IR 05000443/1989003
| ML20247R589 | |
| Person / Time | |
|---|---|
| Site: | Seabrook  |
| Issue date: | 05/24/1989 |
| From: | Haverkamp D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20245E996 | List: |
| References | |
| 50-443-89-03, 50-443-89-3, IEIN-88-084, IEIN-88-097, IEIN-88-84, IEIN-88-97, NUDOCS 8906070263 | |
| Download: ML20247R589 (37) | |
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U. S. NUCLEAR REGULATORY COMMISSION Region I Report No.:
50-443/89-03 License No.:
!icensee:
Public Service Company of New Hampshire 1000 Elm Streat Manchester, New Hampshire 03105
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Facility:
Seabrook Station, Unit No. 1 Location:
Seabrook, New Hampshire Dates:
February 28 - April 24, 1989 Inspectors:
D. G. Ruscitto, Senior Resident Inspector D. A. Dempsey, Reactor Engineer
Approved By:
lb k b f/2//#4 Donalo R. Haverkamp, Chfef
' Date Reactor Projects Sectioh No. 3C Division of Reactor Projects Inspection Summary:
a.
Areas Inspected 1.
Routine inspection by the Senior Resident Inspector and a regional reactor engineer.
Areas of inspection included operational safety, licensee reportable events and station information reports, mainten-ance, surveillance, NRC Information Notices, previous items and followup issues.
2.
An inspection and evaluation was conducted of the NHY operational quality assurance program and (Jality verification activity.
b.
Results 1.
General Conclusions on Adequacy, Strengths and Weaknesses of Licensee
' Programs Licensee recognition that the operational quality assurance program implementation required upgrading was evidenced by establishment of an independent team to conduct an in-depth program review. Certain initiatives were taken in this report period to upgrade the perform-ante level of the Nuclear Quality Group (NQG) where weaknesses were identified both by the licensee and the NRC (Paragraph 6).
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H-Inspection Summary (Continued)-
Four incidents. highlighted a potential reduction in attention to detail in the conduct of routine plant operations.
Two involved failures to properly position and lock-'a valve to prevent potential boron dilution of the reactor coolant system. Another concerned the generation of a reactor trip signal when steam generator levels were allowed to drop to the trip setpoint while in wet layup. A fourth event involved the inadvertent opening of a pressurizer power oper-ated relief valve during I&C testing. While none of these incidents had significant safety impact, they may indicate a potential weakness in what has been to date, an excellent operating record. (Paragraphs 3.1,3.3).
NRC and licensee evaluation of an electric shock incident which occurred during the previous reporting period while conducting MOVATS testing of a service water valve revealed weaknesses in the areas of design drawings and electrical maintenance procedures (Paragraph 10.5).
A weakness was identified in the NHY program for reviewing and taking required corrective action for NRC Information Notices. The review of two specific notices by the NQG was instrumental in formulating corrective action for this problem (Paragraphs 5.6 and 9.1).
j A weakness was identified in the knowledge of station supervisors with respect to required reporting of safeguards events. This condi-tion lead to a delay in confirming the identity of a controlled sub-stance found on site and a subsequently late one-hour notification to the NRC. This incident also demonstrated the effectiveness of the ongoing NHY druc detection program (Paragraph 3.1).
It appears that additional resources are necessary to expedite the review and approval of station operations and surveillance procedure changes and revisions (Paragraph 10.4).
2.
Violations A non-cited violation of 10 CFR Part 50, Appendix B, Criterion IX was identified regarding implementation of the welding program.
This violation was identified during a licensee quality assurance audit (89-03-04, Paragraph 8.2).
A non-cited violation of 10 CFR Part 73.71 was identified in that a one-hour safeguards notification to the NRC was not made within the prescribed time frame.
The notification. concerned discovery of a controlled substance within the protected area. This failure to report within one hour resulted from conflicting interpretation of NRC regulations within the NHY organization.
This conflict was brought to the attention of the inspector by the licensee and, once resolved, the report was oromptly made (89-03-01, Paragraph 3.2).
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Inspection Summary (Continued)
A violation of the Seabrook "zero power" license (NPF-56) was iden-tified regarding the locking closed of certain valves to prevent boron dilution of the reactor coolant system. A Notice of Violation is issued (89-03-02, Paragraph 3.3).
A non-cited violation of the Seabrook Technical specifications was identified with respect to instrumentation overlap testing (89-03-03, Paragraph 5.2).
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TABLE OF CONTENTS Page i
1.
Persons Contacted...........................................
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2.
Summa ry of Facili ty and NRC Acti vi tie s.......................
2.1 Resident Inspector Activities..........................
l 2.2 Visiting Inspector and Management Activities...........
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2.3 Plant Status...........................................
3.
Operational Safety (IP 71707, IP 93702)*....................
3.1 Plant Inspection Tours................................
l 3.2 Operational and Security Events......................
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3.3 BoronDilutionFlowPathValvesFoundMispositioned....
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4.
Licensee Action on Previous Itm= (IP 92701,92702).........
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4.1 Open Item 88-06-01:
Non-Class IE Loads Connected to l
Class IE Sources....................................
4.2 Open Item 88-13-04:
Fire Protection Program Deficiencies.......................................
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4.3 Violation 88-13-02:
Failure to Meet Technical
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Specification Action Statement Requiremer.ts..........
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4.4 Violation 88-13-03:
Failure to Meet Reporting
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-Requirements.........................................
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4.5 10 CFR 21 Report 88-00-03: Qualification of Agastat 7000 Series Time Delay Relays................
i 4.6 Open Item 89-01-01:
Seismic Storage of Service Water Cooling Tower Pump...................................
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5.
Licensee Event Reports (IP 92700)...................
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5.1 LER 88-005: Non-Class IE Loads Connected to Class 1E Sources..............................................
i 5.2 LER 88-006:
Cold Overpressure Mitigation System i
Inadequate Surveillance..............................
l 5.3 LER 89-001: Control Room Ventilation Isolation Oue to
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Radiation Monitor Failure............................
l 5.4 LER 89-002: Storage of Cooling Tower Makeup Pump......
5.5 LER 89-003:
Control Room Ventilation Isolation Oue to j
Test Equipment Malfunction.......................
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5.6 LER 89-004:
Control Room Ventilation Isolation Oue to
Loss of Power During Main Generator Circuit Breaker Testing................
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Page 6.
Evaluation of Quality Verification Function (IP 35702, 35502)....................................................
6.1 Scope..................................................
6.2 Seabrook Operational Quality Assurance Program.........
6.3 Seabrook Organization..................................
6.4 Discussion.............................................
7.
Followup Issues (IP 92701)..................................
7.1 Control Building Air Handling System............
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7.2 Diesel Generator Fuel System...........................
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8.. Maintenance / Surveillance (IP 62703, IP 61726)...............
8.1 Solid State Protection System......
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8.2 Welding Program........................................
8.3 S e r v i c e Wa t e r Sy s t em...................................
8.4 Thread Engagement of Packing Gland Nuts and Bolts......
9.
NRC Information Noti ces (IP 92701)..........................
9.1 NRC Information Notice 88-84:
Defective Shaft Keys i n Limi torque Motor Ac tua to rs........................
9.2 NRC Information Notice 88-97:
Potentially Substandard Valve Replacement Parts..............................
10.
Station Information Reports (IP 93702)......................
10.1 SIR 88-019: Barton Differential Pressure Switch Calibration Tolerances...............................
10.2 SIR 88-067: Area Temperature Monitoring...............
10.3 SIR 88-074:
Failed Relay Driver Card in Emergency of Power Sequencer...............................
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10.4 SIR 88-091: Refueling Water Storage Tank Drainage to the Reactor Coolant System.......................
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10.5 SIR 89-005: Wiring and Procedural Deficiencies During Maintenance on Service Water Valve............
11. Management Meetings (IP 30702, IP 30703).................
Attachment A: AEOD Engineering Evaluation Report on Problems With Oils, Greases, Solvents and Other Chemical Materials..........................
- The NRC Inspection Manual Inspection Procedure (IP) that was used as inspection guidance is listed for each applicable report section.
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DETAILS 1.
Persons Contacted W. A. DiProfio, Assistant Station Manager
- T. C. Feigenbaum, Vice President, Engineering, Licensing and Quality Programs
- D.- E. Moody, Station Manager
- J. E. Peschel, Operational Programs Manager
- N. A. Pillsbury, Independent Review Team Manager
- G. S. Thomas, Vice President, Nuclear Production
J. M. Vargas, Manager of Engineering
J. J. Warnock, Nuclear Quality Manager
- Attended inspection status meeting conducted March 22, 1989
- Attended exit meeting conducted April 26, 1989 Interviews and discussions with other members of licensee and contractor management and with their staffs were also conducted relative to the inspection of items documented in this report.
2.
Summary of Facility and NRC Activities 2.1 Resident Inspector Activities One full time senior resident inspector was assigned to the site dur-ing the entire inspection period.
The inspection included eighteen hours of observation of licersee activities during backshift work periods and twelve hours du. * g deep backshift periods. Deep back-shift inspection was conducted from 4:30 a.m.
to 5:00 a.m.
on March 29, 1989, from 3:30 a.m.
to 5:00 a.m.
on April 12, 1989, and from 6:30 a.m. to 5:00 p.m. on April 24, 1989.
2.2 Visiting Inspector and Management Activities The NRC reactor projects section chief for the Seabrook plant visited the site on March 22 and April 26, 1989.
He held discussions with licensee senior managers and attended an inspection status meeting on quality verification activities and the exit meeting for this inspection.
l On March 27-31, 1989, two electrical specialists from NRC Region I
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conducted an inspection of previous inspection findings and other l
technical issues. The results of that inspection are described in NRC:RI Inspection Report 50-443/89-04.
