IR 05000341/1986016
| ML20198K747 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 05/14/1986 |
| From: | Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20198K728 | List: |
| References | |
| 50-341-86-16, NUDOCS 8606040123 | |
| Download: ML20198K747 (15) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-341/86016(DRP)
Docket No. 50-341 License No. NPF-43 Licensee: Detroit Edison Company 2000 Second Avenue Detroit, MI 48226 Facility Name:
Fermi 2 Inspection At:
Fermi Site, Newport, MI Inspection Conducted: March 1 through April 30, 1986 Inspectors:
W. G. Rogers M. E. Parker P. M. Byron JGLdA N/
h Approved By:
G. C. Wrigh, Chief Reactor Projects Section 2C Date Inspection Sunnary Inspection on March 1 through April 30, 1986 (Report No. 50-341/86016(DRP))
Areas Inspected: Routine, unannounced inspection by resident inspectors of licensee action on violations, licensee action of inspector identified items, regional requests, independent inspection, operational safety, maintenance, surveillance, design changes, report review, followup of events, management meetings and information meeting with local officials.
Results: No violations or deviations were identified. One open item was identified (Paragraph 8).
8606040123 860516 gDR ADOCK 05000341 PDR j
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DETAILS 1.
Persons Contacted
- F. Agosti, Vice President, Nuclear Operations-S. Booker, Assistant Maintenance Engineer
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L. Bregni, Compliance Engineer
- J. Conen, Licensing Engineer J. DuBay, Director, Computer Service & Information Systems R. Eberhardt, Rad-Chem Engineer J. Leman, Superintendent, Maintenance and Modification Engineer L. Lessor, Consultant to the Assistant Manager, Nuclear Production
- R. Lenart, Assistant Manager, Nuclear Production R. Mays, Outage Management Engineer
- W. Miller, Supervisor, Operational Assurance
- S. Noetzel, Assistant Manager, Nuclear Engineering J. Nyquist, Supervisor, Independent Safety Engineering Group T. O'Keefe, Technical Engineer
- G. Overbeck, Assistant Plant Superintendent, Startup J. Plona, Technical Engineer E. Preston, Operations Engineer W. Ripley, Assistant Operations Engineer - Administrative
- G. Trahey, Director, Quality Assurance
- R. Wooley, Acting Supervisor, Licensing
- Denotes those who attended the exit meetings.
The inspectors also interviewed others of the licensee's staff during this inspection.
2.
Followup on Violations (92702)
a.
(Closed) Violation (341/85042-02):
The licensee failed to submit reports for many LERs within 30 days.
The inspectors reviewed the licensee's corrective action and found it satisfactory.
The inspectors have reviewed licensee LER report submittals and observed that all have met the requirements of 10 CFR 50.73(a)(1).
This itera is closed.
b.
(Closed) Violation (341/86003-02):
Shift crew failed to follow Procedure 21.000.01, "Shif t Operations and Control Room," in that for two shift turnovers and intervening shifts, they failed to detect or recognize that the Active Seismic Monitor was in an off-normal condition as indicated by the presence of a lighted control room annunciator. As noted in Inspection Report No. 50-341/86003, once brought to the licensee's attention, the licensee determined that the system had not been reset and subsequently verified operability of the monitor and reset the monitor which in turn cleared the annunciator.
The licensee has since taken action with the licensed operators involved with this
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alarmed condition.
The surveillance procedure for the Active Seismic Monitoring System has been revised to include a step to verify that the annunciator alarm is clear upon completion of the surveillance test.
Action has also been taken through a standing order, required reading and shift briefing to ensure timely responses to all control room alarms.
The standing order requires, in addition to the control room operator, that patrol NS0's and non-licensed operators know the status of the control room alarms for their assigned areas and bring to the attention of the control room operator any problems identified.
This item is closed.
3.
Followup on Inspector Identified Items (92701)
a.
