ML15112B109
| ML15112B109 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 05/05/1983 |
| From: | Office of Nuclear Reactor Regulation |
| To: | |
| Shared Package | |
| ML15112B108 | List: |
| References | |
| NUDOCS 8305180059 | |
| Download: ML15112B109 (5) | |
Text
UNITED STATES NUCLEAR REGULATORY-COMMISSION WASHINGTON, D. C. 20555 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION SUPPORTING AMENDMENT NO. 121 TO FACILITY OPERATIlNG LICENSE NO.
DPR-38 AMENDMENT NO. 121 TO FACILITY OPERATING LICENSE NO.
DPR-47 AMENDMENT NO. 118 TO FACILITY OPERATING LICENSE NO. DPR-55 ANDIREQUEST FOR EXEMPTION FROM SECTIONS III.D.2 AND 3 OF APPENDIX J TO 10 CFR PART 50 DUKE POWER COMPANY C0NEE NUCLEAR STATION, UNITS NOS. 1, 2 AND 3 DOCKETS NOS. 50-269, 50-270 AND 50-287 Introduction By application dated April 18, 1983, as supplemented on April 22, 1983, Duke Power Company (DPC or the licensee) proposed changes to the Oconee Nuclear Station,'Unit No. 1 (ONS-1 or the facility) Technical Specifications (TSs). The proposed TS changes would delay certain surveillance requirements until the unit's upcoming refueling outage.
Background
The last ONS-1 refueling outage lasted approximately six months, from June 26 until December 31, 1981.
The extended outage was to determine the broken-bolt failure mechanism, engineer a fix and carry out the required modifications to the lower thermal shield. Many equipment tests, calibrations and inspections required by the TSs were performed early in this refueling outage. Because-of the long outage and the cycle operating history, some TS surveillance requirements are coming due ahead of the scheduled July 3, 1983 refueling outage. DPC has pointed out that the July 3 shutdown date assumes continuous operation and could be as late as 11:59pm on July 15. Therefore, their request is For one-time f changes to delay25 'surveillance requirements until July-16, 1983.
Each area of the proposed TS changes is evaluated below.
Evaluation
- Instrument Channel Calibrations Thirteen different types of instrument channels were calibrated between June ?6 and August10, 1981, in accordance with TS 4.1.1 and Table 4.1-1.
TS 4.0.2.gives.*the maximum allowable interval between surveillance as 22 months 1 5 days.Therefore, these calibrations are due to be performed between May 11 and June 25, 1983.
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DPC has analyzed the instrument channels involved for drift. The channels are subject to only "drift" errors induced within the instrumentation itself and can tolerate long intervals between calibrations.
The process system instrumentation errors induced by drift are expected to remain within acceptable FSAR limits until recalibration can be performed during the upcoming refueling or the next forced outage of sufficient length. Various channels involved n 1 the request for relief are one of a series of redundant channels in a given system. The request for relief involves only the formal surveillance requirement and not the additional checks that the channels receive during shift or monthly inspections.
Substantial calibration shifts within the channel (essential channel failure) is revealed during routine checking and testing procedures.
Additionally, the results of the previous calibration were investigated and the acceptance criteria were met. In two cases (RPS Channel D Flow Instriment and LPIS Sump Level Instrument) the acceptance criteria were not met for the previous calibration. In the case of the Channel D Flow Instrument, however, the system uses total flow in the RPS calculations and this met the acceptance criteria.
In the cas of the Sump Level Instrument the drift, although outside of acceptance criteria, was in the conservative-direction. This instrumentjmeasures leakage from the reactor coolant system and is backed up by redundant.systems (i.e., the reactor building air particulate monitor, iodine monitors, gaseous area monitors and water inventory balances).
Based on our review of this data, we find the additional 73 days (maximum possible) of reactor operation acceptable from an instrumentation reliability standpoint.
Local Leak Rate Testing TS 4.4.1.2.2 requires local leak rate testing of all containment penetrations at intervals no greater than 24 months. This require ment is in agreement with Sections III.D.2 and 3 of Appendix J. to 10.CFR Part 50 (Schedule for Type B and Type C tests). The last electrical penetration 0-ring seal leak test and the mechanical penetratio n leak rate test for Unit 1 began June 30, 1981 and July 4, 1981, respectively. The detailed data show only three of the 61 electrical penetrations and three mechanical penetrations were tested before July 16, 1981 and, therefore, are due before the latest proposed shutdown date, 11:59pm on July 15, 1983.
The justification to delay surveillance for each is as follows:
Electrical Penetration 0-ring Seal Test An oper ting experience review by DPC has shown that failure of 0-ring seals at the plant are relatively low.
Of the more than a thousand leak rate tests performed to date, only two failures of 0-ring seals have been found.
All electrical penetrations are grouped within or vented to the penetration room which is formed adjacent to the outside surface of each Reactor Building by enclosing the area around the majority of the penetrations.