On April 10-14, 1989, a reactor engineer from NRC Region I conducted an inspection of operational safety.
The results of that inspection are included in this reoort.
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2.3. Plant Status The plant remained in Mode 5, cold shutdown with primary temperature between 120-150 degrees F and primary pressure between 50-345 psig with a bubble in the pressurizer and one train of the residual heat removal system in operation. Major maintenance was conducted on the train
"A" emergency diesel generator and several service water valves.
3.
Operational Safety
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3.1. Plant Inspection Tours While touring the primary auxiliary building, the inspector noted a-temporary handrail made up of scaffolding components on the 37'-0" elevation. The scaffolding was apparently installed to temporarily substitute for the permanent handrail which had been partially removed.
Following notification by the inspector, the licensee initiated a work request (89WO739) to remove the temporary railing and restore the section which had been removed.
The inspector ver-ified that the temporary railing was added to the scaffolding /
temporary equipment status report.
While touring the boric acid tank (BAT) room on the 25'-0" elevation of the' primary auxiliary building, the inspector noted damaged armoured cable on the temperature element leads for both BATS. As a result of the inspector's observation, a request for engineering ser-vices (89-105) was initiated to determine the action required to pro-tect and support these cables which are subject to damage in their present configuration.
While touring the emergency core cooling system vault in the primary auxiliary building, the inspector noted that drain valve WLD-V263 did not have any identification that would allow determination of valve position.
This valve is of an unusual design in which a spring-return handle protrudes from a block-shaped valve body.
Following identification of this condition, an instructional label was fabri-cated to alert the operator that counter-clockwise rotation of the handle opens the valve and that it spring-returns to the closed position.
With respect to each of the above minor hardware deficiencies, no compromise of plant safety was identified.
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3.2. Operational and Security Events 3.2.1 March 14, 1989 - Rupture of Screen Wash System Piping Due to Water Hammer On March 14, 1989, while starting up the circulating water (CW) system, the Unit I screen wash (SCW) pump, 1-SCW-P-79 was started by an auxiliary operator (AO).
In order to wash the CW traveling water screens prior to CW pump start-up, the A0 opened isolation valve 1-SCW-V-12. Due to dif-ficulties in gaining access to the valve operator from its
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normal location, due to installation of temporary scaffold-ing, the A0 was unable to open the valve ' slowly enough while filling the downstream piping to prevent a water hammer in the line. The resulting hydraulic shock caused a rupture in the newly installed fiberglass SCW system piping in the CW pumphouse.
Piping support damage also occurred.
This system is not required for reactor safety and no per-sonnel injuries occurred. It is of NRC interest because of the use of fiberglass piping in other seismic buildings.
Lessons learned from this minor incident may be appropri-ately carried over onto the nuclear portion of the plant.
A station information report was initiated and may be the subject of further NRC inspection.
3.2.2 March 16, 1989 - Trip of Train "A" Diesel Generator During Post-Maintenance Testing While conducting post-maintenance testing of the Train "A" emergency diesel generator (EDG), a low lube oil pressure trip occurred.
The trip was attributed to a partial drain down of the lube oil header during maintenance. The header was refilled following the failed start and the subsequent restart was successful.
Because of two previous similar failures following extended outages, a monitoring program will be initiated to gather data during post maintenance outages which may be useful in formulating future corrective actions.
This event was evaluated for deportability in accordance with Seabrook Technical Specification 6.8.2.
A special report was sub-mitted to NRC by letter (NYN-89039) on April 17, 1989.
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3.2.3 March 21, 1989 - Inadvertent Actuation of Pressurizer Power Operated Relief Valve (PORV)
During testing of wide range reactor coolant system hot leg temperature instruments, an actuation of the
"A" PORV occurred. The control room operator immediately closed the valve manually from the main control board.
The surveil-lance procedure in use required the control switch for the PORV to be in the " closed" position. The technician per-forming the surveillance believed that since he had been authorized to commence the procedure by the on-shift con-trol room operator that the PORV control ~ switch had already been re positioned.
Station information report 89-013 was initiated to evaluate this incident.
No adverse impact occurred from the event due to swift operator reaction to the. valve actuation. This event is one example of several recent minor events that taken ir,dividually are of no safety impact but taken as a whole may indicate a declining trend in the attention being paid to detail in day to day plant operations, testing and maintenance.
3.2.4 March 21, 1989 - Automatic Trip of Circuit Breaker 11 and 163 and Control Room Ventilation Isolation A trip signal for 345 kV circuit breakers No.11 and No.163 occurred as a result of improperly planned testing.
This de-energized the unit auxi iiery transformer. As a result of this in plant power transient, a control room ventila-tion isolation signal was generated.
This engineered safety features actuation was reset and systems returned to normal without further prcblems.
Additional details of this incident may be found ira paragraph 5.6 of this report.
3.2.5 April 3, 1989 - Inadvertent Reactor Trip Signal A reactor trip signal (RTS) was generated when the level in the
"B" steam generator (SG) decreased below the "LO-LO" setpoint of 14 inches. Two separate instrumentation chan-nels are required to actuate to complete the 2/4 logic.
Level in the
"B" SG was low as a result of normal level decrease over time during extended Mode 5 operations. One level bistable was actuated with the SG in a steady state condition.
The operators were shifting the valve lineup to fill the "B" SG when the second bistable was actuated. The resultant RTS caused no equipment actuation because all reactor trip breakers were already open.
The appropriate
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alarm was received on the main control board. -The SG level was restored per procedure and a four hour non-emergency telephone report was made to the NRC Operations Center in accordance with 10 CFR Part 50.72. The. levels in all four SG.
id been low when the day shift took over that morning.
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It was recognized by the oncoming shift that all SGs needed refilling and that since the "B" SG was in a wet layup i
recirculation configuration that the potential existed for a level transient while shifting out of that lineup. The actual reason for allowing all SGs to decrease to near the trip setpoint will be addressed in - a station information report. Due to the plant configuration at the time and non-irradiated status of the core, this event had no safety implications.
3.2.6 April 7, 1989 - Charging System Valve CS-V625 Mispositioned Following a routine transfer from normal letdown to excess letdown, it was discovered that charging system motor oper-ated valve CS-V625 was not closed and de-energized as required by the Seabrook "zero power" license. More detail on this event may be found in paragraph 3.3 of this report.
3.2.7 April 7, 1989 - Controlled Substance Found Within f otected Area At about 11:00 p.m.,
on Friday, April 7,1989, a routine search of the plant was conducted with the drug detection canine.
The canine was accompanied by his handler (a NHY contractor) and a site security officer (a member of the contract guard' force). While inspecting the 21'-0" eleva-tion of the turbine building, the canine handler noted what appeared to be a marijuana cigarette wrapped in aluminum foil located in the steel of a pipe support. The canine handler noted a positive reaction from the canine when given the opportunity to monitor the substance. Based on this fact and the obvious appearance of the marijuana cig-arette, reasonable suspicion existed that a controlled sub-stance had been found. The discovery was reported by the site security officer to the NHY security shif t supervisor.
The supervisor failed to recognize that pursuant to 10 CFR Part 73.71, the actual or attempted introduction of con-traband into.a protected area must be reported to the NRC within one hour.
He did not understand that controlled
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substances fall within this category even though a threat to the site may not exist. He informed the Shift Superin-tendent (SS) of his interpretation that this was a logable rather than a reportable discovery The SS failed to make an independent verification of the security shift super-visor's interpretation.
It was not until the following Monday, April 10, 1989, that this issue was brought to the attention of upper level security supervision.
Guidance provided in NUREG 1304, " Reporting of Safeguards Events" indicates that the one-hour clock begins when there is reasonable suspicion that the material discoverd is a
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controlled substance.
Since the security shift supervisor was not able to perform the tests required to identify the substance, no tests were run until the morning of April 10,1989.
The inspector was informed of the discovery by the NHY Operations Manager on April 10, 1989, who indicated that a one-hour report had not yet been made since field testing was in progress.
NHY security supervisors at that time were undecided whether the report should have been made prior to the field test.
Following discussion with the inspector during which NUREG-1304 was used as a reference, it was determined that the event should be reported within one hour after reasonable suspicion exists that a con-trolled substance has been found.
By this time, the field test confirmed the substance to be marijuana and the one-hour report was made.
Other mitigating factors also exist. The discovery of the substance by the canine handler, confirmation by the drug canine, and the fact that backshift drug detection activ-ities at Seabrook are routine, are all evidence of an ef-fective drug detection program. The unfamiliarity with the contents of NUREG-1304 on the part of the security shift supervisor and the shift superintendent were the major con-tributors to this violation of NRC requirements. However, 10 CFR Part 2, Appendix C allows the exercise of enforce-ment discretion to supprt licensee initiatives for self-identification and correction of problems.
The NHY drug detection program at Seabrook, because of its effectiveness to date, is a candidate for such discretion based upon the following:
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(a) The licensee clearly. understood that this discovery may have been reportable and identified. this to the inspector.
In this case, however, the licensee did not correctly determine when the call should be made.
(b) The failure to ' report is of minor significance as was the discovery of a minimal amount of a controlled sub-stance.
It is clear from interviews with the on-shift security supervisor that had he noted an odor of smoke or discovered any individuals. in the area, he would have treated this discovery with a higher priority.
No significant threat to the plant was noted by the NHY staff nor did one actually exist.
(c) The discovery was reported within one hour of the-field test and failure to report is not, in and of itself, a reportable event.