(Closed) Open Item (341/85048-02(DRP)):
During a routine tour of the control room, the inspector found the Division II RHR recirculation valve in the open position.
P0M Procedure 23.205,
" Residual Heat Removal System," requires this valve to be in the closed position while in the standby mode.
In Inspection Report No. 50-341/85048, the inspectors identified that in addition to the operator error, the system operating procedure was in error.
Upon identification of the problem the Operations Engineer took action to initiate a procedure change and ensure operators were made aware of the valve logic.
The licensee has since revised the system operating procedure and the Training Synopsis to reflect the correct valve logic.
To ensure ell operators were made aware of this problem it was identified as aart of the licensed operator requalification program.
The liceni.e has completed all proposed corrective action.
This item is closed.
4.
Followup on Regional Requests (927058)
a.
Possible Generic Problem with Failure of Squibb Valves The inspectors followed up on a possible generic problem that occurred at the Vermont Yankee plant in which a squibb valve supplied by Conax Corporation failed to fire.
This was determined to be an internal wiring problem with the squibb valves associated with a particular batch number.
Squibb valves within the same batch were found to have different pin-to-bridgewire groupings of 1 and 4, and 2 and 3.
i The licensee has reviewed this concern with the General Electric Corporation and against plant drawings and determined that this is i
l not applicable to the current batch of squibb valves procured by
Fermi.
In addition the inspectors followed the squibb valve firing associated with surveillance testing.
Upon completion of this test,
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the licensee replaced the fired squibb valve with one of five replacement squibbs of the same batch number.
The squibb valves have a shelf life of five years which expires on the fourth quarter of 1989.
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b.
Use of Licensed Reactor Operators in Supervisory Positions The inspectors reviewed the use of licensed reactor operators as control room supervisors at the Fermi facility. This was due to the concern that another power reactor facility was not meeting the requirements of 10 CFR 50.54(m)(2)iii, lu CFR 55.4(d) and 10 CFR 55.4(e) in that the Supervising Control Operator (SCO) was not a licensed SR0 and directing the activities of other licensed R0s.
The inspectors reviewed the licensee's administrative procedure POM 21.000.01, " Shift Operations and Control Room," which describes the administrative controls and guidelines for shift operations.
The inspectors also reviewed the Safety Evaluation Report and supplements, Technical Specifications, and 10 CFR. The inspectors have determined that the licensee is meeting its commitments as described in these documents.
c.
Potential Bearing Problems with Standby Liquid Control System (SBLC)
Pumps Regional management requested the inspectors to determine whether the same type of lubrication grease was used on the bearings of the standby liquid control system pumps as was being used at the Perry Nuclear Power Station.
On March 24, 1986, NRC was notified that the grease being used at Perry contained sulfides which had caused the potential for long term degradation of bearings through pitting.
The inspector determined that the same grease was not in use on the SBLC pumps at Fermi 2.
No violations or deviations were identified in this area.
5.
Followup of Events (93702)
During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72.
The inspectors pursued the events onsite with licensee and/or other NRC officials.
In each case, the inspectors verified that the notification was correct and timely, if appropriate, that the licensee was taking prompt and appropriate actions, that activities were conducted within regulatory requirements and that corrective actions would prevent future recurrence. The specific events are as follows:
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March 11, 1986 - Isolation of ReTctor Water Cleanup System on Area High Temperature due to personnel error.
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March 16, 1986 - Failure of Division I Backup Manual Scram Breaker to trip.
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March 21,1986 - Initiation of Division II EECW/EESW due to failure of the Digital Load Sequencer to reset.
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e April 4, 1986 - Trip of Division I CCHVAC Makeup Radiation Monitor
during surveillance testing.
April 10, 1986 - Isolation of Torus Water Management System due to
false Hi Hi drywell floor drain sump level during surveillance testing.
April 11, 1986 - Failure of Division I Standby Gas Treatment system
to auto start.
The resident inspectors and Region III security inspectors followed up on several security events during this inspection period.
