ML20117A649
| ML20117A649 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 04/30/1985 |
| From: | NRC |
| To: | |
| Shared Package | |
| ML20117A615 | List: |
| References | |
| NUDOCS 8505080299 | |
| Download: ML20117A649 (5) | |
Text
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UNITED STATES
.8.
-g NUCLEAR REGULATORY COMMISSION ij WASHINGTON, D. C. 20555
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SAFETY EVALUATION AMENDMENT NO. 22 TO NPF-11 AND AMENDMENT N0.10 TO NPF-18 LA SALLE COUNTY STATION, UNITS 1 & 2 DOCKET NOS. 50-373 AND 50-374 Introduction By letter dated February 21, 1985, Comonwealth Edison Company (the licensee) proposed amendments requesting changes to the La Salle Units 1 and 2 Technical Specifications to delete channel check surveillance requirements for reactor vessel level and main steam line flow sensors (differential pressure switches) installed in the reactor protection system, primary containment isolation system, emergency core cooling system, and the reactor core isolation cooling system.
These changes are the result of replacement of existing Barton differential pressure (dp) indicating switches that have local readout capability, with
" blind" dp switches (i.e., local readout capability is not provided) manufactured by Static-0-Ring. Thus, the capability to perform channel checks no longer exists. The reason for the changeout of the dp switches is that the Barton switches were not environmentally qualified in accordance with the requirements of 10 CFR 50.49,
" Environmental Qualification of Electrical Equipment Important to Safety for Nuclear Power Plants." A list of the specific instruments and the associated systems affected by the changeout is provided in Attachment 1.
Evaluation The following definition is provided in the BWR Standard Technical Specifications (STS) for a channel check:
A CHANNEL CHECK shall be the qualitative assessment of channel behavior during operation by observation. This determination shall include, where possible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels measuring the same parameter.
That is, a channel check is d comparison of a group of instrument channel readouts / displays, typically control room indicators, for a given monitored parameter,(e.g., reactor vessel water level). An instrument channel readout that differs significantly from the readouts of the remaining instrument channels is indicative of a channel malfunction. The STS typically requirs that channel checks be performed'once each operating shift (8 hrs.) for those protection system instruments having readout capability._ The performance of a channel check provides a quick and easy method for detecting gross instru-ment failures in the non-conservative direction (i.e., failures away from the trip setpoint) between the surveillance intervals of other more extensive tests (e.g., monthly channel functional tests) which would detect the failure.
8505090299 850430 PDR ADOCK 05000373 P
l A gross failure in the conservative direction would typically be detected in the form of a channel trip (i.e., the setpoint value would be exceeded). For those instruments for which readout / display capability is not provided, periodic surveillance in the form of channel checks is not required. Channel checks are not relied on to ensure the operability of protection system equip-ment. This is accomplished by more extensive testing; channel functional tests and channel calibrations. A channel functional test involves the injection of a simulated signal into the sensor to verify operability inclJding alarm and/or trip setpoint functions. A channel calibration is the adjustment, as necessary, of the instrument channel output such that it responds with the necessary range and accuracy to known values of the parameter which the channel onitors.
It is the combination of these periodic surveillance activities m
which ensures that protection system instrument channels remain operable, and thus, that this portion of the protection system remains in compliance with the single failure criterions.
The performance of channel checks does not increase protection system reliabil-ity, although they may result in increased availability of individual.instru-ment channels. Protection system reliability is achieved and maintained by the design and installation of equipment that satisfies safety criteria set forth in the Comission's regulations (e.g., diversity of parameters, single failure, equipment qualification, channel independence, etc.), and has the capability of being tested and calibrated while retaining the capability to accomplish protective functions. The staff does not require protection system i
sensors to be provided with readout / display capability in order to perform instrument channel checks. If readout capability is provided, then channel check surveillance is typically required by plant technical specifications.
because of the potential benefit gained (i.e., early detection and repair of a failed instrument channel) from a surveillance activity that is simple to perform and does not require significant time or manpower on behalf of the utility. It is noted that requirements exist for the display of information in the control room to allow the operator (s) to assess the status of the plant and the protection system, and to perform manual actions required for
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safety. However, these generic requirements are independent of plant specific capability for performing channel checks.
Channel checks surveillance requirements are typically associated with analog
-instrument channels that provide 4-20mA signals to the control room. These signals or corresponding voltage signals, typically 1-SV, are usually displayed r
on meters / indicators at the main control boards or back row instrument cabinets.