(d) The licensee took corrective actions to. ensure that confusion over similar situations in the future does not occur. Additional training will be conducted with the appropriate staff and the NHY Reporting Manual will be updated to include requisite guidance to assist those individuals who must determine the deportability of such events.
(e) This violation could not reasonably have been pre-vented by corrective action from a previous violation.
As a result, no Notice of Violation is issued and no licensee response is required.
Thi s violation will be identified as non-cited violation number 89-03-01.
This item is considered closed.
3.2.8 A ril 17,1989 - Charging System Valve CS-V176 J
Mispositioned On April 17, 1989, a second incident occurred in which a valve required to be locked closed pursuant to the Seabrook license was found open and unlocked. Further discussion of this event may be found in Paragraph 3.3 of this report.
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3.2.9 April 18, 1989 - Loss of 345 kV Scobie Line During maintenance on the 345 kV SF6 bus duct in zone 3, gas pressure was lost causing a trip of 345 kV power cir-cuit breakers No. 163 and No. 632.
The loss of pressure trip signal was generated when workers began maintenance activities prior to completion of the tagging isolation.
Since both of.the other two 345 kV outside lines, Newington and Tewksbury, were available, no reduction in any plant performance parameter was affected.
Seabrook Technical Specifications require only one outside line to be operable in the current mode. While a station information report was initiated to conclusively identify root cause and correc-tive action, it appears that this incident is attributable to noncompliance with the station work control program.
-3.3. Boron Dilution Flowpath Valves Found Mispositioned 3.3.1 Background On April 7, 1989 and April 17, 1989, NHY identified two separate violations of license condition 2.C(11)c of the Seabrook "zero-power" license, NPF-56. This license condi-tion exists to ensure that boron dilution of the reactor coolant system (RCS) would be precluded by locking closed all valves in potential dilution paths. One of these paths is from the reactor coolant drain tank (RCDT) located inside containment to the excess letdown line.
When RCS pressure is less than 300 psig and excess letdown is not in service, air-operated valve (A0V) CS-V176 must be closed.
Additionally, the air supply valve for the CS-V176 oper-ator, CS-FY-7417-V4, which is a manual valve, must also be locked closed.
A second flowpath exists from the primary drain tank (PDT). in the waste process building to the nor-mal letdown line.
When normal letdown is secured, motor-operated valve CS-V625 must be closed and locked with the circuit breaker for its valve motor located on motor con-trol center (MCC) 631 locked open.
Operations procedure 0S86-1-7, "Unborated Water Source Locked Valve List" was written to provide instructions to verify that the required isolation valves from unborated water sources are closed, locked and chained.
Precaution 5.2.5 of OS86-1-7 requires that once the evolution is completed which required the value to be unlocked, the valve will be independently ver-ifed to be positioned to its required position.
All valves, circuit breakers and control switches associated with the locked valves are caution tagged including the CS-V625 and CS-V176 control switches on the main control board (MCB).
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3.3.2 Chronology-4:00 p.m. April 7, 1989 RCS pressure raised to 345 psig to establish condition necessary to balance seal injection flow and-perform maintenance.
5:54 p.m. April 7, 1989 Normal letdown removed from ser-vice per OS 1002.02.
Operator fails to observe cautions to close, de-energize and lock CS-V625.
Operators fail to conduct applicable portion of locked valve lineup per' 0S86-1-7.
CS-V625 remains open and indicates open and energized in spite of caution tag on main control board.
Mid-shift April 8, 1989 Daily lineup per OS86-1-7 per-formed. Discrepancies on CS-V625 and its 'oreaker on MCC-631 are not noted.
Mid-shift April 9, 1989 Daily lineup per 0S-86-1-7 per-formed.
Discrepancies on CS-V625 and its breaker on MCC-631 are not noted.
10:20 a.m. April 9,1989 Operator notes valve CS-V625 mis-positioned.
Valve is closed, de-energized and locked.
1:18 p.m. April 9, 1989 24-hour ENS call made regarding violation of license condition 2.C(11)c.
7:53 p.m. April 13, 1989 Normal letdown placed in service and excess letdown is shutdown.
Operator fails to observe caution tag on MCB regarding closure of air supply valve to CS-V176.
9:00 p.m. April 13, 1989 CS-V625 is unlocked and breaker on MCC-631 is closed.
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2:00 a.m. April 17,1989 A0 discovers instrument air supply valve CS-FY-7417-V4 to excess let-down. isolation valve CS-V176 open.
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The valve locking cover -was chained in place and locked but not fully covering valve hand-~
wheel CS-FY-7417-V4-is elosed and~relocked.
5:05 a.m. April 17, 1989 Completed valve ' lineup per 0586-1-7 which is independently verif--
ied by Shift-Superintendent.
This-check includes removal of ' valve
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locking devices per procedure to check actual valve positions. All valves are found to-be properly positioned.
9:20 a.m. April 17, 1989 24-hour ENS call-made regarding violation of licensee condition 2.C(11)c.
3.3.3 Description of Events On April 7,1989, RCS pressure was raised to 345 'psig to facilitate maintenance on the normal letdown flowpath.
RCS letdown was secured in accordance with operations procedure 0S1002.02, " Operation of Charging, Letdown and Seal Injec-tion" (Revision 07, Change 08).
Change No. I to 051002.02 had been initiated in October, 1988 to add a new Precaution (number 3.14) which included closing and locking CS-V625 and opening and lockisng its breaker at Node D62 on MCC-631 immediately after removing normal letdown from service.
Additionally, - a similar caution step was added prior to Step 6.7.1 which is the first step in the detailed proced-ure for removing letdown from service.
Given the precau-tion prior to entering the procedure, the caution prior to H
the first procedural step and the caution tag on the con-trol switch for CS-V625 on the MCB, adequate administrative controls appeared to exist to ensure compliance with 0586-1-7.
However, the operator failed to close CS-V625 once letdown was removed.
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As a further backup to the station operating procedures, OS86-1-7 mandates a daily surveillance of all of the valves on Form OS86-1-7A (Revision 3), the locked valve lineup.
An auxiliary operator ( AO) normally performs this lineup on the mid shift (11:00 p.m.
7:00 a.m.).
The A0 who per-
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formed this lineup on the mid-shift on April 8 and 9,1989, did not adequately carry out his responsibilities to verify the status of CS-V625 and its breaker on MCC-631.
An
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he merely verified that the caution tag was in place.
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Secondly, he did not verify valve position indication on CS-V625 locally; he only verified that the chain was in l
place.
Although numerous shift crews had assumed the watch in the control room after letdown was secured, none noted this discrepancy which should have been readily apparent on the MCB. As a result, the mispositioned breaker and valve were not discovered until the day shift on April 9,1989, when a control room operator realized that CS-V625 was still open by MCB indication. The valve was immediately closed and locked and the breaker on MCC-631 opened and locked.
An
emergency notification system (ENS) call was made to NRC Headquarters at 1:18 p.m.
on April 9, 1989, pursuant to License Condition 2.G which requires that violations of License Condition 2.C concerning boron dilution be reported within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Contributing factors to this incident include the following:
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Eight procedure changes vere attached to 051002.02,
" Operation of Letdown Charging and Seal Injection."
Each change is reflected in the main procedure with a vertical "sidebar" in the margin and a note indicating which change applies at that particular step.
With eight changes in effect, reference to the appropriate
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change is a cumbersome, time consuming activity which I
distracts the operator from concentrating on the task at hand and interrupts the mental focus required for complex system manipulations.
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The signature locations on Form OS86-1-7A do not positively indicate the required position of CS-V625 and its associated circuit breaker.
Rather, the
" Position Required" is indicated as, "When normal let-down is not in service this breaker must be locked j
open" (for CS-V625 circuit breaker) and "When normal
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letdown is not in service this valve must be chain-locked closed" (for valve CS-V625).
It is not clea-I what the. operators initials in the signature space adjacent to each of the above position lines actually signifies.
Lacking specific guidance from super-vision, the A0 must make some judgement regarding let-down status.
Additionally, lacking any notation by the A0 as to what his signature meant, a reviewing supervisor would not actually know what position the component is in.
In summary, the layout of the lineup
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sheet contributed to the confusion regarding component status.
Following the shutdown of normal letdown, the plant was placed on excess letdown in accordance with operations pro-cedure 0S1002.03, " Operation of Excess Letdown System" (Revision 02). On April 13, 1989, after work on the normal letdown flowpath was completed, the normal letdown lineup was restored and excess letdown secured.
Step 6.3.2. of OS1002.03 directs the operator to close CS-V176.
No cau-tion exists within the procedure to indicate that OS86-1-7 requires that whenever RCS pressure is less than 300 psig, the air supply valve to CS-V176 must be chain-locked l
closed. A caution tag on the control switch for CS-V176 on
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the' MCB does state the above requirement however.
The l
operator failed to perform this step and reduced pressure
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to approximately 150 psig. Since the CR0 was not aware of the OS86-1-7 requirement, no A0 was ever directed to iso-late air to CS-V176.
It is not clear how the locking device (a can-like arrangement chained over the air valve stem and handwheel) was restored but during routine daily surveillance on April 14-16, the mid-shif t A0 noted the device to be in place. In accordance with the provisions of OS86-1-7, once a valve has been positioned and locked, removal of the locking device is not required to verify valve position. Verification that the locking device is in place is sufficient. During the mid-shift surveillance on April 17,1989, the on-shift A0 noted that the locking device was loose enough to actually check the valve position and he did so, finding the valve open. The con-trol room was notified, the valve immediately closed and a complete walkdown of all valves was conducted to verify the
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L correct position. Those valves which may be repositioned
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per 0586-1-7 had th.
locking devices removed so that a physical inspection of valve position could be made.
