IR 05000341/1999007
| ML20207E501 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 06/01/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20207E499 | List: |
| References | |
| 50-341-99-07, 50-341-99-7, NUDOCS 9906070056 | |
| Download: ML20207E501 (20) | |
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U.S. NUCLEAR REGULATORY COMMISSION REGIONlll'
Docket No:
50-341 l
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License No:
NPF-43 Report No:
50-341/99007(DRP)
Licensee:
Detroit Edison Company Facility:
Enrico Fermi, Unit 2 -
Location:
6400 N. Dixie Hwy.
Newport, MI 48166 Dates:
April 2 through May 15,1999 Inspectors:
S. Campbell, Senior Resident inspector a
J. Larizza, Resident inspector
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Approved by:
A. Vegel, Chief Reactor Projects Branch 6 Division of Reactor Projects
l 9906070d56 990601 PDR ADOCK 05000341
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EXECUTIVE SUMMARY Enrico Fermi, Unit 2 NRC Inspection Report 50-341/99007(DRP)
This inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 6-week period of resident inspection.
Operations The operators reduced power in a controlled and deliberate manner per the operating
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procedure in support of planned maintenance activities. Generally, the inspectors noted effective communication and self-checking (Section 01.1).
During the power reduction, the inspectors noted that management expectations were
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not met by operators in training in regard to: 1) attending pre-evolution briefs, 2) communicating when the control rod control power switch would be manipulated, and 3) obtaining permission to enter the area in front of the P603 Panel (Section 01.1).
The licensee appropriately initiated a condition assessment resolution document to
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document an unexpected scram of a control rod due to a bad fuse clip for a scram solenoid pilot valve. Operator response to the unexpected condition was prompt and appropriate. The licensee properly assessed this event for reportability (Section 01.1).
The licensee identified that the originalintent of Generic Letters 82-02, " Nuclear Power
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Plant Staff Working Hours," 82-12, " Definition of ' Key Maintenance Personnel,'" and 83-14, " Nuclear Power Plant Staff Working Hours," for management approval of overtime deviations, justification for overtime deviation, and groups deviating from overtime limits was not met. Further, the licensee determined that the monthly overtime reviews and methods by supervisors in executing the program were less than adequate,
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and that personnel understanding of the program expectations were unclear. One non-cited violation was identified (Section 03.1).
The inspectors observed that a non-licensed operator properly conducted his rounds
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and was knowledgeable of plant and equipment parameters (Section 04.1).
Maintenance The inspectors observed effective coordination between operations and maintenance
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personnel, and appropriate management oversight during the conduct of planned maintenance on the main condenser and the scram solenoid pilot valves (Section M1.2).
A mechanic's response to hold together a fitting that had been separated during a
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maintenance activity on the air piping for a scram solenoid piloi valve, until tightened, was prompt and averted a manual scram. The licensee's investigation into the improper installation of the fitting was thorough. The inspectors concluded that the licensee's approach for investigating possible improperly assembled air fittings on the remaining hydraulic control units was appropriate (Section M1.3).
One minor violation was identified when maintenance personnel did not follow a work
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request and over-greased the control center heating ventilation and air conditioning
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return fan inboard bearing. Since maintenance personnel did not obtain engineering guidance to over-grease l engineering personnelincorrectly focused on over-greasing as a cause to the high temperatures. This caused unnecessary operation of the control center heating ventilation and air conditioning sys';em and an additional operator burden re-tagging the system (Section M1.3).
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Enoineerina The inspectors concluded that the independent Safety Engineering Group's review of
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the overtime program was thorough as reflected in the quality of the identified findings.
The Independent Safety Engineering Group identified programmatic and procedural weaknesses and recommended appropriate corrective actions (Section O3.1).
The licensee effectively identified the error that caused the control rod blades to be
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mispositioned in the 3-D Monicore and placed this deficiency in the corrective action program. The licensee's investigation of this issue was thorough (Section E1.1).
The inspectors observed engineering personnel providing effective support to
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maintenance personnel during the scram solenoid pilot valve replacement and main condenser tube repair evolutions and during routine maintenance and testing activities (Section E4.1).
Plant Supp_gri Radiation protection personnel provtded effective oversight coverage of the main
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condenser tube repair activity (Section M1.2).
The inspectors concluded that radiation protection controls were implemented effectively i
(Section R1.1).
