observation of a pressure instrument downstream of V10-27A and -27B i
does not provide assurance that these valves are leak-tight.
Therefore, these valves could leak excessively or fail to close and this condition would not be 1
J indicated by monitoring the pressure instrument.
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Prom the II
'5*mhW iP R
uma
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PI Oh Vic-N ir i
Y10- N Y
A u
narruu.
vro4s p
(
ir L,
n To the NU To the spr7h ads enant Figure 2 i
14.2.2.1 states that valves which function in the course of plant operation in a manner that demonstrates ft.nctionally adequate seat leak-tightness need not be additionally leak tested. However, because of the series 1
i configuration, observing the downstream pressure indication does not demonstrate adequate seat leak-tightness of the subject valves. Therefore, the provision of T 4.2.2.1 does not apply.
The system P&ID shows that there are test connections on both the upstream and downstress sides of the subject valves.
These connections are located outside of containment and should make 1
it feasible to individually leak rate test valves V10-17, -18, -27A, and -278 i
to verify their leak tight function.
Immediate conformance with the Code to verify the leak tight integrity of these valves individually is impractical because the necessary test provisions i
and test procedures are not in place.
Requiring immediate implementation could i
result in an extension of the upcoming refueling outage which would be an unusual burden to the licensee. The proposed testing would provide continuous indication that each series valve pair is leak tight.
This testing is in d
32 i
accordance with the licensee's response to GL 87-06.
While this testing does not individually test these valves in accordance with 1 4.2.2 of the Code, it should provide adequate assurance of valve operational readiness for an interim period of one year or until the next refueling outage, whichever is longer.
Based on the determination that immediate compliance with the Code requirements is impractical and burdensome and considering the licensee's proposed alternate testing, interim relief should be granted pursuant to
% 50.55a 1 (f)(6)(i) for one year or until the end of the next refueling outage, whichever is longer. At the end of the interim period the licensee should implement a method to leak rate test valves V10-17, -27A, and -278 in accordance with 1 4.2.2.3 of the Code.
3.7 Reactor Cori Isolation Coolino 1 3.7.1 Catenory B Valves 3.7.1.1 Relief Recuest Vll.
Vll requests relief from the stroke time measurement requirements of OM-10, 1 4.2.1.4(b), for the RCIC turbine governor control valve.
The licensee proposes to verify valve operational readiness by observing proper system response during RCIC pump tests.
3.7.1.1.1 Licensee's Basis For Recuestino Relief--Relief is requested on the basis that compliance with the Code requirements is impractical and that the proposed alternative would provide an acceptable level of quality and safety. This is a modulating type governor valve, and has no manual control switch for testing purposes.
This valve is controlled by the RCIC turbine control circuitry, thus making accurate stroke time for this valve very difficult to obtain.
The system modifications necessary to directly measure the stroke time for this valve would be burdensome to Vermont Yankee.
Stroke time is not an appropriate reference parameter for this valve.
r Alternate Testino:
Proper valve operation will be verified through normal system operation during RCIC pump tests.
Valve degradatien will be identified by inadequate system response during pump testing.
3.7.1.1.2 Evaluation--i 4.2.1.4(b) requires measurement of the full-stroke times of pcwer-operated valves to monitor for changes that could be indicative of valve degradation.
This results in retesting degraded valves and corrective action to repair seriously degraded valves prior to their reaching the point where they are incapable of performing their function.
The licensee proposas to verify operational readiness of this hydraulically operated turbine governor control valve by observing adequate valve response to system demand inputs during quarterly testing.
The RCIC turbine governor control valve responds to variations in steam supply pressure and pump discharge pressure to maintain the pump flow rate at the appropriate value.
This is a skid mounted valve that was not designed to be individually tested.
Since this valve actuates in response to system parameters and does not have a manual control switch, it is impractical to stroke it through its full travel.
Since the valve cannot be practically full-stroked and the position to which it would move (as-found position) could vary from test to test, exercising it from the as-found position could result in variations in measured stroke times that are independent of valve condition.