No other discrepancies were found. This second discovery was reported to the NRC by ENS call at 9:20 a.m.
on April 17, 1989.
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A ' contributing factor to ' this second occurrence is that Form 0S86-1-7 specifies in the " Position" column for CS-V176 that, "When the RCS is pressurized to less than 300 psig, the air supply to this valve.' must be chain locked closed." What was intended is that CS-V176 be verified in the closed position and air be isolated to prevent inadver-tent valve motion since chain locking of an ADV is not possible. Therefore, two separate surveillance activities should be required similar to CS-V625 and its circuit breaker. A second factor involves the lack of any pre-caution steps in 051002.03 such as those found in change 01 to 051002.02.
3.3.4 Summary of Deficiencies (a) The CR0 failed to follow the precaution, caution and caution tag instructions to close CS-V625 leaving the valve open and energized with letdown out of service.
(b) The A0 failed to properly perform the daily surveil-lance and indicated that the valve was locked closed and the breaker was locked open when they were not.
(c) Numerous control room personnel on shift failed to notice that CS-V625 -indicated open in violation of 0S86-1-7.
(d) The 0586-1-7 lineup sheet complicated the communica-tion to the A0 of what valve position was required and hindered the SS/USS from knowing what the A0 was actually signing for.
(e) The CR0 failed to comply with the caution tag on CS-V176 and direct that air be isolated to the valve when RCS pressure was lowered below 300 psig.
(f) The locking device for CS-V7417-V4 was returned to its position without notification of supervisory person-nel, delaying discovery of is actual status.
(g) The valve lineup form does not provide the opportunity to verify the position of CS-V176 and CS-V7417-V4 separately.
(h) The valve lineup does not facilitate the positive identification of letdown and RCS status at the time of the lineup.
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3.3.5 Safety Implications In neither of the above instances was reactor safety com-promised. Although the controls specified in the license condition were not maintained, no actual flowpath was available for boron dilution because of other closed valves and a lack of hydraulic driving head. Of greater concern is the lack of effectiveness of the program to implement license condition requirements.
3.3.6 Corrective Action 3.3.6.1 Short Term Corrective Action Licensee actions taken immediately upon discovery of the two mispositioned valves is described in sub paragraph (3) above.
A special meeting of the Station On-site Review Committee (SORC) was held on April 18, 1989, to review changes to the affected procedures. The inspector attended this meeting.
The changes which were reviewed by the 50RC and approved by the Station Manager at the conclusion of the meeting included adding new cautionary steps to the excess letdown procedure, 051002.03 (Revision 02, Change 01), the letdown degasifier procedure 0S1002.04 (Revision 05, Change 02) and the letdown, charging and seal injection procedure 051002.03 (Revision 08, Change 01).
Additionally, the unborated water source locked valve list procedure 0586-1-7 (Revisions 04 and 05) was modified to include removal of the locking device on allowed valves to verify position on the daily surveillance and to specify under what conditions CS-V625, CS-V176, CS-V635 and CS-FY-7417-V4 may be excluded from the marning and sampling requirements.
(CS-V635 is a manual valve which is normally operated concurrently with CS-V625.
This valve was not found out of position during either incident).
0586-1-7 was further modified to instruct the operator issuing the valve lineup to determine-the plant conditions relevant to these valve positions and specify the required position on the valve lineup.
The valve lineup sheet was modified to include blank spaces for this assign-ment to be made. A separate sign-off space was made for each of the two valves associated with the excess letdown line (CS-V176 and CS-FY-7417-V4).
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3.3.6.2 Long Term Corrective Actions Licensee long term corrective actions will evolve from the root cause analysis which is being per-formed as part of the SIR process.
The licen-see's actions detailed in their Licensee Event Report will be reytewed in a
subsequent inspection.
3.3.7 Summary The implementation of the Seabrook program to maintain RCS boron concentration in accordance with the Seabrook Sta-tion, Unit 1, Facility Operating License, NPF-56 was inade-quate (Violation 89-03-02). This deficiency was evident on April 7 and April 17, 1989, when. CS-V625 and CS-V176, respectively, were found to be in noncompliance with special procedure 0586-1-7.
Licensee corrective action has been immediate and sensitiv-ity to the seriousness of license condition compliance is
apparent at all levels of management.
The problems with procedure changes is being addressed by a special task team. Additional licensee corrective actions will be the subject of continued NRC inspector revier and follow-up.
4.
Licensee Action on Previous Inspection Findings 4.1. (Closed) Open Item 88-06-01: Class IE Loads Connected to Class IE Sources 4.1.1 Background This technical issue was originally opened in NRC:RI Inspection Report (IR) 50-443/88-06 to resolve the safety status of the tachometer circuit for the turbinc-driven emergency feedwater (EFW) pump.
The NRC concern was expanded in IR 88-10 to include the program for design, identification and testing of non-Class IE loads powered from Class IE sources. A two part violation was identified in IR 88-13 concerning the failure to enter a Technical Specification (TS) action statement and failure to report l
the above to the NRC within the prescribed time frame. NHY
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responded to that Notice of Violation on January 5,1989,
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in letter NYN-89003.
The first licensee event report (LER l
88-005-00) concerning the EFW system was submitted on
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September 23, 1988, and was supplemented on January 5,1989,
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by 1ctter NYib800004 (LER 88-005-01). This LER was further supplemented on March 6, 1989, by 'etter NYN-89022 (LER 88-005-02).
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The inspector reviewed the relevant documents and analysis and found that no significant safety hazard had existed as a result of the licensee's failure to adquately test the affected circuit breakers.
Furthermore, licensee correc-tive actions taken to modify the Seabrook design as well as the breaker testing requirements address the issue of cur-rent design adequacy.
With respect to the tie breaker issue, adequate procedural controls now exist to ensure that the appropriate action statements are entered when the buses are tied together.
Based on the above, the inspector is satisfied that all outstanding concerns related to the IE/non-1E issue are resolved.
The following NRC open items are closed for inspection purposes:
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Open Item 88-06-01
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Violation 88-13-02 Violation 88-13-03
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Licensee Event Report 88-005 (including Supplements 01 and 02)
4.2. (Closed)' Open Item 88-13-04:
Fire Protection Program Deficiencies.
NRC:RI Inspection Report (IR) 50-443/88-13. described deficiencies identified in the fire protection (FP) program at Seabrook.
These deficiencies were highlighted by the excessive number of occurren es which properly warranted issuance of station information reports (SIR). Quality assurance (QA) %spection reports (QAIR) in September, l
1987. identified problems in conducting surveillance of fire dampers.
The December, 1987 Annual Fire Protection Audit identified other
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administrative weaknesses. A review of the above mentioned FP SIRS by NQG was reported by the NRC in the 88-13 IR to be cursory. A sta-tion staff review subsequent to the NQG review revealed programmatic compliance prob 1 cms existed.
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In August,1988 another required Fire Protection Audit was conducted.
NRC review of that audit and discussion with the audit supervisor indicates that none of the trends or indicators from the NRC IR, the FP SIRS or other NQG findings were taken into account in scoping the
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audit.
As a result the audit focused on administrative details and I
training and not on current problems or corrective action for past problems.
The audit team noted general compliance with the exception of training and-drills.
It is not clear that the NHY audit program determined whether quality surveillance or quality inspection activ-ities had been successful in verifying the adequacy of FP activities at Seabrook as is the purpose of the audit program. Furthermore, the
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Several outstanding NRC inspection items existed at the beginning of this inspection as summarized below:
(a) Open Item 88-06-01 remained open pending NRC review of final design changes and procedure changes (Refer-ence:
IR 88-10, paragraph 4.a.(3)).
(b) Violation 88-13-02 was issued for failure to take action in accordance with the applicable TS - Action Statement (Reference:
IR 88-13, paragraph 4.a.(2).
(b)).
(c) Violation 88-13-03 was issued for failure to report the' above violation pursuant to 10 CFR 50.73 (Refer-ence:
IR 88-13, paragraph 4.a.(2)(c)).
(d) Licensee Event Report 88-005 remained open pending submittal of a supplemental report (Reference:
IR 88-13, paragraph 5.c).
4.1.2 Discussion Licensee corrective actions regarding this issue are sum-marized below.
(a) Personnel involved in the failure to identify the tachometer problem promptly were provided additional training. The training included the requirements of 10 CFR 50.73 and the station information report (SIR)
process.
(b) A management memorandum was issued to all personnel which clarified circumstances under which SIR initia-tion is appropriate.
Emphasis was ;4 aced on timely evaluation of technical issues for deportability.
(c) In responding to the Notice of Violation issued with IR 88-13, the licensee was asked to address the poten-tial consequences of worst case failures of those non-Class IE circuits which required additional design-changes.
This review was presented to the NRC in NYN-89003 and expanded upon in LER 88-005-02.
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audit did not determine whether past deficiencies had been effec-tively addressed or whether current activities demonstrate a positt t trend overall. This weakness in the audit program is not isolated u l
the FP area.
NRC review of 1988 audits in the areas of maintenance, design control and conduct of operations have revealed a similar audit philosophy.
This issue is being addressed by the QA program review described in paragraph 6 of this report.
With respect to administration of the Seabrook FP program, improve-ment has been noted by the inspector.
Station staff has, through self-analysis, identifi2d areas where improvement was required and this corrective action appears to have resulted in improved perform-ance. A significant reduction in the number of technical requirement compliance deficiencies have been noted in the area of fire doors, fire watches, fire detection instrumentation and penetration fire seals. The improving trend in this area will be the subject of con-tinuing NRC review. More effective oversight by the audit and evalu-I ation section in this area is warranted. This item is closed.