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Report Details l
Summary of Plant Status l
Unit 2 began this inspection period at 97 percent power. On April 9,1999, operators reduced I
plant power to sepair a main condenser tube leak, replace selected scram solenoid pilot valves,
and perform maintenance on main turbine control valves. Power was subsequently retumed to 97 percent on April 11,1999.
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Conduct of Operations O 1.1 Power Reduction to Repair Leakina Condenser Tubes a,
Insoection Scoce (71707)
On April 9 and 10,1999, the inspectors observed operators reduce reactor power to 50 percent per General Operating Procedure 22.000.03, Revision 54, * Power Operation 25 percent to 100 percent to 25 percent," to repair and clean the condenser, to replace the scram solenoid pilot valves and perform maintenance activities associated with the turbine control valves. The inspectors reviewed the operating procedure, reviewed condition assessment resolution documents (CARDS) written to document deficiencies identified during the downpower, and attended control room pre-evolution briefs.
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Observations and Findinas
The licensee scheduled four operator trainees to participate in the power reduction for training purposes. The inspectors noted that management expectations were not met in that two of the four trainees did not attend the pre-evolution brief. Subsequently, the nuclear assistant shift supervisor (NASS) counseled these individuals on attending the briefs. During the brief, the NASS discussed using three-way communication and self-checking techniques, expected plant parameter changes and potential problems which may be encountered during the power reduction. Further, the NASS discussed
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requesting permission from the shift technical advisor to enter the area in front of the P603 Panel, and expectations of announcing to the NASS when the control rod power
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switch would be manipulated.
The operators reduced power in a controlled manner per the procedure. A licensed reactor operator supervised the trainees as they changed reactor power. The inspectors observed operators generally use three-way communication and self-checking techniques during the activity. However, the inspectors noted that some licensee individuals had entered in front of the P603 Panel without requesting permission of the shift technical advisor. Additionally, some of the individuals in training did not inform the NASS when the control rod power switch was manipulated.
When power reached 50 percent, operators locked down High Pressure Control Valve No. 4 for maintenance and an expected half scram on Reactor Protection System B occurred. Unknown to the operators, Scram Solenoid Pilot Valve (SSPV) C11-F117 had failed open previously due to a bad fuse clip. When the half
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scram occurred, SSPV C11-F118, which was in series with Valve C11-F117, opened to complete the vent path and Control Rod 06-35 scrammed. No power changes were
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l noted when the control rod scrammed. The operators properly entered Abnormal Operating Procedure 20.106.07, " Control Rod Drift," and took appropriate corrective actions. The operators restored High Pressure Control Valve No. 4 and reset the half scram. The licensee initiated CARD 99-11976 to document the condition. Maintenance personnel subsequently replaced the fuse clip for SSPV C11-F117, and the affected control rod and solenoid were retested satisfactorily. The licensee reviewed 10 CFR 50.72,10 CFR 50.73, and NUREG 1022, Revision 1, Section 3.3.2, and determined that this event was not reportable.
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Conclusions
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The operators reduced power in a controlled and deliberate manner per the operating procedures in support of planned maintenance activities. Generally, the inspectors noted effective communication and self-checking. However, the inspectors ncted that management expectations were not met by operators in training in regards to:
1) attending pre-evolution briefs,2) communicating when the control rod control power switch would be manipulated, and 3) obtaining permission to enter the area in front of the P603 Panel.
The licensee appropriately initiated a CARD to document an unexpected scram of a control rod due to a bad fuse clip for a SSPV. Operator response to the unexpected condition was prompt and appropriate. The licensee properly assessed this event for reportability.
01.2 Emeraency Diesel Generator (EDG) 13 Maintenance Activity with Standby Liauid Control (SLC) Pumo B Inocerable On May 5,1999, the inspectors identified that the licensee had removed the Division 1 EDG 11 for maintenance while the Division 2 SLC system was inoperable.
Divisions l SLC System A and Division 2 SLC System B are powered by Division 1 EDG 11 and Division 2 EDG 13, respectively. With neither SLC B nor EDG 11 available, a method of injecting Boron into the core may not have been available during a loss of offsite power. Technical Specification 3.8.1.1.c states, in part, that with one or both EDGs inoperable, verify within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> that all required systems, subsystems, trains, components and devices that depend on the remaining onsite A.C. electrical power division as a source of emergency power are also operable; otherwise, be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The inspectors determined that the Technical Specification (TS) action was not performed. This is an unresolved item (URI 50-341/99007-01(DRP)) pending the inspectors' review of the licensee's investigation of the issua.
