ML17285A105
| ML17285A105 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 11/23/1988 |
| From: | Martin J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML17285A104 | List: |
| References | |
| 50-397-88-24, NUDOCS 8812120002 | |
| Download: ML17285A105 (10) | |
Text
APPENDIX A NOTICE OF VIOLATION Washington Public Power Supply System Washington Nuclear Project No.
2 (WNP-2)
Docket No. 50-397 License No.
NPF-21 During an NRC inspection conducted from August 22 to September 2, 1988, several violations of NRC requirements were identified.
In accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions,"
10 CFR Part 2, Appendix C (1988),
as modified by 53 Fed.
Reg.
40019 (October 13, 1988), the violations are listed below:
A.
Paragraph 6.8.1 of the Technical Specifications requires written procedures to be established, implemented, and maintained for surveillance and test activities of safety-related equipment.
Paragraph 6.8.2 of the Technical Specifications requires these procedures and changes to these procedures to be reviewed by the POC and approved by the Plant Manager, as set forth in administrative procedures.
Paragraph 6.8.3 of the Technical Specifications allows temporary changes to be made to procedures provided that the intent of the original procedure is not altered, the change is approved by two members of management staff (at least one of whom holds a Senior Operator license),
and the change is documented, reviewed by the
- POC, and approved by the Plant Manager within 14 days of implementation.
Administrative Procedure 1.2.3, "Use of Procedures" (Rev.
12 dated September 18, 1987), requires procedures to be followed in the performance of plant activities.
When procedures cannot be followed, a revision to the procedure or a procedure deviation must be completed.
In the case of a procedure deviation, documentation prior to its implementation is not required provided the deviation has been approved by two members of plant management/supervisory staff and the Shift Manager is of the opinion that the work must continue.
Contrary to the above, changes were made to Surveillance Procedure 7.4.4.3. 1.4 during the performance of a drywell sump flow monitor calibration on August 24, 1988, and a procedure revision or procedure deviation was not completed.
This is a Severity Level IV violation (Supplement I).
B-10 CFR 50.72(b)(2)(ii) requires the licensee to notify the NRC as soon as practical and in all cases within four hours of any event or condition that results in an automatic Reactor Protection System (RPS) actuation that is not part of a preplanned sequence during testing or reactor operation.
Contrary to the above, the following RPS actuations were not par t of the preplanned sequence during testing or reactor operation, and were not reported to the NRC as required:
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At 0844 on May 29, 1988, during Mode 5 operation, an RPS actuation occurred during initial testing of the alternate rod insertion (ARI) system.
The RPS actuation occurred when air pressure bled off the scram valves after the ARI system was placed in the test mode and the scram air header was isolated.
Control rod drive air system leakage resulted from undocumented air system leaks, and the RPS actuation was not a normal occurrence and was not anticipated in the ARI system test procedure.
4 At 1553 on August 26, 1988, during Mode 5 operation, an RPS actuation occurred when Division II RPS power was transferred from the alternate to the normal source.
The RPS actuation was due to switch over-travel during the power transfer evolution.
The control room logs did not indicate that testing was in progress at the time of the RPS actuation, and the licensee could not produce a
maintenance work order or other documentation to demonstrate that testing was in progress during the August 26 event.
This is a Severity Level IV violation (Supplement I).
C.
Technical Specification 6.8.1 states, in part, that "Written procedures shall be established, implemented, and maintained covering... the applicable procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978."
These include "Procedures for Performing Maintenance".
Paragraph E of Administrative Procedure 1.3.9, Revision 9, "Control of Electrical and Mechanical Jumpers and Lifted Leads," states in part that any deviations to the determination/retermination data sheet following Shift Manager approval shall be reauthorized by the Shift Manager.
Contrary to the above, each of the "determination/retermination" sheets associated with completed maintenance work requests HWR-A-0110 (troubleshooting blown fuses on the power supply to solenoid pilot valves for MS-V22A-D) and MWR-AU9257 (repair of leaking valve RHR-V53-B) contained a cable which had been determinated but not reterminated.
The changes to the work instruction had not been authorized by the Shift Manager.
This is a Severity Level IV violation (Supplement I).
D.
10 CFR 50, Appendix B, Criterion XVI, "Corrective Action", requires measures to be established to assur e that conditions adverse to quality, such as defective equipment and nonconformances, are promptly identified and corrected.
Contrary to the above as of September 2, 1988, two torque wrenches and one leak rate monitoring instrument had been identified 12-18 months prior to the inspection as being out of calibration, but an evaluation of the impact of this lack of calibration had not been performed.
This is a Severity Level IV violation (Supplement I).
Pursuant to the provisions of 10 CFR 2.201, the Mashington Public Power Supply System is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN:
Document Control Desk, Washington, DC 20555, with a copy to the Regional Administrator, Region V, within 30 days of the date of the letter transmitting this Notice.
This reply should be clearly marked as a "Reply to a Notice of Violation" and should include for each violation: (1) the reason for the violation if admitted, (2) the corrective steps that have been taken and the results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4) the date when full compliance will be achieved.
If an adequate reply is not received within the time specified in this Notice, an order may be issued to show cause why the license should not be modified, suspended, or revoked or.
why such other action as may be proper should not be taken.
Consideration may be given to extending the response time for good cause shown.
FOR E NUCLEAR REGULATORY COMMISSION Dated at Walnut Creek, California this 2Q day of November, 1988 D. B. Martin Regional Administrator
1 APPENDIX B Areas Ins ected and Results 0 erations During the inspection period, the licensee declared an emergency action level of Unusual Event (UE) due to a drywell unidentified leakage indication ex'ceeding Technical Specification limits.