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4.3. (Closed) Violation 88-13-02: Failure to Meet Technical Specification Action Statement. Refer to paragraph 4.1 of this report for closure of this item.
4.4. (Closed) Violation 88-13-03: Failure to Meet Reporting Requirerrentj.
Refer to paragraph 4.1 of this report for closure of this item.
4.6. (Closed) 10 CFR 21 Report 88-00-03:
Qualification of Agastat 7000 I
Series Time Delay Relays.
This open item consisted of four sub-l items, three of which were closed in NRC:RI Inspection Report 50-443/
89-01. The remaining sub-item involved NHY review of NRC Information Notice (IN) 87-66.
This IN 87-66 was issued in December, 1987 and
was entitled " Inappropriate Application of Commercial Grade Compo-
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nents."
It described problems identified with non-Class 1E Agastat 7000 series time delay relays being used in Class IE applications.
The discussion in IN 87-66 clearly described the differences between I
the Class 1E and non-Class IE relays.
I No reviews were conducted at Seabrook to determine whether this issue raised any problems in currently installed equipment.
The Seabrook review concentrated on procurement of the affected relays and deter-mined that no problems existed. Subsequently the issue was raised by
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the NRC inspector which lead to the replacement of several relays in
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November, 1988. The root cause of this oversight is similar to that
described in paragraph 9.1 of this report concerning NRC IN 88-84.
Licensee corrective actions taken as a result of these findings is also described in paragraph 9.1.
Licensee response to this issue was also reviewed by an NRC:RI electrical specialist.
Based upon this corrective action and the closure of the other three sub-items, open item 88-00-03 is closed.
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4.6. (0 pen). Unresolved. Item-89-01-01:
Seismic. Storage of Service Water-Cooling Tower pump.
The inspector' obtained l a preliminary copy of design coordination report (DCR) 87-0097L which was-initiated - in response to request for engineering services (RES) 87-0083.
The RES
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was written jn January 1987 to request a design change to provide for storage of the portal'1a cump hoses.. It; was not iuntil the seismic
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storage issue was raised by the NRC inspector 'that' DCR 87-0097 was L
modified to provide seistr c storage in addition'to the rack storage
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of the pump hoses.
A' contributing. factor to - this problem' is t' e wording of Technical-h Specification 3.7.5,
" Ultimate Heat: Sink."~
Dialogue between the.
licensee and the NRC Office of Nuclear Reactor Regulation (NRR) is ongoing in an effort to'specify what pump operational characteristics should be inc.luded in surveillance requirements and.to establish satisfactory allowed. outage times.
c Licensee activities in addressing corrective actions for this problem have been properly directed.
NRC determination of the circumstances surrounding. previous entries into Mode 4 sithout proper storage per T.S. 3.7.5 remains unresolved pending further inspection.
5.
Licensee Event Reports (LER)
5.1. LER 88-005: Non-Class IE Loads Connected to Class-1E Sources. Refer to paragraph 4.1 of this report for closure of this item.
L 5.2. LER 88-006:
Cold Overpressure Mitigation System Inadequate Surveil-l lance.
LER 88-006-00 was discussed in NRC:RI. ]nspection Report (IR)
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50-443/88-15. The 88-15 IR indicated that neither the LER= nor its associated station information report (SIR-88-071) expanded the scope of the problem to investigate possible similar problems with other surveillance procedures associated with. instrumentation.
At that time, the inspector met with I&C department staff and indi-cated that this area warranted further review before LER 88-006-00 could be closed. At about the same time NRC Information Notice (IN) 88-83 was issued describing similar problems at.other plants in the United States. As a result of these factors as well as prior recog-nitien within the I&C department that additional review was warran-ted,-a comprehensive licensee verification was -conducted of all I&C surveillance procedures related to Technical Specification require-ments. On March 7, 1989, NHY transmitted LER supplement 88-006-01 to the NRC by letter NYN-89024. This supplement described the discovery of an additional noncompliance which is associated with the quarterly-o
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u testing of) slave relays K-628A and : K-628B. - These - relays actuate'
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three containment isolation valves.in the containment air handling
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system.
These' valves. and their actuation circuitrr had - been ' pre-viously verified to be operable asoa result of another surveillance conducted on an 18-month interval so-that operability was never. inA question.. Although the licensee review was expedited by NRC inspec-tor questions, the issuance of Ilt 88-83 combined with internal NHY
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questionr1 concerning the adequacy of the corrective action for LER '
88-006-00 indicates that in the absence of NRC followup, this: second-
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problem would-have been* discovered. Therefore, even though a viola-
tion of Technical Specification 3.3.2 relative to the quarterly test-ing of the subject relays did occur, no notice of violation has been issued.
Mitigating circumstances authorized by 10 CFR 2 exist in that the violation was originally licensee identified, is of low severity level and was reported as required,- Additionally, correc-y tive action was prompt and comprehensive and the violation could not j
have been ' prevented by corrective action from a previous violation.
This issue.is a non-cited violation.and is' considered closed-(89-03-03).
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While' the final licensee review has not-been completed,- a followup-SIR will be written to document the review process. Should any addi-tional. procedural problems be identified,- reports will be made as required.
This LER and.its supplement are considered closed.-
5.3 LER 89-001:
Control Room Ventilation Isolation (CRVI) Due to Radia-tion Monitor Failure.
NRC Region I Inspection Report 50-443/89-01
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described the January 21, 1989; CRVI which occurred when RM-6506B in the east air intake failed. Licensee Event Report 89-001-00 was sub-mitted to the NRC by letter (NYN-890017) on February 21,-1989. The actuation was attributed to a. failure-of the detector. The inspector verified that the report submitted pursuant to 10 CFR 50.73 was accurate and timely.
5.4. LER 89-002:
Noncompliance With Technical Specification for Ultimate Heat Sink.
This licensee event report (LER) concerns storage of the cooling tower (CT) portable makeup pump.
This issue was first ad-dressed in NRC:RI Inspection Report 50-443/89-01.
The inspector reviewed the LER which was transmitted to the NRC by letter NYN-89021 on-March 6,1989.
Additional discussion of this issue may be found in paragraph 4.6.
The root cause of the non-conformance was identified to be an inade-quate surveillance procedure which checked pump functionality but not storage environment. The corrective actions listed failed to address
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how this deficiency would be corrected.
The LER did indicate that proper storage would ' be achieved prior to entry into Mode 4.
The inspector discussed the procedural deficiency with the. cognizant operations and engineering personnel who indicated that the surveil-L lance procedure was to be modified.
The inspector subsequently reviewed the draft procedure revision and noted that the changes were responsive to the identified problem.
5.5. LER 89-003:
Control Room Ventilation Isolation (CRVI) Due to Test Equipment Malfunction.
NRC:RI Inspection Report 50-443/89-01 de-scribed this CRVI which occurred on February 14, 1989. NHY reported this event by letter (NYN-89029) on March 16, 1989.
The inspector reviewed the submittal and verified that the requirements of 10 CFR 50.73 were met.
i 5.6. LER 89-004:
Control Room Ventilation 1 sedation Due to Loss of Power I
During Main Generator Circuit Breaker 'iestEng 5.6.1 Background The main generator ties into the 345 kV grid via the gener-ator circuit breaker (GCB) and the generator step up trans-former (GSU).
Two 345 kV power circuit breakers (PCB), No.
11 and No. 163 isolate the main-generr. tor output from the two main 345 kV switchyard buses. These PCBs are electric-
{
ally interlocked with the generator output breaker failure
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protection scheme. Normal power for all in plant busses is from the main generator upstream of the GSU via the two unit auxiliary transformers (UAT).
5.6.2 Event Descriptig On March 21, 1989, while conducting maintenance, the GCB was closed locally resulting in an automatic trip of PCB l
No. 11 and PCB No. 163. In plant busses with the exception
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of non safety related 13.8 kV Bus 2 transferred to the standby source which is the two reserve auxiliary trans-formers (RAT).
Bus 2 did not transfer and as a result remained de-energized until it was determined that no fault existed in the bus.
The bus was then re-energized.
The
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inspector responded to the control room and observed recovery operations.
Operator !'tions in restoring the plant were noted to be effective J carried out in accord-ance with procedures.
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At the time; of the power. loss, power panel ED-PP-1F - was
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being. powered from its maintenance supply: since inverter ED-I-1F was de-energized for. maintenance. The maintenance supply-was de-energized. momentarily during. the UAT/ RAT transfer. This. caused an actuation of the train
"B" con-
' trol. building air handling (CBA) system. east and west in-
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take radiation monitors. The.-resulting controlo room ven-
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tilation isolation (CRVI) occurred as- ~ designed with no -
anomalies. The CRVI was reset and the CBA. system was sub-sequently restored.to normal. operation.
Actuation of an
. engineered safety feature:(CRVI) is, reportable pursuant to..
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10 CFR Part 50.72-A non-emergency call to' the NRC Opera-
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tions Center was made in a timely fashion.
5.6.3 Event Analysis-
The cause of the event was determined to be a breaker fail-ure scheme: trip signal which was generated when the main generator circuit breaker was closed locally. for. testing.
Thef test personnel incorrectly believed thatf placing the:
generator breaker " local-remote" switch in the " local" position. would disable the turbine trip feature of the
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breaker. This was not the case since this._is not a design
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feature of this circuit breaker although it is a design feature of.other plant circuit breakers.
In-depth tech-nical support department investigation of the Bus 2 failure is underway as is the event evaluation process which was
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initiated by the Station Manager as 'part of the station information report (SIR) process.
I j-5.6.4 Inspection Licensee Event Report-(LER) 89-004-00 was made to the NRC by letter NYN-89041 on April 20, 1989.