The comparison of indicators monitoring the same parameter by observation cons-titutes the channel check. The indicating dp switches used to sense reactor vessel water level and main steam line flow at La Salle Units 1 & 2 only provide a digital / bistable signal (i.e., the value of the monitored parameter is either above or below the trip setpoint) to the protection system cabinets in the i
control room. There is no associated display capability in the control room which allow the operator (s) to determine how close the monitored parameter value is to the trip setpoint. The dp switches are located at instrument racks in different areas of the reactor building. At these racks, the dp switches have~an associated mechanical indication consisting of a linkage assembly connected to a torque tube (connected to the monitored process) at one end,
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and a pointer and dial assembly at the other end. Channel checks are currently performed by comparison of these local mechanical indications. Although not as accurate or convenient as channel checks of analog channel readouts from the control room, channel-check surveillance was still required because of the 6
potential benefits discussed above. Following replacement of the Barton indi-
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cating dp switches with the environmentally qualified Static-0-Ring dp switches, the capability to perform instrument channel checks will no longer exist for those instruments identified in Attachment 1.
The " blind" Static-0-Ring dp switches are completely sealed; no mechanical indication is provided. The.
licensee has thus requested to delete channel check surveillance requirements for these instruments from the La Salle Units 1 & 2 Technical Specifications.
Based on the NRC staff's review of infonnation provided by the licensee, and a review of the bases for channel check surveillance requirements in the STS, the staff concludes that the proposed revisions to the La Salle Units 1 & 2 Technical Specifications to delete channel check surveillance requirements for those instruments identified in Attachment 1, are acceptable. The licensee has conunitted 1to continue to perform channel checks each shift on all instruments to be replaced up to the time of replacement. This approach is acceptable to the staff.
j Environmental' Consideration This amendment involves a change in the installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20 and changes a surveillance requirement. The 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 Comission has previously issued a proposed finding that this amendment involves no significant hazards consideration and there has been no public coment on such finding. Accordingly, this 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 the issuance of this amendment.
Conclusion The Consnission made a proposed detennination that the amendment involves no significant hazards consideration which was published in the Federal Register (50 FR 12141) on March 27, 1985. No public coments were received.
We have concluded, based on the considerations discussed above, that:
(1) there is reasonable assurance that the health and safety of the public will j
not be endangered by operation in the 3roposed manner, and (2) such activities will be conducted in compliance with t1e Comission's regulations and the issuance of this amendment will not be inimical to the comon defense and j
security or to the health and safety of the public.
1 j
Dated: April 30,1985 p
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ATTACHMENT 1 LIST OF AFFECTED INSTRUMENTS INSTRUMENT NUMBER MONITORED PARAMETER AFFECTEDSYSTEM(S)
& FUNCTIONS 1(2)B21-N026A,B,C,&D Reactor Vessel Level Primary and Secondary Containment Isolation, and RWCU system isola-tion on low level (level 2) 1(2)B21-N024A,B,C,&D Reactor Vessel Level Reactor Scram, and Primary Containment and RHR system Shutdown Cooling Mode Isolation on low level (level 3) 1(2)E31-N008A,B,C,&D Main Steam Line Flow Primary Containment Isolation on High Flow 1(2)E31-N009A,B,C,&D Main Steam Line Flow Primary Containment Isolation on High Flow 1(2)E31-N010A,B,C,&D Main Steam Line Flow Primary Containment Isolation on High Flow 1(2)E31-N011A,B,C,&D Main Steam Line Flow Primary Containment Isolation on High Flow 1(2)B21-NO37A&C Reactor Vessel Level Initiation of ADS (Div.
1), LPCS, and LPCI A on low level (level 1); and RCIC initiation (level 2).
1(2)B21-NO37B&D Reactor Vessel Level InitiationofADS(Div.
- 2) and LPCI B&C on low level (level 1); and RCIC initiation (level 2) 1(2)B21-N101A&B Reactor Vessel Level RCIC termination on high level (level 8) 1(2)B21-N038A Reactor Vessel Level ADS (Div. 1) low level permissive (level 3)
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' INSTRUMENT NUMBER MONITORED PARAMETER AFFECTED SYSTEM (S)
& FUNCTIONS 1(2)B21-N038B Reactor Vessel Level ADS (Div. 2) low level permissive (level 3) 1(2)B21-N100A&B Reactor Vessel Level HPCS tennination on high level (level 8) 1(2)B21-NO31A,B,C,8D Reactor Vessel Level HPCS initiation on low level (level 2)
M DISTRIBUTION
{0sikst' File' NRC PDR Local PDR PRC System NSIC ABournia ((2 )LB#2 Reading)-
EHylton 2
TNovak JSaltzman, SAB Woodhead, OELD CMiles HDenton
'JRutberg AToalston WMiller, LFMB JPartlow BGrimes EJordan LHarmon TBarnhartd)
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