Operations Procedure and Documentation O3.1 Control of Overtime (OT)
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Inspection Scope (71707)
in March,1999, licensee management directed the Independent Safety Engineering Group (ISEG) to review OT incurred at the Fermi plant. Between March 11 and April 12,
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1999, ISEG reviewed OT hours in 1998 and the process for controlling OT usage. The inspectors interviewed associated personnel, reviewed the following documents to review the licensee's findings and to assess the adequacy of the OT program:
CARD 99-11345 " Overtime Hours Beyond Technical Specification (TS) Limits"
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CARD 99-12798 " Overtime Control Concerns"
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Employee Time Sheets
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Time Entered Reports
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Card Reader Histories for Selected Individuals
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Amendment 101 of TS 6.2.2 " Removal of Overtime Limits from TS"
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Suspended TS 6.2.2 " Administrative Controls for Unit Staff"
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General Administration Conduct Manual (MGA) Procedure 10, Revision 7,
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" Fitness for Duty" TS 6.8.6 " Administrative Controls to Limit Working Hours of Personnel"
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Generic Letters (GLs) 82-02 and 82-12 " Nuclear Power Plant Staff Working
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Hours" GL 83-14 " Definition of ' Key Maintenance Personnel'(Clarification of GL 82-12)"
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Observations and Findinag in conducting their review the ISEG used payroll sheets from Detroit Edison Company headquarters to review OT on a weekly basis of the mission critical organizations (operations, maintenance, radiation protection, and system eng neering). The ISEG completed the OT assessment on April 12,1999. The licensee entered the OT deficiencies noted by ISEG into their corrective action process via CARDS 99-11345 and 99-12798.
The ISEG established the criterion of individuals working greater than or equal to 14 weeks at greater or equal to 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> a week as excessive overtime. Based on the review of the company payroll sheets the licensee identified that fifteen operations, seven maintenance, one engineering, and two radiation protection personnel exceeded the ISEG criteria for excessive overtime. No examples were confirmed where TS overtime requirements were exceeded.
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The ISEG identified the following program weaknesses and concerns, which were documented in CARD 99-12798:
In many cases, OT deviations were authorized by individuals who were not
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designated by Procedure MGA10.
Procedure MGA10 for OT control allows for " blanket" deviations for all of a
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department during extended shutdown conditions (which is defined to include refuel outages [RF)). During RFO6, a number of deviation request forms were
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approved for periods of up to several weeks.
i Two instances were documented where nuclear shift supervisors (NSSs)
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requested and authorized their own OT deviations.
One instance was noted where an NSS authorized an OT deviation requested
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by/and for the operations engineer (the NSS's supervisor).
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Examples were noted where deviation request forms were authorized after the
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dates covering the requested work-hour deviations, which did not meet the intent of Procedure MGA010 or TS.
Deviation request forms were not specific enough to justify the particular OT
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deviation (e.g., "to support RFO6").
Overtime deviations occurred where deviation request forms could not be found
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authorizing the deviation.
The procedure change process did not adequately ensure that the original intent
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of the NRC guidelines was maintained after the OT control requirements were transferred from TS (via Amendment 101) to site administrative procedures.
The ISEG recommended that the following actions be evaluated / pursued:
Strengthen / clarify site OT procedural guidance.
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Track the accumulated OT usage on an ongoing basis and provide a tie to the
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associated deviation request forms.
Overtime usage during outages should be managed such that blanket deviations
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are not expected to occur /be authorized for large groups for long periods of time.
Individuals should not be allowed to work sigr.ificant amounts of OT for extended
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periods of time without higher levels of approval.
Re-evaluate the site population that needs to be covered by the regulatory portion
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of the OT program.
A solution team was formed to investigate the ISEG findings. The solution team determined that the OT program did not meet the originalintent of GL 82-02,82-12, and 83-14 regarding management approval of OT deviations, justification for OT deviation, and groups deviating from OT limits. Further, the solution team determined that the monthly OT reviews and methods by supervisors in executing the program were less l
than adequate, and that personnel understanding of the program expectations were unclear. The solution team proposed the following corrective actions to restore the original intent of the OT program:
Require OT approval by plant manager or the emergency director,
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i El;minate approval of group deviations from OT requirements.
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Reduce the scope of OT applicability to personnel performing safety-related
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activities.
Communicate the OT policy to the site.
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l Improve computer reports for monthly OT reviews and develop formal method for I
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tracking paid and unpaid OT.