That event permitted the team an opportunity to observe control room operator performance under off-normal circumstances.
Conduct of the operations staff in the control room appeared professional and the staff displayed a good attitude toward their assigned duties.
Documentation and log book entries were considered too abbreviated in nature.
Plant upsets and inoperable equipment are not highlighted and carried forward in the control operator's log for reference by the oncoming operations crew.
Technical Specification action statement times and train outages were not tracked by a formal system other than a note in the log book.
I Reportability evaluations did not appear to be consistent in that an RPS actuation which had occurred on August 25, 1988 was determined to have been reportable under 10 CFR 50.72.
- However, a similar RPS actuation occurred the next day, August 26, 1988, and was determined to be not reportable due to in process testing.
The control room logs did not indicate any in process testing had been undertaken.
Material Plant Condition Plant tours conducted by the team indicated that there was a lack of attention to detail in maintaining plant equipment.
Access to the drywell was permitted during a reactor shutdown on the second week of the inspection.
The team observed debris, an electrical wire attached to the reactor vessel which had not been author ized on plant drawings, a missing electrical connector cover
- plate, and excessive rust on piping and components within the drywell.
The material condition of other plant equipment outside the containment also appeared to need attention.
This equipment included:
emergency lighting battery electrolyte levels found low, a missing conduit cover, a grounding wire not secured, handwheels not secured, and failed local indicator lights.
A foreign substance was observed in the diesel generator jacket water system,
- however, no documentation had been initiated to identify the potential pr obl em.
Observations and documentation of unexpected plant occurrences by plant personnel did not appear to be routine, as evidenced on one occasion witnessed by the team.
During a start of the RHR pump, an unusual condition was observed prior to the pump start in that the pump shaft had begun rotating backwards.
During the pump start, a water hammer occurred.
These two events were not logged and, other than followup by the system engineer in the control room, did not appear to have attracted licensee attention.
The team expressed concern regarding these two events to plant management.
Followup investigation by the licensee of the team's concern revealed that the discharge check valve in the RHR pump had failed to close, which led to the draining of the discharge piping.
This would have caused the shaft rotation and potentially the water hammer which occurred when the piping rapidly refilled during the pump start.
This same event apparently occur red several days earlier during another pump start.
No significant followup by the licensee occurred.
Diesel generator material condition was the greatest concern.
A number of
- items, such as tubing supports, piping coupling alignment, fluid levels, foreign material within fluids, and engine support deficiencies, were identified based on visual inspections during tours conducted by the team.
The items described had not been previously identified by the licensee.
Conduct of Plant Surveillances In general, surveillances conducted by operations personnel appeared to have been performed in a satisfactory manner.
Procedure requirements were adhered to with results correctly reported.
An instrument calibration of the drywell sump monitor was observed by the team.
Apparently, the procedure used during the calibration contained inaccuracies which were changed while the calibration was still in-process.
Administrative controls established by the licensee to control procedure changes apparently were not followed.
Vendor Manual Review A review was conducted of vendor manual and service advice or bulletins to determine the status of the information.
Two areas selected were the emergency diesel generator and ASCO solenoid valve vendor information status.
The inspection revealed that the licensee did possess the vendor information which was known to the team.
Information supplied by the Automatic Switch Company (ASCO) was present in the licensee library.
Vendor information appeared to be adequately addressed by the licensee.
Service information provided by the diesel generator vendor was in the licensee library, however two areas did not appear to be adequately addressed.
Those areas were the engine governor oil level and air line oil lubricators.
Engine governor oil level was not addressed within any of the appropriate procedures for maintenance or surveillance of the engine.
In addition, starting air line lubricator oil drip rates were not addressed by procedures even though the vendor recommended an oil drip rate.
These lubricators supply an oil fog atmosphere to the diesel generator air start motors.
Desi n Process Review The area of design control and the accuracy and completeness of engineering work was addressed in previous inspections.
During the present inspection, a
concern was raised over the number of Field Change Requests (FCR's) generated against one design package.
The number of FCR's generated to correct errors
within the package appears to indicate a lack of rigor in the checking and design verification process.
However, the concerns appear to be already addressed in licensee programs to improve the quality of engineering work.
No new significant design packages were completed and available for review at the time of the inspection.
Plant Oversi ht Grou s
In general, the Nuclear Safety Assurance Group (NSAG) and Corporate Nuclear Safety Review Board (CNSRB) appear to function well.
Except for some difficulty with the tracking systems, no deficiencies were identified.
The Plant Operations Committee (POC) does not appear to be functioning as well as the offsite committees.
Two recent events involving a higher than normal temperature and leakage in the drywell, and the drywell material condition and housekeeping, were not vigorously addressed by the committee in their documentation.
The Plant Operations Committee was aware of both conditions as stated in their
- minutes, however, the long term significance of the elevated drywel'i temperature was not addressed.
Drywell cleanliness was discussed by the POC when drywell inspections indicated that a substandard condition existed in the drywell.
- However, no followup action appeared to have been taken by the committee to ensure that the cleanup was completed.
During the recent plant outage, the team conducted a tour of the drywell and found a number of housekeeping items which should have been corrected prior to plant restart following the plant refueling.
guality Assurance audits appear to be of adequate depth and thoroughness, however, the followup on an audit response appeared to be weak.
An audit finding appears to have been closed out based on a response which was a
restatement of existing policy concerning the walkdowns of a system by engineering personnel.
Although there appeared to be a recent resolution of the identified finding, there did not appear to exist documentation which indicated significant changes to engineering procedures, nor senior management involvement to define policy requirements pertaining to system walkdowns by engineering personnel.