ML18086B075
| ML18086B075 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 11/09/1981 |
| From: | Schneider F Public Service Enterprise Group |
| To: | Haynes R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| Shared Package | |
| ML18086B074 | List: |
| References | |
| NUDOCS 8111270263 | |
| Download: ML18086B075 (9) | |
Text
Public Service Electric and Gas Company Frederick W. Schneider 80 Park Plaza, Newark, NJ 07101 201-430-7373 Mailing Address: P.O. Box 570, Newark, NJ 07101 Vice President -
Production and Assistant to Senior Vice President -
Energy Supply and Engineering Mr. Ronald C. Haynes, Director November 9, 1981 Off ice of Inspection and Enforcement U.S. Nuclear Regulatory Commission Region I 631 Park Avenue King of Prussia, Pa.
19406 Attention:
Mr. R. R. Keimig, Chief Projects Branch #2, Division of Resident and Project Inspection Gentlemen:
NRC COMBINED INSPECTION 50-272/81-23 AND 50-311/81-21 UNIT NOS. 1 AND 2 SALEM GENERATING STATION We have reviewed the report of your routine safety i~spection conducted by Mr. L. Norrholm during the period August 4-September 14, 1981.
A four day extension to the thirty day reply:requirement was granted by Mr. R. R. Keimig by telephone on November 6, 1981.
Our response to the items of non-compliance identified in Appendix A to your letter of October 7, 1981 are as foilows:
Item A Technical Specification 3.0.4 states, in part, "Entry into an OPERATIONAL MODE or other specified condition shall not be made unle~s th~ conditions of the Limiting Condition for Operation are met without reliance on provisions contained in the ACTION STATEMENTS requirements."
Technical Specification 4.0.3 states, "Failure to perform a Surveillance Requirement within the specified time interval shall constitute failure to meet the OPERABILITY requirements for a Limiting C0ndition for Operation."
Contrary to the above, the following reactor mode changes were made without verification that Limiting Conditions for Operation had been satisfied, without reliance on Action Statements requirements:
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11/~,/81 On June 21, 1981, Unit 1 changed from Mode 4 to Mode 3 with No. 11 RHR Pump inoperable due to a shut isolation valve.
Technical Specification 3.5.2 requires two RHR Pumps in Mode 3 as the Limiting Condition for Operation.
Action Statement 3.5.2.a permits inoperability of one RHR Pump for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
Both pumps were operable within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
This event was reported in Licensee Event Report 50-272/81-62/03L.
On June 21-22, 1981, Unit 2 changed from Mode 5 to Mode 1 without completion of the containment airlock surveillance testing required by Technical Specification 4.6.1.3.b after establishing containment integrity.
When this was discovered on July 1, 1981, an overall airlock test confirmed that the airlock had been operable.
This event was reported in Licensee Event Report 50-311/81-53/03L.
Several times during the period June 2-4, 1981, Unit 2 changed from Mode 3 to Mode 1 while the surveillance test of Technical Specification 4.3.3.7 relative to accident monitoring instrumentation channels was overdue.
When this situation was discovered on June 6, 1981, performance of the. surveillance test confirmed that the instrumentation had been operable.
This event was reported in Licensee Event Report 50-3ll/81-39/03L.
Reply To Item A On June 21, 1981, the isolation valve in Unit No. 1 was not positioned properly following realignment of the system and a second verification of the system realignment was not performed.
The valve was positioned properly immediately upon discovery of the error.
Operations personnel directly involved were counseled on the errors made.
A letter was issued on June 29, 1981 to all operations personnel informing them of the occurrence and the errors made, and stressed the importance of fulfilling the responsibilities of their jobs.
Additionally, the Tagging Request and Inquiry System (TRISl, a computerized equipment and component tracking system, is presently being finalized and will be fully operational by December 1, 1981.
The TRIS system will fully document all tagging, tagging releases, and system alignments.
We feel that these steps will assist in preventing further recurrences of the problem.
We are in full compliance now.
On June 21-22, 1981, the Unit No. 2 containment airlock surveillance requirement was overlooked by operations personnel while changing modes.
This No. 2 requirement is new and different from the requirement for Unit No. 1 which calls for a leakage test every six months.
The responsible personnel were unaware of the difference
Mr. Ronald C. Haynes, Director U.S. Nuclear Regulatory Commission 11/9/81 and believed Unit No. 2 to be similar to Unit No. 1.
