ML20118A403
| ML20118A403 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 08/28/1992 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML20118A402 | List: |
| References | |
| NUDOCS 9209040217 | |
| Download: ML20118A403 (7) | |
Text
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SAFE 1Y EVALVAT10f1 BY THE Of flCLOF f4VCLEAR RLACTOR REGUL AT10t1 E[1ATED TO AMEf4DMENT NQ1.,135 AND 114 TO FACILITY OPERATUgj Ll WISE NOS. OPR-70 AND DPR-75 PUBLIC SERVICE ELETRIC & CAS COMPANY P'ill AtlELPHI A ELECTRlf COMPAt4Y QLLiiARVA POWER AND LlqHT COMPANY
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61LAf411C CITY ELLG RIC COMPAffY SALEM NVCLEAR GENERATING STATION. UNil NOS. 1 AND 2 DOCKET NOS. 50-272 At40 50-311
1.0 INTRODUCTION
By letter dated August 26, 1992, the Public Service Electric & Gas Company, Philadelphia Electric Company, Delmarva Power and Light Company and Atlantic City Electric Company (the licensees) submitted a request for changes to the Salem Nuclear Generating Station, Unit Nos. 1 and 2, Technical Specifications (15).
The requested changes would revise Salem Unit I and 2 Technical Specification Sections 3/4.3.1 reactor trip system (RTS) as follows:
1.
Limiting Condition for Operation 3.3.1.1
(
A.
Table 3.3-1 1)
(Units 1 and 2) functional Unit 11.
Change applicable ACTION from 7 (present) to 6 (proposed).
2)
(Units 1 and 2) ACT10fJ 6.
Change the time an inoperable channel may be maintained in an untripped condition from 1 (present) to 6 (proposed) hours.
Allow placing the inonerable channel in bypass while testing another channel in the same function, instead of placing the tested channel in bypass.
Change the time an inoperable channel may remain in bypass to support testing another channel in the same function from 2 (present) to 4 (proposed) hours.
B.
Table 4.3-1 1)
(Units 1 and 2) functional Unit 11.
Change CHANNEL FUNCTIONAL TEST frequencies from monthly (present) to auarteriv (proposed).
9209040217 920828 PDR ADOCK 05000272 P
2.0 EVALUATION Many utilities expressed concern over the level of testing and maintenance requirements, and theit impact on plant operation, particularly in instrumentation systems.
The Westinghouse Owners' Group (WOG) initiated a program to respond to these concerns, by developing a justification for revising generic and plant-specific instrumentation TS. This program is documented in WCAP-10271 and its supplements, and referred to as the Technical Specification Optimization Program (TOPS).
Many operating plants experienced inadvertent reactor trips and safeguards actuations while performing instrumentation surveillances.
These actions resulted in unnecessary plant transients and safety system challenges.
Plant personnel devote a significant amoup d time and effort to performing, documenting, reviewing, and tracki 4 r% W.) cveillance activities.
Many of these surveillances are unwarra:.cc du.
+he
'.5 level of equipment reliability.
An opportunity for sw hingct.pd,, existed through revised instrumentation test and maintenance en,p w tt.
The NRC staff issued a Safety Evaluation Rtport (SER) for WCAP-10271 and supplement 1 in a letter dated February 21, 1585. The SER approved quarterly testing, 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to place a failed channel in a tripped condition, and increased A0T for testing RTS analog channels.
increasing the RTS surveillance test intervals (STis) minimizes the potential number of inadvertent reactor trips.
Less frequent survelliance testing is estimated to result in 0.5 fewer inadvertent reactor trips per unit, per year.
Increasing the STis enhances the operational effectiveness of plant personnel.
Reducing the amount of time devoted to surveillance testing allows manpower reallocation to tasks such as preventive maintenance.
Increased allowed outage times (A0Ts) result in fewer human factors errors, since more time is allotted to perform corrective actions.
WCAP-10271 results indicate that the reduction in testing frequency and the increase in maintenance A0Ts do not adversely affect public health and safety.
The proposed changes will reduce the number of inadvertent reactor trips and support better utilization of plant resources, in a telephone conversation with PSE&G on August 28, 1992, they confirmed that pressure level instrument drift had not been experienced.
Therefore, extending the STI from monthly to quarterly would not cause the instruments to exceed the drift tolerance.
In addition, the setpoint methodology used at Salem Units 1 and 2 properly account for drift associated with extended STis.