No violations or deviations were identified in this area.
6.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable logs and conducted discussions with control room operators during the months of March and April 1986.
The inspectors verified the operability of selected emergency systems, reviewed tagout records and verified proper return to service of affected components.
Tours of the reactor building and turbine building were conducted to observe plant equipment conditions, including potential fire hazards, fluid leaks, and excessive vibrations and to verify that maintenance requests had been initiated for equipment in need of maintenance.
The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan.
The inspectors observed plant housekeeping / cleanliness conditions and verified implementation of radiation protection controls.
During the inspection, the inspectors walked down the accessible portions of the Low Pressure Coolant Injection system to verify operability by comparing system lineup with plant drawings, as-built configuration or present valve lineup lists; observing equipment conditions that could degrade performance; and verified that instrumentation was properly valved, functioning, and calibrated.
On March 22, 1986, the inspector observed the licensee resetting a reactor scram during RPS testing. While in the process of draining the scram discharge volume, a torus water management system isolation was received due to Hi Hi torus sump level.
This isolation automatically closes the Group 12 containment isolation valves.
The scram discharge volume drains into the torus sump.
The licensee has since received other torus water management system isolations due to Hi Hi torus sump level while resetting reactor scrams.
The licensee is investigating and reviewing the circumstances of these isolations and currently believes this to be a normal occurrence on resetting of a reactor scram.
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inspector has asked the licensee to review these isolations further since a containment isolation is not considered a normal consequence of resetting a reactor scram.
The inspectors also witnessed portions of the radioactive waste system controls associated with radwaste shipments and barreling.
During a plant tour the inspector noticed two coats hung on a reactor protection system instrument rack.
The situation was identified to operations management.
The coats were removed and the licensee indicated that personnel would be informed of this unsatisfactory practice through the monthly maintenance newsletter.
These reviews and observations were conducted to verify that facility operations were in conformance with the requirements established under technical specifications, 10 CFR, and administrative procedures.
No violations or deviations were identified in this area.
7.
Monthly Maintenance Observation (62703)
Station maintenance activities of safety-related systems and components listed below were observed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with technical specifications.
The following items were considered during this review:
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conditions for operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemented.
Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performance.
The following naintenance activities were observed:
Standby Liquid Control Squibb Valve Replacement
Divisions I and II Backup Manual Scram Breaker Replacement
Preparations for Neutron Source Replacement
Following completion of maintenance on the squibb valves and the scram breakers, the inspectors verified that these systems had been returned to service properly.
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No violations or deviations were identified in this area.
8.
Monthly Surveillance Observation (61726)
Tha inspectors observed surveillance testing required by technical specifications and verified that:
testing was performed in accordance with adequate procedures, test instrumentation was calibrated, limiting ccaditions for operation were met, removal and restoration of the affected components were accomplished, test results conformed with technical specifications and procedure requirements and were reviewed by personnel other than the individual directing the test, and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The inspectors also witnessed portions of the following test activities:
LPCI and Torus Cooling / Spray Pump & Valve Operability Test
Standby Liquid Control Manual Initiation and Storage Tank Heater
Operability Test.
Division I and Division II Electrical Protection Assembly (EPA)
Breaker Testing.
Divisions I and II RPS Backup Manual Scram Breaker Testing.
- Secondary Containment Isolation Damper Operability Test.
- The Standby Liquid Control System test consisted of pumping demineralized water from the storage tank through the "B" pump and squibb valve to the reactor vessel.
The "A" squibb valve was electrically disconnected because only one valve is required to be tested every 18 months.
During the test proper actuation of the squibb valve and indication of injection into the vessel was verified.
One item of concern to the inspector was the lack of indication on the testable check valve C41-F007.
The c*pck valve disk position indicator did not indicate "open" during the injection.
This concern had been previously identified and resolved during preopera-tional testing.