When it was discovered that it was missed, the surveillance was performed immediately.
All personnel involved were counseled on the differences between the two units' requirements.
We feel that this step is sufficient to prevent further recurrence.
We are in full compliance now.
On June 2-4, 1981, the new surveillance test of Technical Speci-fication 4.3.3.7 had not been entered into the Inspection Order System.
When it was discovered that the surveillance was missed, it was performed immediately.
The surveillance was entered int9 the Inspection Order System and the personnel responsible were counseled on the importance of ensuring new or revised surveillance requirements are entered into the Inspection Order System for tracking.
We are in full compliance now.
In all of the above incidents, the operations personnel were unaware that there was equipment inoperable (as defined by the Technical Specifications} when they entered into an operational mode.
Item B Facility Operating License DPR-75 states, in Section 2.C(lO) (d),
"By July 31, 1981, PSE&G shall. ** (9) Wrap one of the redundant power cables from the diesel generators located in the fuel oil storage tank room."
Contrary to the above, when inspected on September 1, 1981, neither power feed to the diesel generators had been wrapped.
Reply To Item B On September 1, 1981, it was determined that a diesel generator power feed conduit had not been wrapped as required by July 31, 1981.
A fire watch was immediately established and maintained until the conduit wrapping was completed and signed off to work package specifications later in the day.
The cause of this non-compliance was that wrapping of this conduit in the diesel fuel oil storage tank room was inadvertently overlooked by contractor personnel and presumed completed by PSE&G personnel.
This event was reported in Licensee Event Report 50-311/81-85/0lT.
Previously, a temporary construction status board was referenced in determining and then reporting that the item was done on time.
A detail field check of the required work shown in the Design Change Package was not made against actual installation at the time of the* *completion report.
A detail field check would not have been done at this time by existing procedure because the
Mr. Ronald c. Haynes, Director U.S. Nuclear Regulatory Commission 11/9,/81 commitment item (Diesel Generator Power Cable} was part of a larger Design Change Package, which was not scheduled for com-pletion for several more weeks.
The detail field check would occur on completion of the entire Design Change Package.
On October 6, 1981, during a field inspection on a sampling basis to review the cable wrapping work, PSE&G engineering personnel discovered Penetration Canister 2-41 unprotected from potential fire damage.
This canister, located in the No. 2 Unit Electrical Penetration Area, Elevation 78', was to have been wrapped in accordance with Design Change Package 2EC-1145.
A fire watch was established within one hour and the canister properly protected by 1600 hours0.0185 days <br />0.444 hours <br />0.00265 weeks <br />6.088e-4 months <br /> on October 7, 1981.
The cause of this non-compliance was also personnel error in that this wrapping requirement was overlooked by contractor personnel.
This event was reported in Licensee Event Report 50-311/81-104/0lT.
Subsequently, a 100% field audit of those plant changes accomplished in accordance with our Safe Shutdown and Interaction Analysis for vital cable and cable tray fire wrapping and fire barrier installation was performed.
An audit team composed of PSE&G Engineering and PSE&G Quality Assurance personnel performed a plant walkdown to verify that all work was properly accomplished.
This walkdown identified additional areas where wrapping was not in conformance with requirements.
Fire watches were established within one hour and all required wrappings were subsequently properly accomplished.
The cause of these non-conformances is as follows:
The ends of two cables, each in a different area, were inadvertently omitted from the Design Change Package.
One cable was properly included in the Design Change Package but another cable, running parallel to and beneath it, was erroneously wrapped by contractor personnel.
They had assumed that the cable orientation was the same on both units when, in fact, it was not.
One tray was partially wrapped, but due to a field measuring error, was not wrapped to the extent required.
These events were reported in Licensee Event Report 50-311/81-104/0lT.
The 100% field audit has been completed on both units and no additional items at variance with design requirements have been found.
We are now in full compliance with our Safe Shutdown and Interaction Analysis.
Mr. Ronald C. Haynes, Director U.S. Nuclear Regulatory Commission 11/9:/81 As a result of the above events, action has been taken by PSE&G's Plant Betterment and Maintenance Contractor to improve their site organization and to obtain better objectivity by their Quality Control group.