The proposed change to ACTION 6 also affects the following FUNCTIONAL UN1?5 of Table 3.3-1:
4 9.
Pressurizer Pressure-Low 10.
Pressurizer Pressure-High
- 16. Undervoltage-Reactor Coolant Pumps
- 17. Underfrequency-Reactor Coolant Pumps
--um
Plant modifications are not required to implement the requested changes.
WCAP-10271 allows testing of the operable channels in the bypass mode.
Salem Units 1 and 2 do not have the capability of testing the operable char.nels without first bypassing the inoperable channel, with the exception of the Containment Pressure High-High channels.
The staff finds the proposed changes to the ST!, A01, and ACTION requirements to be in accordance with the staff's SER for WCAP-10271 and Supplement I and is, therefore, acceptable.
3.0 EMERGENCY CIRCUMSTANCES In PSE&G's August 26, 1992 letter, they requested that their application for the license amendments be processed as involving exigent circumstances.
Because only three days are available to issue the amendments, the staff is processing the amendments as an emergency change per 10 CFR-50.91(a)(5).
PSE&G entered Limiting Condition (LCO) 3.3.1.1 functional unit 11 on August 13, 1992, at 2026 hours0.0234 days <br />0.563 hours <br />0.00335 weeks <br />7.70893e-4 months <br />.
Pressurizer level channel 3 was declared inoperable because it was out of specification low when compared to the other two level channels.
(CHANNEL CHECK)
PSE&G has been experiencing difficulties (channel checks) with this channel since early August 1992.
In early August, Instrument and Control (l&C) personnel satisfactorily performed a channel calibration on this channel.
The calibration data indicated a 200 millivolts (low) discrepancy.
On August 13, 1992, the channel was declared inoperable due to failing its channel check.
1&C personnel found the channel 90 millivolts high.
The channel was satisfactorily recalibrated; however, the TS action statement was not exited. At this time, a channel check indicated a good correlation
-(within 3% as required by TS) with channel 1 (of pressurizer level), but marginally met the required band for channel 2.
PSE&G (!&C) supervision decided to perform a sensor calibration on channel 2 to ensure that it was not
-the source of problem. However. while preparing for this sensor calibration, channel 3 drifted out of specification.
PSE&G 1&C supervision and Technical Department System Engineering opted to replace the transmitter circuit boards with new ones prior to recalibrating cnannel 3.
Channel 3 could not be satisfactorily calibrated with the new circuit boards.
The old circuit boards were re-installed; however, the channel still could not be calibrated.
PSE&G decided to replace the channel 3 level transmitter and sought Westinghouse's assistance.
NOTE:
All pressurizer level transmitters had been replaced during the past refueling outage at required by NRC Bulletin 90-01.
In addition, the bellows assembly was also replaced.
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1 During the transmitter replacement, the reference sealed *eg must be drained.
Prior to draining the reference leg, the bellows must be protected by inserting a protection device which will prevent the bellows from collapsing.
During this evolution, it was noted that the bellows assembly (Pressurizer level channel 3) was collapsed, indicating either a leak in the bellows or a loss of filled fluid.
With the new transmitter installed, and vendor support, a series of tests were conducted. A Westinghouse standard pressure test on the bellows was conducted. This test pressurizes the bellows to about 15 psi and it is maintained for about 6 to 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. At the conclusion of the pressure test, the line is evacuated to check for vacuum loss. No leaks were identified.
The reference leg was then filled with deaerated demineralized water and the bellows housing is installed.
A depth test of the bellows was performed followed by an external pressure test (up to 3000 psi).
This pressure is left on for approximately 1/2 to I hour. At the conclusion of the test, the line is depressurized and a second depth test is performed.
This second measurement indicated approximately-a 1/4th of an inch dearession, which is indicative of a potential small leak on the bellows assem)1y.
PSE&G is presently replacing the bellows assembly.
The bellows are located approximately 100 ft. from the transmitter on elevation 150 ft. of the Pressurizer. Work at this aarticular location has been restricted due to heat stress considerations, and aas significantly hampered the ability of PSE&G to accomplish this work.
PSE&G has indicated that with Westinghouse assistance, it is aggressively hrsuing the bellows assembly replacement.
At midnight on August 29, 1992, pressurizer level channel I becomes overdue for its channel functional test.
Because of the present TS surveillance requirement, Salem Unit I will have to shut down since it can not perform the required surveillance without incurring a reactor trip.
Unit 2 has been included to keep consistency between the two Salem units.