Therefore, measuring and evaluating stroke times for this valve would not 33
=
provide information that could be practically used to monitor its condition or detect degradation.
System modifications would be required to permit measurement of repeatable and meaningful stroke times.
Performing these modifications would be burdensome to the licensee.
Observing adequate valve response to system demand inputs during RCIC operability testing provides an indication that this valve is functioning, but it does not provide a quantitative means of monitoring for valve degradation.
The proposed test is subjective and may allow a degraded valve to remain in service.
The licensee should perform a study to determine if a more objective test is practicable.
If a better test is determined to be practicable, the licensee should implement this testing within one year or by the next refueling outage, whichever is longer.
The results of the licensee's study should be documented in a subsequent IST program submittal.
It may be impractical to perform quantitative testing on this valve.
Although the proposed testing does not provide objective indication of valve condition, this testing in conjunction with TS required operability testing and routine maintenance activities may provide adequate assurance of valve operational readiness. Observing the response of this valve while controlling RCIC pump flow rate during quarterly testing, together with verification of 1
proper response during low steam pressure testing once each operating cycle, demonstrate that this valve is capable of moving to all positions required for it to perform its safety-related functions.
Based on the determination that complying with the Code requirements is impractical and burdensome and considering the licensee's proposed alternate testing, relief should be granted pursuant to & 50.55a 1 (f)(6)(i).
3.8 Diesel Generator Air Start System i
3.8.1 Cateaory B Valves 3.8.1.1 Relief Recuest V03.
V03 requests relief from the stroke time measurement requirements of GM-10, j 4.2.1.4(b), for the EDG starting air inlet and vent valves, AS-24-1A, -1B, -2A, -2B, AV-24-1A, and -1B.
The licensee i
proposes to assess valve operational readiness by measuring diesel generator start times during quarterly EDG testing using both air start trains.
In addition, the EDG start times using one air start train will be measured once per operating cycle.
3.8.1.1.1 Licensee's Basis For Recuestina Relief--Relief is requested on the basis that compliance with the Code requirements is i
impractical and that the proposed alternatives would provide an acceptable level of quality and safety.
These valves do not have remote position indication. Heasuring the stroke time of these valves by observing stem travel would require disassembly of the operator.
Testing of the inlet valves individually would require the lifting of the power leads to the other valve.
Since the stroke timing of these valves is performed by the indirect indication of the respective EDG start time, to lift j
leads each quarter and perform the necessary EDG starts to verify each valve's stroke time would be an undue hardship.
Because excessive diesel starts are a known contributor to decreased diesel reliability and owing to the criticality of the diesels as part of the ECCS system, the overall impact of testing these 34 1
v valves in accordance with Code requirements would be an overall decrease in plant safety.
Furthermore, since the air start system is not totally redundant (e.g. they share common piping, components and initiating logic), testing of these valves individually on a quarterly basis would not increase the quality and safety of the system.
A11gynate Testina:
During quarterly testing, indirect measurement that at least one of the two parallel air start inlet valves opens promptly, and the vent valve closes promptly, will be performed by ensuring the EDG starts within the TS limit of 13 seconds.
Measuring the EDG start time gives indication of possible valve degradation (as a pair) since any significant changes in valve stroke time will be identified by longer than normal EDG start times.
In addition, to further assess the operational readiness of each air start inlet valve, an independent operability test is performed once per operating cycle.
This test will be accomplished by alternately lifting the power leads to one of the two air start valves, and then measuring the diesel start time with the remaining valve in operation.
3.8.1.1.2 Evaluation-- 4.2.1.4(b) requires measurement of the full-stroke times of power-operated valves to monitor for changes that could be indicative of valve degradation.
This results in retesting degraded valves and corrective action to repair seriously degraded valves prior to their reaching the point where they are incapable of performing their function.
The licensee proposes to verify operational readiness of these valves by measuring diesel generator start times during quarterly EDG testing using both air start trains.