Since a significant cause of the non-conformances appears to be a lack of detachment of QC personnel from work in progress, the following specific actions have been taken:
- 1.
The Contractor's Site QA Manager has instructed all Contractor QC personnel of the critical need for their acceptance to be 100% accurate, and has cautioned the QC personnel against too close an involvement with the work group.
- 2.
The Contractor field engineers have been instructed to provide work steps for verification by craft supervision specifically, rather than just the work group, in more instances than was prevalent in the cable wrapping work.
- 3.
The Contractor principal field engineer and/or the craft supervisor have been directed by the Contractor or Site QA Manager to participate personally in the*walkdown and turnback procedures.
This is a change from the past practice of the walkdown being monitored only by the turnback co-ordinator.
This will ensure that the walkdown is performed by personnel familiar with both the site and the job require-ments prior to officially reporting work completion to PSE&G.
- 4.
The Contractor's Maintenance Superintendent, with the assistance of the Site QC Supervisor, has instructed craft supervisors and craft foremen on the requirements of Con-tractor Work Package implementation.
These instructions clarify the requirements for obtaining engineering resolution to field generated questions.
This will better assure proper implementation of approved procedures.
It is believed that these actions will improve implementation of contractor work packages and assist in preventing recurrences of these types of non-conformances.
Additionally, a PSE&G Task Force was formed to review the con-tractor's work program and, more specifically, to investigate how work in the field is reported complete, and subsequently found to be incomplete.
The Task Force findings and recommendations are expected to b_e available for PSE&G management review and consider-ation by November 15, 1981.
By December 31, 1981, appropriate additional changes to PSE&G's Design Change Package implementation program will be identified along with a schedule for their accomplishment.
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Mr. Ronald c. Haynes, Director U.S. Nuclear Regulatory Commission 11/9/81 We have reviewed our design control and design verification procedures for adequacy, in light of the two cable sections omitted from the Design Change Package.
It was found that currently implemented procedures are adequate and that no *:
systematic design control problem exists.
In actuality the omitted cable sections were originally identified in design studies but inadvertently deleted from the Design Change Package during the verification process due to a communications problem.
Review of the verification process did show it to be effective in correcting design error.
Item c Technical Specification 4.1.3.1.l requires that the position of each full length rod shall be determined to be within the group demand limit by verifying the individual rod positions at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> except during time intervals when the Rod Position Deviation Monitor is inoperable, then verify the group positions at least once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
Technical Specification 4.0.2 extends the above interval by 25% to 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.
Contrary to the above, for the following listed 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> intervals, during which the Deviation Monitor was inoperable, no record could be identified to demonstrate that the required determination had been made:
Unit 1 September 10, 1981 0800 to 1600 Unit 1 September 2, 1981 1600 to 2400 Unit 2 August 29, 1981 1600 to 2400 Unit 2 September 1, 1981 0800 to 1600 Re12ly To Item c The operators overlooked the requirements for rod position veri-fication during the times when the Rod Position Deviation Monitor was inoperable.
A change was made to the Operations Directive Manual (Shift Routine) requiring rod positions be monitored every four hours and recorded into Log 3 regardless of operability of the Rod Position Deviation Monitor.
This new requirement will make 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> rod position readings routine and will prevent oversight when the alarm is inoperable.
We feel that this action is sufficient to prevent recurrence and we are now in compliance.
Mr. Ronald C. Haynes, Director U.S. Nuclear Regulatory Commission 11/9/81 We feel that when the forthcoming recommendations of the Task Force have been acted upon by PSE&G management, the necessary actions will have been taken to correct these items of non-compliance and to preclude their recurrence in the future.
Sincerely, CC Director, Office of Inspection and Enforcement Nuclear Regulatory Commission Washington, D.C.
20555
STATE OF NEW JERSEY SS:
COUNTY OF ESSEX COUNTY OF ESSEX FREDERICK W. SCHNEIDER, being duly sworn according to law deposes and says:
I am a V;ice President of Public Service Electric and Gas Company, and as such,.~ find the matteis set forth in our response dated November> 9, 19~81, to the NRC' s combined inspection report 50-272/81-23 and 50-311/81-21 are 'true to the best of my knowledge, information and belief.
Subscribed and sworn to before me.
this* *f day of
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- ti Notary Pu.bli:c* ~*
My Commission expires on */l-;?J!;L * :;;J * /9?r::