1 The staff has reviewed the circumstances associated with PSE&G's request for an emergency TS change. ine staff has concluded that this condition could not have reasonably been foreseen because of the prorlems experienced in calibrating the instrument and apparent equipment failures.
4.0 FINAL NO SIGNIFICANT HA7ARDS CON 11 DERAT 10N DETERMINATION The Commission's regulations in 10 CFR 50.92 state that the Commission may make a fina1' determination that a license amendment involves no significant hazards consideration if operation of the facility in accordance with the amendment would not:
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-S-(1) Involve a significant increase in the probability or consequences of an accident previously evaluated; or (2) Create the possibility of a new or different kind of accident from any accident previously evaluated; or (3) Involve a significant reduction in a margin of safety.
The licensee proposed that the proposed TS change did not involve a significant hazards consideration, stating as follows:
"The proposed Technical Specification changes:
1.
Do not involve a significant increase in the probability or consequences of an accident previously evaluated.
SERs-issued for WCAP-10271. WCAP-10271 Supplement 1. WCAP-10271 Supplement 2 and WCAP-10271 Supplement 2 Revision 1, document the determination that the proposed changes are within acceptable limits.
Implementation of the proposed changes decreases the total Reactor Protection System (RPS) yearly availability, primarily due to less frequent surveillance testing.
Decreased availability causes a higher probability of Anticipated Transient Without Scram (ATWS), with an associated increase in the core melt contribution resulting from an ATWS.
Decreased ESFAS availability slightly increases the CDF [ core damage frequency). The proposed changes result in a significant reduction in the core melt probability from inadvertent reactor trips.
This reduction is primarily attributable to less frequent surveillance testing.
The reduction in inadvertent reactor trip core melt frequency is large enough to counter the increase in ATWS core melt probability, resulting in an overall reduction in total c0re melt probability.
The WOG determined values for the increase in CDF were documented in the WCAP, and independently verified by Brookhaven National Laboratory, as part of an NRC Staff audit and sensitivity analysis.
Based on the small increase in CDF compared to the range of uncertainty, the increase is considered acceptable.
(*) Saler, Functional Unit 9, evaluated on a plant-spectfic basis, falls within the same criteria and is considered acceptable.
(*) Not applicable to functional unit 11.
Therefore, it may be concluded that the proposed _ changes do not increase the severity or consequences of an accident previously evaluated.
The proposed changes do affect the probability of RPS failure, but do not alter the manner in which protection is afforded, nor the manner in which limiting criteria are established.
i 2.
Do not create the possibility of a new or different kind of accident from any previously evaluated.
The >roposed change-do not involve hardware modifications or result in c1anges to RPS provided plant protection.
RPS functionally is not altered.
Therefore, it may be concluded that the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.
3.
Do not involve a significant reduction in a margin of safety.
The proposed changes do not alter the manner in which Safety Limits, limiting Safety System Setpoints, or limiting Conditions for Operation are determined.
The impact of reduced testing is a longer timt in..rval over which instrument uncertainties (e.g., drift) may act.
Experience indicates that the initial uncertainty assumptions are valid-for reduced testing.
Therefore, it may be concluded that the proposed changes do not involve a significant reduction in a margin of safety.
Based on the above discussion, the staff concludes that this amendment meets the criteria and therefore, does not involve a significant hazards consideration.
5.0 STATE CONSULTATION
In accordance with the Commission's regulations, the New Jersey State official was notified of the proposed issuance of the amendments.
The State official had no comments.-
6.0 ENVIRONMENTAL CONSIDERATIQB The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20.
The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure.
The Commission has made a final no significant hazards finding with respect to this amendment. Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Pursuant to 10 CFR 51,22(b) no environmental impact statement or environmental assessment need be prepared in connection with t'-
issuance of the amendment.
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, i 7.0 2101US10!4 The staff has concluded, based on the considerations discussed above, that:
(1)-the amendment does not (a) significantly increase the probability or consequences of an accident previously evaluated, (b) increase the possibility of a new or different kind of accident from any previously evaluated or (c)
-significantly reduce a safety margin and, therefore, the amendment does not-involve a significant hazards consideration; that the health and saftty of the public will(2) there is reasonabic asserance not be endangered by operation in the proposed manner; and (3) such activities will be conducted-in compliance with the Commission's regulations, and the issuance of this amendment.will not be inimical to the common defense and security or to the health and safety of the public.
Principal Contributor:
J. C. Stone
-Date:
August 28, 1992
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