1 In addition, the EDG start times using one air start train will be measured once per operating cycle.
These valves operate from an engine start control signal rather than a control switch and do not have remote position indication or any external means to determine valve position.
Therefore, it is impractical to stroke time these valves as required by the Code.
System modifications would be necessary to directly measure the stroke times of these valves.
Performing these modifications would be burdensome to the licensee.
During the quarterly test using both air start valves, a diesel start within 13 seconds of the start signal indicates rapid opening of at least one of these valves.
It is impractical to alternately lift the leads of the air start valves to individually test them quarterly, because this would reduce EDG availability and the additional testing could damage the EDGs.
The licensee's proposal to perform individual start tests each operating cycle should provide adequate assurance of valve operational readiness.
Based on the determination that compliance with the Code requirements is impractical and burdensome, and considering the proposed alternate testing.
relief should be granted from the Code requirements pursuant to 5 50.55a 1 (f)(6)(i).
3.9 Diesel Fuel Oil Transfer System 3.9.1 Cateaory C Valve 3.9.1.1 Relief Recuest V04.
V04 requests relief from the exercising frequency requirements of the Code, 1 4.3.2.1, for the check valve in the fill line for the diesel fuel oil storage tank, V78-2.
The licensee proposes to 35
disassemble and inspect or test this valve by other positive means once each year.
3.9.1.1.1 Licensee's Basis for Recuestina Relief--Relief is requested on the basis that compliance with the Code requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety and that the proposed alternative would provide an acceptable level of quality and safety.
The 75,000 gallon fuel oil storage tank supplies the EDGs.
The tank is partially below grade for missile 1
protection.
The protected portion of the tank provides a minimum of 5 days fuel oil supply to an EDG operating at the continuous rating of 2750 kW.
Valve V78-2 is normally closed and is only open during manual filling of the tank.
Should a failure of valve V78-2 occur coincident with the loss of the non-safety related fill line piping, operation of the EDGs would still be possible due to the design of the fuel oil storage tank as described above.
There is no means to manually exercise the valve and no test taps are available to backflow test the valve.
System modifications necessary to exercise this valve would be burdensome to Vermont Yankee.
In addition, the valve is a simple swing check valve located in an oil system.
This combined with the infrequent use of the valve, approximately once per month, provides assurance that the likelihood of failure or degradation is low.
Alternate Testino: Operability of valve V78-2 will be assessed on an annual basis by disassembly and inspection or other positive means. Corrective action shall be in accordance with OM-10, 1 4.3.2.6.
3.9.1.1.2 Evaluation--The Code requires a full-stroke exercise of safety-related check valves quarterly if practical and provides a hierarchy for 4
part and full-stroke exercising quarterly, at cold shutdowns, or during refueling outages if quarterly full-stroke exercising is impractical.
This testing is to demonstrate that a valve is capable of moving to its safety function position (s) to assess its operational readiness.
The licensee proposes to disassemble and inspect or test this valve by other positive means once each year.
V78-2 is a simple check valve in the fill line for the diesel fuel oil storage tank.
This valve does not have position indication, therefore, the only practicable conventional method of verifying valve closure is leak testing.
It is impractical to leak test this valve at any frequency because the fill line does not have any test connections or provisions to perform this testing.
Since it is impractical to verify closure of this valve quarterly or during cold shutdowns, the licensee's proposal to test it yearly corresponds to and may be more conservative than the Code required refueling frequency. The proposed test methods are both permitted by the Code.
1 4.3.2.4(a) permits verification of obturator movement by other positive means and i 4.3.2.4(c) permits disassembly.
Therefore, the proposed test frequency and methods conform to the requirements of OM-10.
Since the licensee's proposal complies with DM-10, relief is not required related to the check valve exercising method and frequency.
36
3.10 Nuclear Boiler System 3.10.1 Cateoory B/C Valves 3.10.1.1 Relief Recuest V05.
V05 requests relief from the relief valve testing requirements of OM-1, is 1.3.3.l(c)(1) and 1.3.3.l(e)(1), for the main steam safety valves and dual function (ADS) relief valves, SV-2-70A, -708, RV-2-71A, -71B, -71C, and -710.