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Develop lessons leamed training for organizational unit heads.
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Track the regulatory commitments for OT and identify the commitments in the OT
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procedure.
The inspectors concluded that these corrective actions were acceptable to resolve the program weaknesses.
TS 6.8.6 states, in part, that any deviation from the working-hour guidelines shall be authorized in advance by the plant manager, or his designee, in accordance with approved administrative procedures, or by higher levels of management, in accordance with established procedures and with the docurnentation of the basis for granting the deviation. Contrary to the above, during the period before between March 11 and April 12,1999, the licensee identified several instances that occurred during 1998 where the plant manager, his designee, or higher levels of management did not authorize approvals in advance for deviations from the working-hour guideline. Specifically: 1) two instances were identified where NSSs requested and authorized their own OT deviations, 2) one instance was noted where an NSS authorized an OT deviation requested by/and for the operations engineer, who was the NSS's supervisor, and 3) several examples were noted where deviation request forms were not authorized in advance but after the dates covering the requested work-hour deviations. This is a Severity Level IV violation and is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 50-341/99007-02). This violation is in the licensee's corrective action program as CARDS 99-11345 and 99-12798.
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Conclusions The licensee identified that the original intent of GL 82-02,82-012, and 83-14 for management approval of OT deviations, justification for OT deviation, and groups deviating from OT limits was not met. Further, the licensee determined that the monthly
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OT reviews and methods by supervisors in executing the program were less than adequate, and that personnel understanding of the program expectations were unclear.
One non-cited violation was identified. The inspectors concluded that the ISEG review of the OT program was thorough.
Operator Knowledge and Performance 04.1 Operator Rounds Observation (71707)
The inspectors accompanied a non-licensed operator on his tour of plant facilities outside of the main plant buildings. The operator properly documented readings in the log sheets and enscred that the readings were within the allowable tolerances. The operator was knowledgeable of related plant systems, equipment, instrumentation, and expected operating parameters.
Miscellaneous Operations issues (92700)
08.1 Closure of Severity Level IV Violations The Severity Level IV violations listed below were issued in Notices of Violation prior to the March 11,1999, implementation of the NRC's new policy for treatment of Severity
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Level IV violations (Appendix C of the Enforcement Policy). Because these violations l
would have been treated as non-cited violations in accordance with Appendix C, they are
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being closed out in this report.
Violation 50-341/97002-07 This violation is in the licensee's corrective action
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program as Deviation Event Reports (DERs) 96-1027,96-1058, and 96-1129.
. Violation 50-341/97002-08 This violation is in the licensee's corrective action
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program as DERs 96-0684, and 96-1823.
08.2 (Closed) Licensee Event Report (LER) 50-341/96011-00: " Emergency Safety Feature Actuation of Torus to Drywell Vacuum Breaker." This actuation occurred because the operators lacked awareness regarding the potential for opening the torus to drywell breaker while initiating the Residual Heat Removal and drywell purge systems.
Insufficient information in the Residual Heat Removal system procedure alerting the operators of the potential for vacuum breaker cycling during this evolution was a contributing factor to the event. The licensee conducted training meetings with personnel and a caution statement was added to the procedures. The inspectors determined that the licensees corrective actions were adequate to prevent event recurrence. This LER is closed.
08.3 (Closed) LER 50-341/96015-00: " Emergency Safety Feature Actuation of Division 2 Emergency Equipment Cooling Water (EECW) System During Fill and Vent Evolution."
The operating crew did not effectively control filling and venting of the Division 2 EECW system and as a result the EECW system automatically initiated in response to a low differential pressure. Corrective actions included training and discussion of " lessons learned" with licensed and non-licensed operators, and development of an operations evolution guide to properly coordinate sequence of events. The inspectors determined that the licensees corrective actions were adequate to prevent event recurrence. This LER is closed.
08.4 (Closed) Unresolved item (URI) 50-341/98002-01(DRS): Requirements for Mixed Atmosphere in Containment. Since this issue was raised, and after consultation with Nuclear Reactor Regulation staff, the inspectors determined that natural convection would provide adequate mixing to ensure that a combustible hydrogen concentration would not develop in containment following an accident. The inspectors reviewed Emergency Operating Procedure 29.100.01, Sheet 4, * Primary Containment H /O,
Control," Revision 7, and determined that the procedure had been revised to specify operation of the drywell fans after a Loss-of-Coolant-Accident. Operation of the drywell fans would provide another means of ensuring that the containment atmosphere was mixed to preclude localized combustible hydrogen concentrations. The inspectors i
concluded that the licensee met the requirements outlined in Paragraph (b)(2) of 10 CFR 50.44, " Standards for Combustible Gas Control System in Light-Water-Cooled Power Reactors." This URI is closed.