The inspector reviewed the draft SIR, LER and Event Evaluation. He dis-cussed the event and investigative activities with the-cognizant technical support department engineers.
The inspector determined that licensee efforts are properly directed. Focus is on the root cause of the Bus 2 failure as well as other lessons learned from the event.
In the LER the root cause was attributed to the power fail-ure which is accurate.
A more complete analysis made by the licensee and reviewed by the inspector traces the origin of the power loss to inadequate test preparations.
Cognizant test personnel did not completely evaluate the r
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actual circuitry prior to the test to verify that the sys-tem would respond as they believed it would.
The results of the more complete analysis were not included in the LER.
The inspector noted in a meeting with cognizant licensee staff that future LERs should more fully discuss the' root cause.
6.
Inspection of Quality Verification Function 6.1. Scope
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In acc.ordance with the NRC Core Inspection Program for operational plants, an inspection was conducted of licensee quality verification activities.
The purpose of this-inspection was to assess the effec-tiveness of NHY quality assurance activities in identifying. technical issues and problems having safety significance.
The inspector held discussions with members of the station staff and the Nuclear Quality Group' (NQG).
These interviews were conducted at all levels of the organization including first level management and supervisors. Addi-tionally, the inspector conducted detailed technical reviews of Sea-brook station. information reports (SIR), -licensee event reports (LER), work requests (WR), design coordination reports (DCR), repet-
-itive task sheets (RTS), quality assurance surveillance reports (QASR), quality assurance inspection reports (QAIR) and quality assurance audit reports (QAAR). He observed work and test activities in the field including activities involving NQG oversight.
Recent NRC inspection reports were also reviewed for quality-related inspec-tion findings.
6.2. Seabrook Operational Quality Assurance Program The Seabrook Operational Quality Assurance Program (0QAP) was developed to implement the regulatory requirements of 10 CFR 50, Appendix B, " Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants."
The OQAP organization, description, policy ' and requirements are contained in the NHY OQAP Manual (NYQA).
The NQG veri'ies implementation of the OQAP through audits, surveil-
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lances, inspections and reviews of activities and records. In addi-tion to the NQG, other organizations also provide independent reviews of safety-related activities.
6.3, Seabrook Organization Many organizations at Seabrook are tasked with quality verification responsibilities. These groups are independent of first line super-vision in the production organization.
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6.3.1 Nuclear Quality' Group (NQG)
The NQG is composed of four sections and is headed by the Nuclear Quality Manager.
The Nuclear Quality Manager.
reports to the Vice President - Engineering, Licensing and Quality Programs (VP-ELQP).
6.3.2 Quality Control (QC)
l The QC Department Supervisor reports to the Nuclear Quality Manager.
Three lead inspectors report through the _ QC Inspection Supervisor to the QC Department Supervisor.
Lead QC inspectors are assigned in the technical (opera-tions, chemistry and health physics), mechanical and elec-trical/I&C disciplines. QC inspectors conduct independent inspections and tests of station activities. The QC func-tion at Seabrook is referred to as Level 1.
6.3.3 Quality Surveillance The Quality Surveillance Supervisor reports to the Nuclear.
Quality Manager.
Surveillance activities include observa-tions of plant activities, record reviews and equipment status verifications. -The quality surveillance function at Seabrook is referred to as Level 2.
6.3.4 Quality Audit and Evaluation The Quality Audit and Evaluation Supervisor reports to the Nuclear Quality Manager.
The audit program ensures that Level 1 and 2 quality activities are properly implemented.
Additionally, audit and evaluation activities ensure that the OQAP requirements, as implemented, satisfy regulatory requirements.
Certain audits required by the Seabrook Technical Specifications (TS) are conducted by this group under the cognizance of the Nuclear Safety Audit and Review Committee (NSARC).
The quality audit and evaluation pro-gram at Seabrook is referred to as Level 3.
6.3.5 Quality Assurance (QA)
The QA Supervisor reports to the Nuclear Quality Manager.
The QA engineers assigned to his staff conduct document reviews, train and qualify inspectors, coordinate the non-destructive examination (NDE)
program, administer the Approved Vendor List (AVL) and coordinate quality program assistance with the Yankee Nuclear Services Division (YNSD).
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6.3.6 Nuclear Safety Audit and Review Committee'(NSARC)
The NSARC Chairman reports directly to the NHY President and Chief Executive Officer. The NSARC provides indepEnd-ent review and audit of designated safety related activ-ities.
The NSARC is required by Seabrook Technical Spec-ifications.
6.3.7 Independent Safety Engineering Group (ISEG)
The ISEG Supervisor reports to the VP-ELQP. The ISEG main-tains surveillance of station activities to provide inde-pendent. verification that these activities are performed correctly and that human errors are reduced as much as practical. The ISEG is mandated by the Seabrook Technical Specifications.
6.3.8 Independent Review Team (IRT)
The IRT was established during - the Seabrook construction period to provide an independent assessment capability for corporate management on key issues.
The IRT Manager now reports to the VP-ELQP.
6.4. Discussion The inspector interviewed members of the Station Staff and the NQG concerning implementation of the OQAP.
There is a recognition at Seabrook at all levels of management that although the Operational Quality Assurance Program (0QAP) is meeting programmatic requirements several areas could be improved.
These areas include the quality of inspection, surveillance and audit find -
ings, interface between the NQG and station staff, technical credi-bility of NQG inspectors, review of plant events, and performance-based inspection.
NHY senior corporate management are committed to making long-term improvements in all these areas.
Several initia-tives as described below are in progress or planned in the near future. The most significant of these initiatives is an IRT review of the 0QAP implementation.
This review will focus on four major areas:
OQAP Content Clarity and Change Control
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Management Effectiveness
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OQAp Interfaces and Communications OQAP Implementation Effectiveness
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L The IRT has, in the past, conducted programmatic reviews at Seabrook with significant, positive impact.. Their findings are highly regarded by NHY corporate management and IRT recommendations are nor--
mally acted upon.
It is therefore anticipated.that this OQAP review will serve to-provide an overall status of quality verification activities at the site. Once this status is determined, it is expec-i ted that appropriate action will be implemented to enhance the program.
In addition to the IRT review, several other licensee initiatives are.
in progress.
Dialogue between the VP-ELQP and the Vice President-Nuclear Production QC holdpoints in the maintenance area is ongoing.
A significant commitment to improve technical credibility has been made by enrolling fourteen NQG personnel in the advanced phases of
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systems' training (refer to NRC:RI Inspection Report 50-443/89-01, paragraph 8.b).
Two individuals possessing senior reactor operator licenses at other nuclear plants have also been hired on a contract basis to enhance the capabilities of the operations QC group.
Fur-thermore, a series of training sessions on performance-based inspec-tion have been conducted for NQG personnel.
Increased training on the OQAP itself has-been conducted within the NQG.
It may be appropriate to expand this training to the station staff to enhance their understanding and. acceptance of the OQAP. A Findings Review Board (FRB) has been established to review NQG find-ings -for validity, accuracy, escalation, severity and safety impact.
This review will serve to provide feedback to NQG personnel that will allow improved quality and content of published inspection findings.
Additionally,- an increased level. of consistency among the four NQG sections will be possible.
These initiatives combined with any actions determined to be appropriate following the IRT review are expected to increase the effectiveness of the NQG.
With respect to the review functions of the NSARC and ISEG, the inspector notes a significant amount of duplication of effort between the groups. The volume of material to be reviewed by NSARC appears to be excessive.
Licensee management should investigate methods which would reduce the review burden on the NSARC while maintaining compl'snce with the Seabrook Technical Specifications.
As a result of this inspection, it is recommended' that the licensee conduct an independent investigation of the status of quality activ-ities at Seabrook, better define how the broad mandate of the OQAP is to be implemented and evaluate the working interface between the station staff and the nuclear quality group.
These observations and recommendations were presented to the VP-ELQP by the inspector in a meeting cn March 1,1989, and to NHY managers and supervisors in a meeting on March 22, 1989.
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7.
Followup Issues 7.1. Control Building Air Handling (CBA) System NRC:RI Inspection Report 50-443/88-17 described inspector concerns about the field configuration and design documents of the CBA makeup air. piping located in the Unit 2 diesel generator building.
In resolving this technical issue, NHY engineering initiated design co-
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ordination report (DCR)89-007. This design change involved cutting and capping both the CBA drain line and potable water fill and drain lines associated with this Unit 2 piping jumper. The piping drawings were also updated.
Inspector review of this DCR revealed a compre-hensive treatment of this issue.
The inspector conducted a walkdown of the changes in the Unit 2 diesel generator building.
He also verified that the piping pit cover had been restored, ensuring pro-tection of the CBA piping jumper.
Licensee actions have addressed all of the inspector's concerns.
7.2. Diesel Generator Fuel System Another' nuclear facility reported diesel generator fuel leakage at an injection nozzle flange which resulted from failed capscrews. The inspector provided the NHY technical support department with the fastener part number. NHY investigation of this issue revealed that the Seabrook diesel generators are not similar to those in question.
8.
Maintenance / Surveillance 8.1. Solid State Protection System (SSPS)
The inspector observed performance of operations surveillance proced-ure OX1456.43 "ESFA Slave Relay Quarterly Go Test (K601, K622, K624)
train "B".
He noted that the test was performed satisfactorily. One minor administrative deficiency was noted in that the forms refer-enced for recording data were actually the forms used
.'n the train
"A" test procedure. This occurred because when the procedures were originally written, the procedure for train "A" was writtei first and then " copied"'to produce the procedure for train "B".