The licensee proposes to bench-check or replace 2 valves from the group consisting of RV-2-71A through -710 and one valve from the group of SV-2-70A and -70B every refueling outage. The proposal would also permit power generation to resume prior to obtaining test as-found data and the sample size will not be expanded based on test failures.
3.10.1.1.1 Licensee's Basis for Recuestino Relief--Relief is requested on the basis that compliance with the Code requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality or safety and that the proposed alternatives would provide an acceptable level of quality and safety. The addressed requirements pose a j
significant hardship for several reasons:
1.
Vermont Yankee does not have the facilities required to perform setpoint tests on large relief and safety valves.
These valves are unbolted from their mounting flanges, decontaminated, packaged, and shipped to an off-site test facility. The typical time period required to remove, package, transport, and test these valves is from four to eight weeks.
This exceeds Vermont Yankee's typical outage duration. As such, outages would need to be extended several weeks to allow for receipt of test results and would result in several million dollars in lost revenue.
Dedication of company resources is better assigned to plant activities that have a more significant impact on safety.
2.
The subject valves are in a contaminated area with the following radiological conditions: Dose rate 15 - 400 mr/hr and contamination level 2
10-70K dpm/100cm.
This results in a typical dose of 2-5 manREM per valve for removal and reinstallation.
Removal of additional valves would subject plant personnel to significant radiation doses which are better avoided or used on tasks with greater safety significance.
3.
Because these valves must be sent off-site for testing, the removal, decontamination, packaging, and testing of additional valves due to sample expansion would delay unit start-up from refueling outages by at least an additional 8-10 weeks following testing of the initial sample. This again would result in several additional million dollars in lost revenue.
Dedication of company resources is better assigned to plant activities that have a more significant impact on safety.
Testing these valves during the outage and performing sample expansion is not expected to result in a increase in safety or quality for the following reasons:
1.
Vermont Yankee is already testing these valves more frequently than is required by OH-1.
In accordance with TS Basts 4.6.D and FSAR Section 4.4.8, during each refueling outage, 2 of the 4 relief valves, RV-2-71A through -710, and I of the 2 safety valves: SV-2-70A and -708, are removed 37
for testing and replaced with previously tested spares.
This accelerated test and maintenance schedule significantly exceeds the requirements of DM-1.
In a five year period, a minimum of 9 valves are tested.
This represents a sample population of 150% of the Code required population, i.e., 50% more than is required. More frequent testing is not expected to result in an increase in safety or quality and could have a detrimental affect on the valves due to the wear and tear associated with remova',
decontamination, shipping, and reinstallation.
2.
TS Basis 4.6.0 states: " Experience in safety valve operation shows that a testing of 50% of the safety valves per refueling outage is adequate to detect failures or deterioration." Because the NRC has reviewed and approved the Vermont Yankee T5 and FSAR, this prior approval has already acknowledged the testing of one half of the subject valves without further sample expansion.
Any test failures are assessed via the Licensee Event Report Systen (10 CFR 50.73), which requires a detailed root cause determination and corrective action. Thus, proper review of failures and appropriate corrective action is assured though this system, which includes NRC participation.
3.
Because Vermont Yankee is performing 50% more testing than is required by the Code, the station is effectively conducting sample expansion now, even when no failures occur.
4 The primary purpose of testing the remaining population prior to the resumption of electric power generation is to verify that a generic concern with either the valve design, application, or maintenance and testing practices does not exist.
A review of the root cause analyses performed for the Vermont Yankee specific valve failures indicates that none of the failures had generic implications.
This is furthar supported by the extensive operational history of the relief and safety valve designs used at Vermont Yankee and the maturity of the maintenance and testing practices in place.
As such, the cost and burden of performing testing during the refueling outage in order to ascertain the need for additional testing is not warranted by the historical data.
5.
A review of Vermont Yankee test data since 1984 indicates only a single failure when based on the acceptance criteria of OH-1.