Each penetration room is provided with two fans and two filter assemblies. When the filtration system is placed into operation (upon receipt of an engineered safeguards signal from the Reactor Building), a negative pressure will be maintained in the peneiration room to assure inleakage which is collected and discharged through HEPA and charcoal filters to the unit vent.
We, therefore, find reactor operation without performing the TS required Type B tett (Appendix J of 10 CFR 50, Section III.B) acceptable based on previous reliability, system design and the short period of time (less than 16 days beyond the scheduled due date).
Additionally, justification has been provided for the schedular relief from the 24 month test interval specified in Appendix J.
- Mechanical Penetration Leak Rate Test There are only three penetrations affected by the request for relief.
Penetration 10 is tied to the HPI system outside of containment which is a closed system and seismic designed. Penetration 38 (Quench Tank Cooler Inlet Line) is also a closed system and non-seismic outside the containment isolation valve. Penetration 55 (Demineralized Water upply) is a closed system and non-seismic outside the containment isolation valve. Additional justification provided by the licensee is the mechanical penetration design and the negative pressure features of the penetration room mentioned above. All mechanical penetrations are grouped within or vented to the penetration room. Any leakage that might occur from these penetrations will be collected and discharged through HEPA filters and charcoal filters to the unit vent. The leakage barrier in the Reactor Building is the one-quarter inch steel.liner plate.. All penetrations are continously welded to the liner plate before they are embedded in concrete. The penetrations become an integral part of the liner and are designed, installed, and tested as such. Additionally, the steel liner plate is attached to the prestressed concrete Reactor Building and forms an integral part of the structure. The Reactor Building is conservatively designed and rigorously analyzed for the extreme loading conditions of a highly improbable hypothetical accident as well as for other types of loading conditions.
We find continued reactor operation for less than 12 days beyond the test schedule acceptable. Likewise, relief from the Type C test of Appendix J to 10 CFR,Section III.G is justified and should be granted.
- Engineered Safety Features (ESF) Valves TS 4.5.1.2.2.b requires critical low pressure injection (LPI) valves to be cycled manually each refueling outage. DPC states that valves LP-9, 10, 12, 14, 17 ahd 18 of the LPI and core flooding systems were last cycled beginning July 21, 1981.
Therefore, the retest is due starting June 6, 1983, about 50 days before the latest shutdown date.
-4 Justification provided is satisfactory stroke test results of these valves in the past.
We find the 50-day delay in testing the operability of the LPI and core flooding systems' valves, as listed above, acceptable.
- Emergency Power Circuitry TS 4.6.4 requires a simulated emergency transfer of the 4160 volt main bases to the startup transformer and to the standby buses during each refueling outage. The last such transfer was performed August 21, 1981, thus it is due by TS on July 6, 1983. The licensee's justification for the needed extension of nine days is no previous operational problems with these breakers.
We find delaying this simulated emergency transfer for nine days maximum will not adversely-affect reactor safety and is, therefore, acceptable.
- Mechanical Snubbers DPC states that five inaccessible mechanical snubbers on the steam generator flush and drain line were previously inspected on July 12, 1981, per TS 4.18.1.
Thus, the inspection on these snubbers is due May 28, 1983, 49 days before the latest possible shutdown date. Justification for this inspection delay supplied by DPC is the relative low stress conditions that would exist if some of the snubbers were inoperable, a new snubber installed last outage and one snubber on non-safety grade piping.
We find the proposed TS change delaying inspection of the subject mechanical snubbers for 49 days acceptable.
Conclusion We conclude that there is adequate justification for the short-time postponement of the TS surveillance of the equipment described above.
Some of the TSs should be modified to meet our requirements such as limiting the exemption coverage. This has been discussed with the DPC staff and agreement reached.
We further conclude that an exemption to the schedular requirements of Sections III.D.2 and 3 of Appendix J to 10 CFR Part 50 is justified.
Environment 1 Consideration We have determined that this action does not authorize a change in effluent types or total amounts nor an increase in power level and will not result in any significant environmental impact. Having made this determination, we have further concluded that this action involves an action which is insignificant from the standpoint of
-5 environmental impact and, pursuant.to 10 CFR §51.5(d)(4), that an environmental impact statement, or negative declaration and environ mental impact appraisal need not be prepared in connection with this actionj Safety Conclusions We have concluded, based on the.considerations discussed above, that:
(1) because the amendments do not involve a significant increase in the probability or consequences of an accident previously evaluated, do not create the possibility of an accident of a type different from any evaluated previously, and do not involve a significant reduction in a margin of safety, the amendments do not involve a significant1 hazards consideration, (2) there is reasonable assurance that the health and safety of the public will 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 these amendments will not be inimical to the common defense and security or to the health and safety of the public.
We have also determined, pursuant to 10 CFR 50.12, that an exemption from the requirements of Sections III.D.2 and 3 of Appendix J to 10 CFR 50 is authorized by-law, will not endanger life or property or the common defense and security and is otherwise in the public interest.
Dated: May 5, 1983 The following NRC personnel have contributed to this Safety Evaluation:
E. Conner, and John F. Suermann.