ML20045H436
| ML20045H436 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 07/12/1993 |
| From: | Antony D NORTHERN STATES POWER CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9307200211 | |
| Download: ML20045H436 (8) | |
Text
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Northem States Power Cornpany 414 Nicollet Mall Minneapolis, Minnesota 554011927 Telephone (612) 330-5500 July 12, 1993 10 CFR Part 2 Section 2.201 U S Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 PRAIRIE ISIAND NUCLEAR GENERATING PLANT Docket Nos. 50-282 License Nos. DPR-42 50-306 DPR-60 Response to Notice of Violation Inspection Reports No. 50-282/93008(DRP) and 50-306/93008(DRP)
In response to your letter of June 11, 1993, which transmitted Inspection Reports No. 282/93008 and 306/93008, the following information is offered.
Violation 1
+
Technical Specifications 2.3.A.2.d (Overtemperature AT) and 2.3.A.2.e (Overpower 4T) require that for each percent that the magnitude of qt *9b exceeds +9 percent (where qt and qb are the percent power in the top and bottom halves of the core, respectively) the overtemperature aT and Overpower aT reactor trip set points shall be_ automatically reduced by an equivalent of 2.5 percent of rated thermal power.
Contrary to the above, from January 22 through February 4,1993, the licensee operated Unit 1 in a condition where the Overtemperature AT and Overpower AT reactor trip setpoints would not have been automatically reduced when q, - qb exceeded +9 percent.
This is a Severity Level IV Violation (Supplement I).
Response to Violation 1 On February 4, 1993, Unit 1 was at 100% power.
Surveillance procedure SP1007, Nuclear Power Range Functional Test, was in progress. The instrument technician found that the lower detector flux signal from Nuclear Instrumentation System (NIS) power range channel IN-41 was significantly (about 10%) outside of the acceptance criterion. The system engineer was notified. Work on the surveillance procedure was suspended and a Work Request was written to correct what appeared to be calibration drift of an isolation h
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US NRC NORTHERN STATES POWER COMPANY July 12, 1993 Page 2 amplifier.
Based on the magnitude of the apparent drift, a decision was made to replace the isolation amplifier and investigate the suspected drift in the shop. A replacement isolation amplifier was installed and calibrated satisfactorily.
Later in the day, the surveillance procedure was resumed.
The instrument technician found that the lower detector flux signal from NIS power range channel IN-42 was also about 10% outside of the acceptance criterion. Again, the system engineer was notified. Work on the surveillance procedure was suspended and a Work Request was written to allow recalibration of channel IN-42 and the other two power range channels, IN-43 and 1N-44, since it was anticipated that the other two channels may also be found outside their acceptance criteria.
Channels IN-43 and 1N-44 were indeed found outside their acceptance criteria by a similar amount.
Testing and recalibration of all the i
power range channels were performed expeditiously.
Investigation showed that on January 22, 1993, after the Unit 1 restart from refueling, SP1006B, NIS Power Range Axial Offset Calibration, had been performed.
An interview with the technician involved in that calibration showed that adjustments to the subject isolation amplifiers had been made at that time.
The measurements in question were made using permanently installed test leads to permit viewing the test point voltage levels while adjusting the isolation amplifiers. At the time of the calibration, test lead NIS-2 did not work, so test lead NIS-3 was substituted. Unknown to the technician was that test lead NIS-3 has a built-in surge suppressiea network.
The effect of this surge suppression network was to lower the indicated lower detector flux signal by about 10%.
This effect was confirmed by testing.
Late the same day, all the Unit 1 NIS power range channels had been recalibrated and SP1007 completed.
Investigation showed that Unit 2 power range channels had also been calibrated on January 22, but the proper test lead was used on Unit 2.
Preliminary engineering review on February 5, 1993, indicated that the miscalibration could have resulted in some nonconservatism in the flux difference information provided to the overpower and overtemperature AT protection channels. Based on this review, the event appeared to be reportable.
Cause of the event was use of an improper test lead to calibrate the power range channels on January 22, 1993.
Contributing causes were:
The improper test lead was not labeled to indicate it contains a surge suppression network.
- The technician involved had never been informed that the test lead
1 US NRC NORTHERN STATES POWER COMPANY July 12, 1993 Page 3 contained a surge suppression network.
The technician involved should have questioned the need for making large adjustments to satisfy the acceptance criteria. Adjustment of isolation amplifiers is rarely needed.
Detailed engineering analysis performed later verified that the overpower and overtemperature AT setpoints would not have been reduced as specified in Technical Specifications 2.3.A.2.d and 2.3.A.2,e.
The Technical Specifications require that for each percent that the magnitude of flux difference exceeds +9%, the AT trip setpoint shall be automatically reduced by an equivalent of 2.5 percent of rated thermal power. Actual penalty would have been applied starting at a flux difference of about +15%.
Plant operating records were reviewed over the time that the nonconservative settings existed to. verify that actual plant conditions never exceeded a flux difference of 9%.