That represents a success rate of 93.75%.
Furthermore, in the case of the valve that failed, the other valve of the same make and model tested at 0.8% above the set point.
Lastly, a statistical analysis of the set point test results since 1984 shows a set point test result mean of only 0.29% above the required setpoint.
5.
A review of NPRDS data revealed only ten industry-wide fcilures related to this make and model exceeding its set point or not opening.
Furthermore, the overall trend points to a reduction in valve failures as demonstrated by the NPRDS failure distribution given below:
1985 - 5 Failures 1989 - 1 Failure l
1986 - 1 Failure 1990 - 0 Failures 1987 - 1 Failure 1991 - 1 Failure 1988 - 1 Failure i
38 n
i I
Considering the large population of valves in use in the industry, this demonstrates that the valves are very reliable.
As such, sample expansion i
4 is not likely to result in a significant increase in the likelihood of identifying a failed valve and will therefore have no beneficial impact on safety or quality.
l All of this data taken together demonstrates that these components have a high degree of reliability.
It also demonstrates that no significant increase j
in safety can be expected if the subject Code requirements are imposed.
Alternate Testina: A minimum of 1/2 of all safety valves, SV-2-70A and -70B, shall be bench-checked or replaced with a bench-checked valve each refueling outage.
Both valves shall be checked or replaced every two refueling outages.
4 l
The lif t point of the safety valves shall be as specified in TS 2.2.8.
A minimum of 1/2 of all relief valves, RV-2-71A through -71D, shall be i
bench-checked or replaced with a bench-checked valve each refueling outage.
l All four valves shall be checked or replaced every two refueling outages.
The i
lift point of the relief valves shall be as specified in TS 2.2.B.
The analysis and reporting of any failures ur and any resultant corrective action will be performed in accordance wi.
Licensee Event Report System, 10 CFR 50.73.
3.10.1.1.2 Evaluation--0M-1 requires safety and relief valves to be tested at a frequency such that each valve is tested once every five years with a minimum of 20% of the valves of each type and manufacture being tested within any 24 months.
The Code test frequency for these valves would be approximately 1 valve from each group each refueling outage, with all valves being tested at least once every five years.
The licensee proposes to bench-check or replace 2 valves from the group consisting of RV-2-71A through -71D and one valve from the group of SV-2-70A and -708 every refueling outage, which is greater than the number required to be tested by the Code during a refueling outage.
The licensee's proposal to bench-check 1/2 of these valves or replace them with refurbished valves each refueling outage should provide reasonable assurance of their operat'onal readiness.
The licensee does not have on-site provisions to setpoint test these large safety relief valves.
It is impractical to test them with system pressure because it would require plant temperatures and pressures well above the operating ranges and would result in the release of reactor coolant to the suppression pool.
Therefore, these valves are removed and sent to an off-site test facility for testing.
The Code requires test completion and knowledge of any test failure information prior to resumption of electric power generation.
This permits determination of the necessity to test additional valves in the sample group during the same outage. However, due to the length of time required for valve removal, decontamination, shipping to the test facility, and bench-checking to determine the as-found data, the information may not be available until after the reactor is ready to resume operations.
This requirement may result in an extension of the outage, which would be extremely burdensome to the licensee; however, the licensee may be able to accomplish this effort in a more efficient manner, or to develop another means of performing the test.
The licensee is testing or replacing more of these valves than required by the Code.
This partially offsets the need for an increased test sample 39
I s
should a failure occur.
However, the licensee's proposal would require no further testing even if all of the tested valves failed to function properly.
Failure of a valve to pass a test could indicate a problem with the valve design, manufacturer, maintenance procedure, testing procedure, or operating environment.
These failures could have a common mode or be generic to the i
valve type and application, therefore, the Code requires expansion of the sample size when a tested valve fails the test.
Because of the possibility of comon mode failures, the licensee's proposal to not perform additional testing based on test failures is not conservative and may not be warranted for safety relief valves.