The inspectors have observed similar problems with this type of testable check valves as addressed in Inspection Reports No. 50-341/84007, No. 50-341/84040, and No. 50-341/85013.
This is an Open Item (341/86016-01(DRP)) pending resolution of the testable check valve disk limit switch.
No violations or deviations were identified in this area.
9.
Design, Design Changes, and Modifications (37700)
The inspectors reviewed a design change and modification that was determined by the licensee to not require approval by the NRC to verify that it was in conformance with regulatory requirements.
The following items were considered during the review:
the change had been
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reviewed and approved in accordance with 10 CFR 50.59 and was technically adequate; it was reviewed and approved in accordance with Technical Specifications and established QA/QC controls; it was controlled by established procedures; activities were conducted in accordance with appropriate specifications, drawings, and other requirements; testing-of the modification was conducted in accordance with technically adequate and approved procedures; and appropriate controls were implemented during installation of the modification.
The following design change and modification was reviewed:
Backup Manual Scram Breaker Replacement for Division I and
Division II.
On March 16, 1986, when transferring RPS Bus A from the primary power source to the alternate power source due to voltage fluctuations, the licensee observed that the Division I Backup Manual Scram Breaker did i;.at trip as expected.
The breaker by design will trip on undervoltage.
The unit was in cold shutdown at the time.
Upon a local manual attempt to trip the breaker, it responded in about ten seconds.
Upon the next attempt, the breaker failed to trip.
Per discussions with the inspectors and Region III, the licensee agreed to quarantine the failed breaker pending the development of mutually agreed troubleshooting.
Subsequently, the licensee agreed to conduct a laboratory failure analysis of the failed breaker.
The inspectors have observed and reviewed the licensee's Engineering
' Design Package (EDP), safety evaluations and procurement document for removal and replacement of the breaker assembly.
The licensee has procured a similar commercial quality replacement breaker and performed qualification testing per the licensee's commercial quality program.
However, the inspectors concluded that the original safety evaluation was weak in its summary justifying the breaker replacement as "like for like." The licensee subsequently provided an appropriate summary.
The inspectors have observed portions of the drop out testing installation and subsequent surveillance testing.
Region III and I&E Vendor Branch are following up on the laboratory failure analysis of the old breaker and will provide an inspector to observe and review the licensee's testing program to determine the failure mechanism.
Subsequent to the close of the inspection period an inspector from the I&E Vendor Branch did observe testing of the failed breaker and reviewed test data on the newly installed breakers.
No violations or deviations were identified in this area.
10.
Independent Inspection (92706)
Reactor Operations Improvement Plan The inspectors reviewed the licensee's Reactor Operations Improvement Plan (ROIP) which was described in correspondence to the Regional
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Administrator dated October 10, 1985, November 27, 1985, and January 29, 1986. The licensee determined that three root causes were to be addressed by the ROIP. The licensee selected six broad corrective action areas as identified in sections III and IV of the ROIP. The inspection consisted of a review of those six areas and the management overview of the corrective actions as identified in sections V and VI of the ROIP.
The inspectors reviewed a number of the specific commitments associated with these eight areas. The reviews performed were not to provide total verification of committed actions but to provide a high confidence level on the status of the committed actions.
The inspection consisted of personal observation; interviews with production, administrative services and quality assurance personnel; and a record review of implementation documents and quality assurance surveillances. The inspection results are presented below under the applicable area.
a.
Increase Management Support and Operating Staff Effectiveness in Control Room (1) Simulator training has been modified to focus upon normal plant operations (emphasize log entries, marking charts, i.e., good control room practices).
(2) Plant Manager or Superintendent-Operations, did have one-on-one meetings with the Nuclear Shift Supervisors (NSS), Nuclear Assistant Shift Supervisors (NASS), and Shift Operating Advisors (SOA) to review and emphasize responsibilities and authorities.