Maximum indicated flux difference throughout the period was 7.67%.
(This indication was unaffected by the miscalibration of the power range channels.) Target flux difference during the period was 3.31% plus or minus 5%.
Technical Speci.fications 3.10.B.5 and 3.10.B.6 require operator l
action to restore flux difference to the target band when operating above 50%
power.
Corrective Steos Taken and Results Achieved When the discrepant conditions were identified, work on the surveillance procedure was stopped and Work Requests written to correct the discrepancies.
Investigation found the cause of the discrepant conditions.
All of the Unit 1 NIS power range channels were recalibrated and the surveillance procedure completed satisfactorily.
Corrective Steps to Avoid Further Violations Previously reported (LER 50-282/93003) actions to preclude recurrence include:
Permanent labels were installed to alert the technician of the surge suppression network in the NIS-3 test leads for both units.
The event was discussed with I6C technicians emphasizing the need for self-checking and the need for questioning a calibration shift outside of the acceptance criteria.
This has been documented in an I&C Section Work Instruction requiring notification of a supervisor or system engineer prior l
to making an adjustment.
SP1006B has been revised to perform only a calibration check of the isolation amplifiers. This change, in effect, disallows adjustment of the isolation amplifiers without notification of a supervisor or system
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US NRC NORTHERN STATES POWER COMPANY July 12, 1993 Page 4 engineer. These amplifiers are calibrated at refueling and typically do not require adjustment during the quarterly axial offset calibration.
The cover letter to the Inspection Report specifically requested that we:
... conduct a review of maintenance and testing activities to determine if other conditions exist where lack of an independent or management review, or lack of required notification / recording of the "as-found" condition could result in an impact on operational safety.
These and additional actions to preclude recurrence have been considered and are discussed below:
Our administrative work control processes require an independent review of all Surveillance Procedures and critical work packages, and in all cases require a supervisory / management review.
If calibration adjustments are allowed, a provision to record AS FOUND and AS LEFT data must be present in the procedure to allow such a taview to note anomalies.
Furthermore,.it is preferred that miscalibration be prevented, rather than noting it such that it may be corrected.
Thus, where appropriate, acceptance criteria are typically provided such that out-of-specification AS FOUND values are immediately exhibited during the performance of the work.
Electrical and I&C Areas Electrical and 16C testing and preventive maintenance procedures which could impact operational safety were reviewed against the broad criteria established above.
This included applicable " stock" attachments used as work package attachments for frequently performed tasks.
All Electrical procedures satisfied these criteria.
There was one additional Reactor Protection I&C procedure, the adjustment of power range NIS rate trips (performed during refueling outages), which did not record adjustment data.
The procedure requires an adjustment to J
achieve the acceptance criteria in the procedure, but does not note whether I
channels were found within specification. The bistables which are adjusted in this procedure are checked monthly during power operation.
There were no other I6C Reactor Protection or Safeguards procedures which allowed adjustment without recording adjustment data.
Several non-protection /non-safeguards procedures were found which did not satisfy this particular criterion.
Procedure change requests have been submitted to correct all identified 1
procedural deficiencies except where an exception is allowed.
Exceptions require justification as to why the criteria are not applicable.
For example, in some procedures (e.g., RPI hot calibration), the expected values for AS FOUND data cannot be established.
The lack of recording the AS FOUND data in such cases would not result in an impact on operational safety.
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US NRC NORTHERN STATES POWER COMPANY July 12, 1993 Page 5 In addition to this effort, existing I6C work practices and 160 test equipment were reviewed soon after the NIS miscalibration to determine if there were other potential " traps" that might lead to a miscalibration (common mode or otherwise). A comprehensive list of action items was developed, which will further reduce the likelihood of recurrence of a similar event. Major areas are-
- Improving test equipment control e Review technician calibration practices
- Expand training on use of test equipment e Strengthen relevant procedures These items were identified through a series of meetings involving I&C technicians, engineers, and several levels of management.
Additionally, an I&C Training representative was present so that these " lessons learned" will be factored into future training.
Mechanical Area The mechanical area is different from the I&C and electrical areas in a couple of important ways.
One is that the testing,is usually performed by a different group than the group performing the adjustments / corrections.
The significance of this is that there is more likely to be at least two.
different perspectives on the situation.
The other is that the post-maintenance testing is usually of a different nature than the correction itself.
For example, after adjusting an internal clearance within a safety injection pump, the method of verifying the functionality of the pump is not merely to reverify the correct clearance but to perform a pump functional test which checks the pump performance against a set of acceptance parameters independent of the adjustment method itself.
The significance of this is that the method of verification is not subject to the same errors which may have occurred in measuring the original adj us tment.
However, similar to the effort in the I6C and Electrical areas, a review was performed of the mechanical testing and maintenance procedures where lack of an independent or management review of the procedure results or lack of required notification / recording of the AS FOUND condition could result in an impact on operational safety.