However, the licensee provided information that demonstrated i
that since 1984, these valves have passed more than 93% of the as-found tests.
1 In addition, the root cause analyses of the failures of these valves over the l
20 years of plant operation indicates that none of the failures had generic i
implications.
Further, the licensee presented industry data from the NPRDS i
that indicates that the safety relief valves of the particular type and 1'
manufacturer used at Vermont Yankee, have not experienced a high rate of i
]
failures over the period from 1985 through 1991.
2 i
Because of the history of low failure rates and the lack of comon mode failures for these valves at Vermont Yankee and other nuclear facilities, the l
proposal to test more valves than required by the Code each refueling outage i
but not to expand the sample size upon finding a failed valve, should provide a reasonable level of quality and safety for an interim period. However, there is always the possibility of comon mode failures.
Therefore, for the upcoming i
refueling outage, if one of these valves fails a test, the licensee should expeditiously perform the required root cause analysis to determine if there i
could be a comon mode or generic failure concern.
If it is determined that l
the cause of the test failure is generic or comon with the other group valves, the remaining valves should be imediately tested, even if this requires a plant shutdown.
There have been recent developments that may permit insitu or on-site testing of these valves.
Implementation of one of these techniques may make it i
possible to comply with this Code rewirement without extending the refueling outage.
4 1
Based on the determination that compliance with the Code is impractical and burdensome, and considering the licensee's proposed alternate testing, i
3 relief should be granted from the Code requirement pursuant to 6 50.55a 1 (f)(6)(i) for an interim period until the refueling outage following the August 1993 refueling outage. During the August 1993 refueling outage, if one of these valves fails a test, the licensee should expeditiously perform the j
required root cause analysis to determine if there could be a comon mode or generic failure concern.
If it is determined that the cause of the test failure is generic or comon with the other group valves, the remaining valves 5
should be imediately tested, even if this requires a plant shutdown.
In the interim, the licensee should assess the testing requirements for these valves.
The assessment may include TS changes and Code inquiries.
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APPENDIX A l
IST PROGPJW ANOMALIES l
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APPENDIX A IST PROGRAM ANOMALIES Anomalies or inconsistencies found during the evaluation are given below.
These anomalies summarize concerns with the IST program that require additional actions by the licensee for resolution.
The licensee should resolve these items as indicated.
l.
P01 requests relief from establishing reference flow rate or differential pressure during testing ior the SSW pump.
The licensee proposes to determine differential pressure quarterly and compare it and a flow value l
that is obtained from comparing the calculated differential pressure to a computerized pump characteristic curve, to the requirements of Table 4-2 of the IST program.
Flow rate will be measured each refueling outage and this measured flow will be evaluated against the calculated differential pressure and compared to the acceptance criteria of OM-6 and Table 4-2 of j
the IST program.
Regarding determination of differential pressure; it is impractical to directly measure the differential pressure of these submerged pumps because there are no installed inlet pressure instruments. OM-6 does not require measurement of pump inlet pressure and allows differential pressure to be determined.
Therefore, the proposal to determine differential pressure is consist.ent with the requirements of OH-6 provided that the calculations yield 2n acceptable level of accuracy.
Regarding establishing reference flow rate or differential pressure; the SSW pumps supply a system consisting of multiple heat exchangers with automatic temperature control valves that independently modulate flow through each heat exchanger.
It is impractical to control this type of system to allow repeatability of reference values.
Testing these pumps in the "as found" condition and comparing values to an established reference curve may be an acceptable alternative.
The following elements would enhance development or validation of reference pump curves for curve testing:
a.
Curves are developed, or manufacturer's pump curves are validated, when the pumps are known to be operating acceptably.
b.
The reference points used to develop or validate the curves are measured using instruments at least as accurate as required by the Code.
c.
Curves are based on an adequate number of data points, with a minimum of five.
d.
Points are beyond the " flat" portion (low flow rates) of the curve in a range which includes or is as close as practicable to design basis flow rates, e,
Acceptance criteria based on the curves does not conflict with TS or facility Safety Analysis Report operability criteria, for flow rate and differential pressure, for the affected pumps.