The form num-bers were inadvertently omitted from the review of train-specific differences.
The correct data were taken during the witnessed test and entered appropriately.
This administrative error was corrected immediately with a procedure change and had no safety significance.
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The inspector also observed performance of operations surveillance I
procedure 0X1456.20, "ESFA Slave Relays Block Test - Train A."
Dur-ing performance of this test, it was noted that at step 8.9.5 two
. test lamps that should not have' illuminated when pressed illuminated
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at a low intensity.
The surveillance was-declared unsatisfactory and. troubleshooting was initiated by the I&C department.
.This
. troubleshooting revealed the existence of an uncontrolled jumper in
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"A" SSPS Output Relay Cabinet No.
1.
The jumper was removed following analysis that it was not necessary per design. A station information report was initiated and determined that the jumper only affected the test feature of the circuit and not the actuation of the devices involved.
Licensee followup to ensure that this is an iso-lated incident remains in progress.
8.2. Welding Program 8.2.1 Background Special processes at Seabrook Station are controlled in accordance with procedure MAS.1 of the Seabrook Station Maintenance Manual (SSMA).
Welding and nondestructive examination (NDE) are two of the special processes within the scope of the SSMA.
Procedure MAS.1 specifies that special processes are developed and qualified on an indi-vidual basis and are to be performed by qualified personnel.
Procedure MA5.2 of the SSMA describes welding and material control.
Specific instructions are provided for weld process control including the processing of weld travelers.
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Weld traveler information includes the welding process and materials to be used as well as a mechanism to ensure sign off by cognizant work control groups (i.e., ANI, QC, weld supervisor) at various stages of the weld process (e.g.
fit-up, preheat.
The Seabrook Station Special Process Procedure Reference (SPPR) contains the specific special process procedures for welding and NDE developed by NHY or develped by Yankee Atomic Electric Company (YAEC) and endorsed by NHY. The following SPPR procedures are listed below for reference:
YA-WP-IS " General Welder Performance Qualifications"
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YA-WP-SS " Gas Tungsten Arc Welding (GTAW)
and Shielded Metal Arc Welding (SMAW) of Carbon Steel (P1 to P-1) With an Open Root Weld"
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YA-WP-7S " Structural Welding Procedure"
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NHY-VE-1 " Visual Examination Procedure"
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Procedure YA-WP-75 applies to structural welding using SMAW.
Other weld processes including GTAW may be used provided a detailed specification sheet is supplied by the cognizant b
engineer.
8.2.2 Nuclear Quality Group (NQG) Audit Finding An audit of special processes (Report No. 89-A02-01) was conducted by the NHY quality assurance (QA) audit and eval-uation group in February,- 1989.
Finding No. F2 described two discrepancies related to the NHY welding program. One involved a welder performing a weld process for which he was not qualified.
The second involved a welder utilizing a process other than that specified on the weld traveller form. These discrepancies were determined to be violations of 10 CFR Part 50, Appendix B, Criterion IX (Control of Special Processes) by the audit team.
In the case of the welder not being qualified for the process in use, the weld traveller specified procedure YA-WP-SS. The welder was qualified to procedure YA-WP-7S.
Evaluation after the fact by the cognizant program support engineer revealed that the specification of the YA-WP-SS procedure for this specific weld was conservative and that procedure YA-WP-75 could have been selected as being appro-priate.
The SS procedure uses the same variables and NDE as the 7S procedure.
Furthermore the welded component in question was later abandoned because of an unrelated design change which eliminated the support in a
revised configuration.
Regarding the second problem involving use of the incorrect process, the weld traveller specified the GTAW process, however the welder used the SMAW process. Weld procedure YA-WP-55 allows either process, however the weld traveller is prepared for a specific process.
The welder was qual-ified for both processes and mistakenly believed that sub-stitution of processes was allowed by the procedure.
A review of previous welds made by this individual showed no other unauthorized substitutions, however, one work request did reveal that in several cases the GTAW process was used
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for the entire weld when a bi process weld traveler spec-ified that both GTAW and SMAW were to be used (e.g. GTAW at root pass and SMAW to finish weld).
These discrepancies appear to be isolated and attributed to a L single individ-ual. Additional training has been conducted with all pro-duction services department welders. Supervisors and field engineers have been instructed to closely monitor welding operations to ensure compliance with applicable instructions.
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NRC Assessment The audit finding described above was a result of good audit techniques in evaluating work in progress and follow-ing up on discrepancies noted. Corrective actions taken by the production services deoartment appear to address the relevant causes. Licensee internal response was determined to be appropriate for the negligible safety significance of the findings.
In accordance with 10 CFR Part 2, Appendix C,.a Notice of Violation is not being issued for this licensee-identified violation because of its minor nature, reasonable corrective action and isolated occurrence. There appears to be a concerted effort being made on the part of the NQG to focus their efforts on performance-based rather than compliance-based activities, The NHY NQG is encour-aged to continue utilizing this technique of evaluating work in progress as a part of the audit process.
This violation is identified as number 89-03-04 for record pur-poses only and is closed.
8.3. Service Water System While conducting a maintenance run of the train "B" emergency diesel generator (EDG), the service water (SW) supply valve, SW-V-18 failed to open upon demand. The EDG was then shutdown. Subsequent investi-gation revealed a sheared key between the air piston operator assem-bly and the valve stem shaft.
The key was sheared because the bush-ing which surrounds the valve shaft had become loose and dropped down sufficiently to expose the upper portion of the key to full thrust shear forces from the valve operator. The bushing is normally held in place vertically by a set screw which had backed out allowing disengagement between the stTft and the bushing. The set screw was most probably not properly sightened following the Belzona repair of SW system valves in 1987. To correct this current problem, the valve body was dropped down from the operator to allow access to the set screw. The set screw was tightened and then sealed with a locking compound.
Since the similar vaive in the train "A" SW system, SW-V-16 could also be susceptible to a similar failure, an examination was conducted.
It could be seen that some motion had already occurred
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L allowing partial disengagement of the key. As corrective action, a spacer was placed below the bushing so that in'the event that the set screw backs out, no vertical motion of the bushing is possible. This was done so that the condition could he corrected without removal of the valve from the system. The inspector discussed the repairs with the cognizant technical support engineers and concurs that either fix was technically adequate to preclude reoccurrence. The set screw for SW-V-16 will be tightened and sealed at the next available opportun-ity when either valve removal from the system or removal of the oper-ator from the valve is required. The evaluation of the failure in accordance with the station information report process will determine if maintenance procedure revisions are required. Additionally, other similar valve configurations in other systems will be evaluated for similar defects. The deportability of this failure per 10 CFR and Seabrook Technical Specifications is in under evaluation by NHY.
Licensee immediate corrective actions to restore operability were determined to be thorough - and comprehensive.
Followup activities will be the subject of possible future NRC review.
8.4. Thread Engagement of Packing Gland.Ntts and Bolts While touring the emergency feedwater (EFW) pumphouse, the inspector noted several small valves which exhibited what appeared to be inade-quate ' packing gland nut thread engagement.
The condition' observed was that in some cases no thread protruded past the top of the nut indicating less than full thread engagement.
As a result of the inspector's observations, the NHY Nuclear Quality Group (NQG) con-ducted a technical evaluation (89-002) of the issue. The evaluation team also included personnel from the engineering, maintenance and technical support departments. As a result, it was determined that although no specific criteria exists other than for ASME Class I components, full packing nut engagement is desirable.
Discussion with the valve manufacturer and engineering analysis indicated that a minimum of 2/3 of full engagement is the minimum which will be allowed at Seabrook. This is due to the fact that the greatest por-tion of the bolting stress is concentrated in the lowest few threads and that bolt stresses are very low compared to bolt strength. Since this attribute has been irregularly controlled in the past at Sea-brook, criteria is being developed for maintenance and procurement activities to ensure that minimum thread engagement is maintained.
It should be noted that of all the nuts found with less than full engagement, none was less than 2/3 engaged and no packing leakage was noted.
The additional training to be provided to maintenance and systems support personnel will enhance the maintenance pro
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Licensee activity on this issue was thorough and comprehensive -
judged to adequately address the inspector's original concern.
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NRC Information Notices 9.1. Information Notice 88-84:
Defective Shaft Keys'in Limitorque Motor Actuators. The inspector followed up on. NRC Information Notice (IN)
- 88-84 which was issued in October, 1988. The IN described possible problems from defective motor shaft keys installed in certain Limitorque actuators.
Licensee discussion directly with Limitorque indicated that. only those motor actuators supplied before 1983 as part of the motor pinion would be. suspect. NHY identified 19 poten-tially affected. valves.
Initial licensee investigation.of which operators were susceptible to problems was initially inadequate. Due
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to an error in '. interpreting correspondence between the -inventory department and the material requirements departments,.the IN was pre-
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maturely closed. Questions by both NRC and the NHY Nuclear Quality Group caused the item-to be re-opened and a subsequent NQG. surveil-lance (reference QASR 89-00128) of the ac civity revealed programmatic
. weakness in the dispositioning of NRC Information Notices.. Based upon - this and other similar incidents (refer to NRC open item 88-00-03, paragraph 5.6 of this report),.the operational. programs department has-undertaken a major review of the methodology used to evaluate. NRC ins at Seabrook.
This review will include program
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modifications to. improve verification of required actions and enhance the capability. to track ins through the NHY integrated commitment tracking system.
Licensee corrective actions in bringing this pro-gram back to an acceptable standard have-been timely and pro'perly -
focused. Actions taken.by the quality surveillance group in resol-ving this issue were initially slow, however, the review was thorough and is an example of the increasing value at Seabrook of independent evaluations of safety-related -issues. The review of NRC ins will. be the subject of continuing NRC inspection. Regarding the specific defects described in IN. 88-84, a complete re-evaluation is underway.
using the QASR findings as a guide. The applicable motor shaft keys will be replaced as a precautionary measure.