A review was completed for those procedures which were determined to have a potential impset on operational safety. Those procedures were determined to satisfy these criteria. Other procedural deficiencies were. identified and each of these will be revised prior to the next performance of the particular procedure.
Additionally the General Superintendent of Engineering issued a letter to each of the Mechanical Engineering Superintendents outlining the concerns raised by this event and requesting that each mechanical engineering group t
4 US NR.C NORTHERN STATES POWER COMPANY July 12, 1993 Page 6 be apprised of these concerns.
f.mpowerment i
The Plant Manager has a concern that management's philosophy of
" empowerment" (i.e.,
the philosophy that decisions be made at the lowest appropriate level) could be misconstrued such that plant management is inadvertently isolated from situations where there should be management involvement. To address this concern, a letter addressed to all plant personnel has been issued by the Plant Manager clarifying the " empowerment" policy.
Date When Full Compliance will be Achieved Full compliance has been achieved.
Violation 2 Technical Specification 3.6.C.3 states that with one or more valve (s)
I listed in Technical Specification TS 4.4-1 inoperable, within four hours:
(a) restore the inoperable valve (s) to operable status or, (b) deactivate the operable valve in the closed position or, (c) lock closed at least one valve in each penetration having one inoperable valve.
Table TS 4.4-1 lists containment penetration No. 45 (Reactor Makeup to PRT) which includes air-operated isolation valve CV-31342 and check valve 2RC-3-1.
2RM-8-4 is the upstream manual isolation valve for CV-31342, Contrary to the above, on April 13, 1993, CV-31342 was inoperable for greater than four hours, but was not deactivated in the closed position by isolating its air supply, or in lieu of that, 2RM-8-4 was not locked closed I
since check valve 2RC-3-1 could not be deactivated in the closed position.
This is a Severity Level IV Violation (Supplement I).
Response to Violation 2 Backnround The event is described in detail in LER 50-306/93002. The cover letter transmitting the Notice of Violation stated that the corrective action documented in the LER was not comprehensive.
We maintain that the actions we l
are taking are comprehensive, though we had not identified all these actions in the LER itself.
Following is a summary of the LER.
t On April 3, 1993, control room operators performed surveillance procedure l
SP2272, Quarterly Cycling of Pressurizer Relief Tank Reactor Makeup Water and Nitrogen Control Valves.
One containment isolation valve, CV-31342, which controls reactor makeup water to Unit 2 containment, exceeded its maximum time i
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~US NRC NORTHERN STATES POWER COMPANY
-July 12, 1993 Page 7 for closure (an ASME Section XI requirement), and was declared inoperable.
The redundant containment isolation check valve was operable.
To comply with Technical Specifications, the control valve was closed and its air supply was lockwired closed.
Later, to improve control over the penetration, the upstream manual isolation valve was closed.
Later, when the System Engineer requested the control room to stroke the inoperable control valve for troubleshooting purposes, an operator was sent'to restore the air supply to CV-31342. He performed that action, but had misunderstood the instructions and mistakenly opened the manual isolation valve.
Later, another operator making rounds discovered the manual valve open when it should have been shut. The situation was promptly corrected.
Administrative control of the penetration had been lost for about 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />.
The redundant containment isolation check valve was operable throughout the period.
The control valve was subsequently repaired and made operable.
Reason for the Violation Primary cause of the violation was miscommunication of verbal instructions.
Investigation of the event also caused reviews to be.made of the Work Control Process and the Safety Tag Proct L (Safety tags are used to administrative 1y control equipment status and can be issued without a Work Request.)
Corrective Steps Taken and Results Achieved When discovered, proper control of the penetration was.re-established.
Corrective Steps to Avoid Further Violations An Operations newsletter was issued discussing requirements for oral communications.
Operators are reviewing the administrative requirements for oral communications.
The process for use of safety tags has been reviewed and found to be adequate.
Operators-are reviewing the administrative requirements for use of safety tags.
The Work Control Process has been reviewed and has been revised to clarify the requirements for initiating troubleshooting Work Requests.
Date When Full Comn11ance will be Achieved Full compliance has been achieved.
In summary, we have made the following new commitments to the NRC:
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US NRC NC RTHERN STATES POWER COMPANY July 12, 1993 Page 8 (1)
With regard to I&C procedures that had been determined to not meet the evaluation criteria discussed in the text: procedure change. requests have been submitted to correct all identified procedural deficiencies except where an exception is allowed.
(2)
With regard to Mechanical procedural deficiencies identified during the review: each of these will be revised prior to the next performance of the particular procedure.
Please contact Jack Leveille (612-388-1121, Ext. 4662) if you have any questions related to our response to the subject inspection reports.
A d' f o -
/AC86 1
Douglas D Antony Vice President Nuclear Generation c: Regional Administrator III, NRC Senior Resident Inspector, NRC NRR Project Manager, NRC J E Silberg r
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