1 A-2
\\
f.
If vibration levels vary significantly over the range of pump conditions, a method for assigning appropriate vibration acceptance criteria should be developed for regions of the pump curve.
g.
When the reference curve may have been affected by repair, replacement, or routine service, a new reference curve shall be determined or the previous curve revalidated by an inservice test.
The licensee should follow the eight guidelines identified above for using reference curves, if practicable. Where it is not practicable to follow these guidelines, the licensee should identify the specifics of their alternative and justify the deviations and show the adequacy of their proposed testing.
Regarding not measuring flow rate during quarterly testing; it is impractical to measure pump flow rates because there are no installed pump header flow instruments or test loops.
The only practical quarterly test appears to be to determine differential pressure and measure vibration.
Comparing the differential pressure to the values in Table 4-2 of the licensee's IST program may not permit detection of pump hydraulic degradation or require corrective actions for p ops with significant degradation.
Therefore, the Code acceptance criteria should be used to evaluate the quarterly test data if practicable. Where it is not practicable to use the Code criteria, the licensee should identify the specifics of their alternatives and justify the deviations by showing the adequacy of the alternatives.
In addition, the licensee should perform a study of the maintenance history of these pumps to determine if they are subject to frequent failures where the degradation has not been detected by the quarterly shutoff head testing.
If these pumps are subject to such failures, the licensee should develop a test method capable of detecting degradation that can be performed more frequently than the proposed yearly pump flow test.
(Refer to TER Section 2.1.1.1) 2.
P07 requests relief from establishing reference flow rate or differential pressure during testing for the RBCCW pumps. The licensee proposes to measure as-found pump vibration, differential pressure, and flow rate during quarterly testing and to measure all Code parameters at a reference condition once s year. An adequate method has not been proposed for evaluating quarterly test data, therefore, the quarterly testing may not be capable of monitoring pump condition and detecting degradation. Where it is impractical to test at a reference point, pump testing at as-found conditions can be found to be acceptable if performed in a manner that allows an adequate assessment of pump condition. When reference conditions cannot be established, one means of evaluating pump condition is to compare measured test parameters to reference pump curves established or validated when the pump is known to be operating acceptably.
If a reference curve is used to test these pumps it should be developed or validated in accordance with the guidelines given in Section 2.1.1.1.2 of the TER.
Deferral of a meaningful pump test until once every year may be found to be acceptable, however, insufficient information is provided to support using this test frequency.
To determine the adequacy of a yearly test frequency, more information would be necessary about the pump failure A-3
S i rates, maintenance history, and types of degradation.
In addition, more detailed information would be necessary about the yearly test and its ability to detect pump degradation.
Interim relief should be granted from the Code for one year or until the end of the next refueling outage, whichever is longer. At the end of this interim period, the licensee should implement a test method that adequately evaluates the condition of these pumps quarterly or they should have submitted for approval technical basis demonstrating the adequacy of the proposed yearly testing.
(Refer to TER Section 2.5.1.1) 3.
P09 requests relief from the flow rate measurement requirements for the diesel fuel oil transfer pumps.
The licensee proposes to observe that each pump provides flow greater than is used by the operating EDG, measure pump discharge pressure, and perform full spectrum vibration ana:ysis quarterly.
In addition, once every operating cycle the licensee will determine flow rate by measuring the change in day tank level over time.
The proposed quarterly testing verifies pump operation but provides little information to permit detection of hydraulic degradation.
However, the testing performed once every cycle should permit detection of degradation provided the flow rate determination is sufficiently accurate. The licensee indicated that the accuracy of the flow rate determination would be comparable to the OH-6 accuracy requirements.
It is assumed that the determination is as accurate as data that could be obtained from instruments meeting the Code requirements.
If the determination is less accurate, the adequacy of the less arcurate in 'onnation should be justified in the IST program.
Relief should be granted from the Code requirements. (Refer to TER Section 2.6.1.1) 4.