(3) To improve the quality of the control room logs, entries into the Nuclear Supervising Operator's (NS0) log were being made on an interim basis by the NASS as noted in DECO memo RCQA85-3366 dated November 18, 1985. Subsequently, the Operations Department believes that the quality and content of the logs had improved to acceptable levels and Control Room logs were returned to the Control Room NS0 (CRNS0).
The QA Department noted and agreed with this.
(4) Operations Engineers or Assistant Operations Engineer were reviewing NSS and NS0 logs daily.
(5) Superintendent-0perations was reviewing the NSS and NS0 logs periodically.
(6) The NASS has been assigned to the Control Room to supervise significant Control Room activities.
(7) During normal operations the Shift Technical Advisor (STA) is required in the control room for all operating modes except shutdown where in addition to his normal duties, he is assigned an additional task of investigating and resolving persistent nuisance alarms and annunciators.
During the current outage,
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however, the STA has been assigned to the Engineering Department since his presence is not required in the Control Room.
Therefore, the inspectors have seen very little involvement of the STAS at this time in Control Room activities involving alarms and annunciators.
The Shift Operations Advisor (SOA) position has been moved to the Control Room.
(8) The Operations Engineer has been reviewing the performance of shift activities against production schedules.
Increased involvement of the Operations Engineer and the Assistant Operations Engineer, particularly prior to going in the outage, has been accomplished through Night Orders, Standing Orders, Control Room tours, shift turnovers and attendance at the Plan of the Day meetings.
(9) The NSS has become more involved in planning for plant evolutions through the plan of the day (P0D) meetings.
(10) Limiting Conditions for Operation are being provided in hard copy through the out of service log and the computerized electronic office system.
(11) The control room information system has been changed to make the magnetic dots used on the control boards more visible and have the NSO perform an audit of dots on the control boards on a weekly basis, b.
Improve Communication Practices:
(1) The licensee had accomplished the committed training.
(2) The management control room tours were being accomplished.
(3) The shift briefings were being accomplished.
(4) Differences between the simulator and the plant were identified by an easel board at the simulator.
c.
Improve Administrative Procedures and Systems:
(1) The licensee had installed an interim status chart to track equipment LCOs.
(2) Post maintenance testing requirements had been given more prominence in the licensee's maintenance work order system through the addition of an attachment stating the testing requirements accompanying the work order.
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(3) The licensee had modified the administrative procedure on procedure development to require human factor considerations.
The licensee has yet to accomplish training of personnel on human factors.
d Improve Effectiveness of Incident Evaluation and Corrective Action Process:
(1) LER reviews were being accomplished by the Quality Assurance Department and the Independent Safety Engineering Group (ISEG).
Quality Assurance personnel were reviewing LERs for root cause and trending the root cause.
ISEG personnel were reviewing the LERs for appropriate corrective action.
The ISEG review was being performed to out-of-date procedures.
ISEG presently is preparing current procedures to reflect accurately the LER review process.
(2) The licensee had written or revised procedures associated with the corrective action process and provided training on the corrective action process.
e.
Increase Awareness of Consequences of Errors and Strengthen Accountability:
(1) The licensee's management conducted one on one meetings with the NSSs, NASSs and SOAs.
(2) Employees were briefed on the necessity to improve plant performance.
f.
Reduce Number of Equipment Repairs and Modifications Being Performed at Any One Time:
(1) Adequate changes had been made to the scheduling process to allow significant input from the NSS on maintenance / test activities.
(2) The committed work schedule meetings were being performed.
(3) Direction was provided to the plant support engineers on reducing engineering changes.
g.
Criteria Established for Measuring Effectiveness:
The licensee has established six performance measures with management attention levels.
These measures are trended and provided to senior management in the monthly production status report, b.
Independent Verification of Implementation of ROIP:
(1) Quality assurance surveillances were accomplished on the implementation of the ROIP.
These surveillances were to determine whether a specific action had been or was being
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accomplished.
A few of the ROIP actions were closed with actions still to be performed such as the performance of human factors training and the writing of the ISEG LER review procedures.