9.2. NRC Information Notice 88-97: Potentially Substandard Valve Replace-ment Parts NRC Information Notice (IN) 88-97 was issued in December, 1988 to inform licensees about reports concerning the manufacture and distribution of replacement parts for Masoneilan-Dresser Industries (M-D) valves that may not be genuine.
These parts, which are not manufactured by M-D, may be substandard. In response to IN 88-97 the NHY Nuclear Quality Group (NQG) conducted a surveillance of safety class home office and field purchase orders which were awarded to vendors who supplied valve replacement parts. A selected number of safety class purchase orders was reviewed with emphasis on M-D pur-chase orders.
The origin of replacement parts was traced in every case to the original valve manufacturer. As a result of this review, it appears that the possibility of receiving fraudulent replacement
- parts for valves at Seabrook is remote.
NHY investigation of this issue was prompt and the sample size appropriate to address the potential problem.
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l 10.
Station Information Reports The following station information reports were reviewed by the inspector and discussed with the cognizant licensee personnel in order to determine that an appropriate technical resolution of each problem was reached.
10.1.
Station Information Report 88-019: Barton Differential Pressure Switch Calibration Tolerances This station information report (SIR) was initiated in February, 1988 to resolve discrepancies involved with adjustment of the internal switch setpoints in Barton differential pressure (DP)
instruments.
Engineering Evaluation Number.88-007 was completed in March,1988 to justify the fact that the defect described in the SIR was not a reportable defect pursuant to 10 CFR Part 21.
At the time that the evaluation was written, the problem re-viewed concerned only to deficiencies related to a diesel gen-erator instrument (DAH-FISH-5530).
The evaluation portion of the SIR significantly expanded the scope of the issue and when.
approved in April,1989 over one year later described several different instrument issues one of which involved use of a Barton DP switch in the residual heat removal (RHR) system in a configuration outside of its accuracy zone for inservice testing (IST) of the RHR pump per ASME Section XI The inspector oues-tioned whether the original 10 CFR Part 21 evaluation was sull valid in light of the final SIR recommendations. The inspector discussed the technical issues involved with the cognizant tech-nical support and corporate engineers who described the process used to evaluate the more -recent findings concerning the accur-acy of the Barton instruments.
Although more accurate test guages will be used for IST of the RHR pumps in the future, the evaluation of previous test data including worst case accuracies and as-found calibration data did not reveal any pump perform-ance characteristics outside of tolerance. Therefore, a detailed 10 CFR Part 21 evaluation was not required.
10.2.
Station Information Report 88-067: Area Temperature Monitoring This station information report (SIR)
was initiated on August 18, 1988, when it was discovered that the temperature switch for the train
"B" electrical tunnel high temperature alarm was set improperly to alarm at 70.0 degrees F rather than 80.5 degrees F.
Since the setpoint was mistakenly set low, the alarm was actuated at a conservative room temperature.
NHY investigation of this SIR determined that this switch is similar
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in appearance to the installed room thermostats and it is theorized that plant staff mistakenly adjusted the switch believing' that they were adjusting room temperature. This has been a recurrent problem at Seabrook. As short term corrective action, the adjustment knobs are being ' removed from all alarm switches so that they may only be adjusted by authorized I&C department-personnel. Additionally, as a result of this review, a procedure was developed to calibrate the switches.
Local temperature indication is also available via permanently installed thermometers. The inspector discussed this event with
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I&C and_ operations department supervisors. The inspector noted that the control room operators verify compliance with Technical Specification 3.7.10, " Area Temperature Monitoring" by verifying the absence of an alarm condition.
If the reliability of a given temperature switch is in question or an alarm condition exists, actual room temperature is then verified locally. Since these temperature switches are not safety related, the alarm setpoints are conservatively set so that switch actuation occurs sufficiently below the technical ' specification setpoint even with the switch out of tolerance by the maximum design amount.
As -long term corrective action, a design change (DCR 87-370)
will replace the existing temperature switches with analog tem-perature transmitters that will input to the plant computer.
10.3.
Station Information Report 88-074:
Failed Relay Driver Card in Emergency Power Sequencer This station information report (SIR) was issued in January, 1989 to evaluate a problem with indicator lights on the main control board noted during surveillance testing of the emergency power _ sequencer (EPS). The problem was traced to a failed relay driver card. The investigation further revealed that this fail-ure would have prevented the starting of two train "B" contain-ment air handling (CAH) system fans in a loss of power (LOP)
situation. The acceptance criteria for operations surveillance procedure OXI426.03, " Emergency Power Sequencer Operability Test" requires satisfactory reviews of the computer record of sequencer operation to verify proper timing intervals. The com-puter inputs are driven separately from the light indication and outgoing control signal.
It was therefore only through the alertness of the operator on shif t that this failure was detec-ted, since another surveillance procedure is used to verify the operability of the relay driver cards.
The failed relay driver card was replaced.
Additionally, changes will be made to 0X1426.03 to identify expected light indications.
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10.4.
Station Information Report 88-091: Refueling Water Storage' Tank (RWST) Drainage to the Reactor Coolant System (RCS)
NRC:RI Inspection Report (IR) 50-443/88-15 described NRC con-cerns with corrective action for several similar RWST/RCS sluice events. As a result of these concerns, NHY formed a task team in February, 1989 to conduct an in-depth evaluation of the three events, review procedures and flowpaths and conduct a root cause L
analysis. The inspector reviewed the Task Team Evaluation. The l
team consisted of members of the Independent Safety Engineering l
Group, Nuclear Quality Group, technical support and engineering l
departments. The team concluded that. operator followup actions l
were correct and that the safety significance of the event was minimal. The engineering evaluation (89-010) determined that no hardware changes were appropriate per design and that although the system is subject to operator error, the consequences of
.such an error are not major and do not warrant a design change.
The root cause analysis pointed out several contributing fac-tors, the most significant. of which was the failure to incor-porate all the temporary changes into the newest revision of surveillance procedure 0X1456.70.
This was the procedure in progress when the sluice occurred. One of thet omitted ;.banges (No.10) contained a caution which, if followed, woula have pre-cluded this event. Past performance of this and other surveil-lance procedures had avoided similar incidents through operator awareness that strict compliance with-the procedure could cause sluice events.
A second notable firding was that SIR 88-091 inadequately identified all remaining procedures which could cause a similar event.
This revelation confirms prior NRC inspector observations that some SIRS do not fully evaluate all potential causes and corrective actions (reference NRC:RI IR 50-443/89-01).
The recommendations made by the task team may require signifi-cant in-house review by NHY of both operating and surveillance proceduras. It appears that operations department resources in this area are presently inadequate. A single staff engineer is responsible for procedure changes.
Additional resources are sometimes drawn from off-shif t operators.
This event and the procedure-related deficiencies described in paragraph 3.3 of this report indicate that further management commitment of resources to this effort would be prudent. With respect to the overall evaluation, it appears that the original SIR 88-091 was incomplete. The followup task team evaluation was responsive to NRC concerns and has adequately scoped the corrective actions required to solve this problem.
An additional ccomitment of resources is now required to implement the team's recommenda-tions.
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St' tion Information Report 89-005:
Wiring and Procedural 10.5.
a Deficiencies During Maintenance on Service Water Valve NRC:RI Inspection Report 50-443/89-01 described a minor electric shock incident related to the determinating of wiring on service water-valve SW-V-25.
The event occurred on February 6, 1989.
Station information report (SIR)89-005 was issued on March 20, 1989.
The inspector reviewed the SIR and held dis-cussions with the cognizant electrical engineers from the tech-nical support department. Items discussed included the SIR con-clusions which indicated that an improper wiring configuration existed whereby both leads were terminated on the same post of the sliding link.
This was most likely a construction error.
Secondly, the technician involved failed to check for potential voltage following the tagout as required by procedure and good
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working practices.
The < technician involved was instructed in the proper work requirements.
This SIR was reviewed with all station personnel who work on electrical equipment. As a result of a technical support department review of potential similar configurations, it was identified that while no other specific-similar situations have been found, certain station electrical terminal boxes may be susceptible to this type of error. This portential exists because of a lack of specificity in identify-ing upper and lower sliding link terminal connections on design drawings with no vendor " field interface.
All such conditions will be identified-oy May 1,1989, and any required rework will be completed by October 1,.1989.
Following the above discuss-ions, the inspector conducted a field walkdown of this and other similar electrical devices with no discrepancies noted.
A visiting electrical specialist from NRC:RI participated in the discussions and walkdowns.
Licensee response to this incident with potentially serious personnel and equipment hazards was adequate.
11. Management Meetings At periodic intervals during the course of this inspection, meetirgs were held with plant management to discuss the scope and findings of this inspection. The inspector discussed the results of his inspection of NHY quality verification activities with the Vice President - Engineering, Licensing and Quality Programs on February 1,1989, and with NHY managers and supervisors on March 22, 1989.
An exit meeting was conducted on April 26, 1989, to discuss the overall inspection findings during the period.
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During this inspection, the NRC inspector received no comments from the licensee that any of his inspection items or issues contained proprietary i
information.
The inspector provided the NRC coordinator from NHY with a
' copy of an' engineering evaluation report prepared by the NRC Office for Analysis and Evaluation of Operational Data. The evaluation is entitled
" Problems with Oils, Greases, Solvents and Other Chemical Materials" and is attached to this inspection report.
No other' written material was provided to the licensee during this inspection.
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