Requests V01 and V10 request relief from the Code stroke time measurement requirements for the specified valves and propose to verify valve operational readiness by observing proper valve response during system testing.
This test does not provide indication of valve condition or permit detection of degradation.
Long term relief should not be granted for testing that is incapable of monitoring valve condition.
Interim relief should be granted for one year or until the end of the next refueling outage, whichever is longer.
The licensee should develop a means to obtain meaningful stroke times or to otherwise monitor for degrading conditions of these valves.
This testing should be performed quarterly if practicable, however, if quarterly testing is impractical the alternate frequency should be justified in the IST program.
This testing might involve non-intrusive diagnostic techniques such as acoustics, magnetics, ultrasonics, thermography, or radiography.
If it is determined that it is impractical to use testing methods effectively, an enhanced maintenance program or periodic replacement may be acceptable.
(Refer to TER Sections 3.1.1.1 and 3.2.1.1) 5.
V05 requests relief from the relief valve testing requirements of OM-1 for the main steam safety valves and dual function ( ADS) relief valves.
j The licensee proposes to bench-check or replace 1/2 of the valves from both groups every refueling outage but resumption of power generation may begin prior to obtaining test as-found data and the sample size will not be expanded based on test failures.
The licensee is testing or replacing more of these valves than required by the Code. This partially offsets the need for an increased test sample should a failure occur. However, A-4
I the licensee's proposal would require no further testing even if all of the tested valves failed to function properly.
Because of the possibility of common mode failures, the licensee's proposal to not perform additional testing based on test failures is not conservative and I
may not be warranted.
Because of the history of low failure rates and the lack of common mode l
failures for these valves at Vermont Yankee and other nuclear facilities, the proposal should provide a reasonable level of quality and safety for an interim period. However, there is always the possibility of common mode failures.
Therefore, for the upcoming refueling outage, if one of these valves fails a test, the licensee should expeditiously perform the required root cause analysis to determine if there could be a common mode or generic failure concern.
If it is determined that the cause of the test failure is generic or common with the other group valves, the remaining valves should be inmediately tested, even if this requires a plant shutdown.
Relief should be granted from the Code requirement for an interim period until the refueling outage following the August 1993 refueling outage.
In the interim, the licensee should assess the testing requireme..ts for these valves.
The assessment may include TS changes and Code inquiries.
(Refer to TER Section 3.10.1.1) 6.
V09 requests relief from the leak rate testing requirements of OH-10 for the RHR shutdown cooling suction and discharge header outboard containment isolation valves.
The licensee proposes to verify valve leak tight closure capabilities by observing downstream pressure indication during power operation.
Since there are two closed valves in series, observation of a downstream pressure instrument does not provide assurance that each series valve is leak-tight.
Since the proposed testing does not verify the leak-tightness of the subject valves and leak rate testir.g them in accordance with the Code has not been shown to be impractical or to be an unusual hardship without a compensating increase in the level of quality and safety, long term relief should not be granted.
Interim relief should be granted for one year or until the next refueling outage, whichever is longer.
By the end of the interim period, the licensee should develop and implement procedures to leak ate test valves V10-17, -27A, and -278 in accordance with 1 4.2.2.3.
(Refer to TER Section 3.6.1.1) 7.
Relief request V04 proposes to test the specified valve by disassembly, inspection.
Disassembly and inspection is a maintenance procedure that provides much information about valve condition.
However, due to hazards associated with this procedure, it should not be routinely used in lieu of testing if a test method is practicable.
Some test method may be feasible to verify closure of this valve.
The licensee should consider methods such as using non-intrusive techniques (e.g., acoustics, ultrasonics, magnetics, radiography, and thermegraphy) to verify closure of the subject check valve.
This testing may only be practical at cold shutdowns or refueling outages.
The licensee should perform their investigation and if a test method is found to be practicable, the applicable valves should be tested instead of using disassembly and i
inspection. The licensee should respond to this concern within one year from receipt of this report.
(Refer to TER Section 3.9.1.1) r A-5
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