The surveillances were not an attempt to determine whether the problem was resolved adequately by the corrective action.
The licensee's QA division has incorporated the R0!P actions into its surveillance program of operating activities to be witnessed on a random basis.
The QA Director indicated that problem resolution determination was being accomplished through review of the performance measure trends and an audit is scheduled of the ROIP for December 1986.
'2) The licensee did provide monthly reports on ROIP progress to the vice president and plant manager.
However, once the Quality Assurance Department closed the action no further status was provided.
As such the appropriate management had no cognizance of the initiatives associated with human factors training.
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ROIP Items Remaining Open or Still to be Reviewed Are:
(1) Performance of human factors training for procedure writing.
(2) Issuance of ISEG procedures on LER rev!ews.
(3) Briefing of personnel to communicate an error to the appropriate operating staff so that management action can take place in a timely manner.
(4) Briefing of personnel to consider the consequences of the simplest operation.
(5) Initiatives taken to increase the reactor engineer's participa-tion in reactor operations.
During the ROIP inspection the inspectors encountered some instances of a lack of documentation of attendance at meetings.
In those cases the inspectors verified by interviewing personnel that the meetings did take place.
However, the inspectors stressed to the licensee at the final exit meeting the necessity of proper documentation.
There were also instances where the committed action had not been proceduralized or established through any other means than verbal direction.
The inspectors' concern of the licensee failing to continue to implement the commitment was reduced by the addition of ROIP commitments in the quality assurance surveillance system.
The inspectors did mention at the final,
exit meeting that prudent actions would be to direct future commitment implementation in a procedure, directive, position description, etc.
The assessment of the effectiveness of the licensee's initiatives under the ROIP shall be determined through review of the performance measures and normal inspector observations in followup of LERs, control room tours, plant tours and operational occurrences.
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No violations or deviations were identified in this area.
11.
Report Review (90713)
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L During the inspection period, the inspectors reviewed the licensee's Monthly Operating Reports for January, February, and March of 1986.
The inspectors confirmed that the information provided met the requirements of Technical Specification 6.6.A.3 and Regulatory Guide 1.16.
No violations or deviations were identified in this area.
Management Meetings (30702)
On March 10, 1986, the licensee met with NRC Region III at Region III headquarters to discuss engineering issues. A presentation by the licensee was given on seismic qualification, environmental qualification, design verification and recent problems on reconciliation of stress calculations. NRC Region III requested information on the turbine bypass line failure and licensee actions regarding a recent contractor evaluation of the replaced piping.
On April 9, 1986, the licensee met with NRC Region III at the plant site to review the current status of the licensee's actions on engineering issues. The main topics were the progress on stress calculation reconciliation, Stone and Webster review of the core spray system and licensee initiatives with ultrasonic examination of nelson studs. A concern over some of the safety-related studs has arisen.
The concern was generated from the licensee's analysis that the embedded plate failure during the turbine bypass line failure was attributed to a failed weld performed by the plate manufacturer. The same manufacturer supplied 251 safety-related plates.
On April 14, 1986, the licensee met with the NRC Regional Administrator at Region III headquarters to discuss Fermi scheduling.
No violations or deviations were identified in this area.
l 13.
Information Meeting with Local Officials (94600)
On March 21, 1986, the inspector met with the chairman of the Monroe County Commissioners and the director of the Monroe County Office of Civil Preparedness. The purpose of the meeting was to introduce the newly assigned inspector.
14. Open Items Open items are matters which have been discussed with the licensec, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both. An open item identified during the inspection is discussed in Paragraph 8.
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15.
Exit Interview (30703)
The inspectors met with licensee representatives (deroted in Paragraph 1)
on April 8 and 29, 1986, and informally throughout the inspection period and summarized the scopa and findings of the inspection activities.
The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection.
The licensee did not identify any such documents / processes as proprietary.
The licensee acknowledged the findings of the inspection.
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