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M1.1 General Comments a.
Inspection Scope (62707.)
The inspectors observed all or portions of the following work activities:
High Pressure Coolant injection System Maintenance Outage
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Procedure 24.307.15, *EDG 12 - Start and Load Test"
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SSPV Replacement, and
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Division 2 Control Center Heating Ventilation and Air Conditioning (CCHVAC)
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Maintenance Outage The inspectors concluded that the observed maintenance and surveillance testing activities were conducted professionally and thoroughly with effective management oversight and effective engineering personnel support. Associated work packages were properly approved and current procedures were used. Further, radiation protection
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personnel provided effective monitoring of the activities as required.
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M1.2 Main Condenser Tube Leak Repair and SSPV Reolacement a.
Inspection Scope (62707)
On April 9,1999, the licensee reduced power to 50 percent to perform the following:
j isolate, drain, and clean the main condenser water boxes,
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inspect the tube sheets and repair a main condenser tube leak,
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replace 33 SSPVs,
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replace the oil filter for the unitized actuator on High Pressure Stop Valve No. 4,
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and clean / replace inlet Turbine Building Closed Cooling Water filter
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The inspectors reviewed selected maintenance procedures and observed portions of the work activities, b.
Observations and Findinas Operations personnel followed procedures for isolating, tagging, and draining the main
. condenser water boxes. The inspectors noted good self-checking techniques and communications during the draining evolution. Maintenance personnel determined the location of the leaking condenser tube and made the necessary repairs. During the main condenser water box inspection, maintenance personnel found debris in the water boxes that consisted of predominantly black plastic material from the cooling tower, and vegetation growth from around the circulating pond. Maintenance personnel removed the debris and cleaned the affected water boxes. Additionally, inspection of the tube sheet revealed two missing tube plugs and three additional tube plugs that were not in the expected location as depicted on the original drawing, and minor corrosion on the
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tube interface of the tube sheet. The drawings will be updated to reflect the correct configuration of the plugs per Technical Service Report 30561.
l The inspectors observed portions of the SSPV replacement and noted that maintenance l
personnel methodically tracked which valves required replacement and performed the work activity in accordance with procedures.
The inspectors noted effective management oversight and effective radiation protection support during both activities. The licensee documented deficiencies identified during the activities into the corrective action program.
c. - Conclusions The inspectors observed effective coordination between operations and maintenance
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' personnel, and appropriate management oversight during the conduct of planned I
maintenance on the main condenser and the scram solenoid pilot valves. Radiation
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protection personnel provided effective coverage of the condenser tube repair and SSPV l
replacement activities.
M1.3 Imorocer initial Installation of Air Fittina Causes Tubina Seoaration for Hydraulic Control Unit (HCU).34-07 f
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Inspection Scoce (62707)
On April 11,1999, while performing SSPV replacement per Work Request (WR) 000Z976042, the air fitting above SSPV C11-F116 separated and caused a low scram pilot valve low header pressure alarm in the control room. A mechanic held the fitting together until the nut on the fitting was tightened with a wrench. This action prevented header pressure from falling to a pressure where a manual scram would have
been required. The inspectors reviewed CARDS and WRs associated with the fitting and interviewed maintenance personnel to determine the cause of the improper installation of f
the air piping.
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Observations and Findinas The licensee initiated CARD 99-11976 to document the unexpected separation of the mechanical joint. As part of the CARD investigation, the licensee used a similar new fitting and identical piping to recreate the configuration that failed. Through repetitive attempts, the licensee concluded that the fitting nut was not tightened adequately during initial installation to cause the ferrule to bite into the pipe sufficiently. The inadequate compression fit caused the ferrule to slide past the pipe and separate the joint while the licensee replaced SSPV C11-F116.
The inspectors reviewed Procedure 35. CON.017, Revision 30, " Fabrication, Installation,
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Repair, and Removal of Q and Non-Q Instrument Tubing," and determined that Enclosure A provided instructions to turn the nut eight flats to ensure proper fitting compression. The inspectors reviewed several previous WRs, CARDS and DERs associated with the system and were unable to identify an activity that involved disconnecting this joint or a previous deficiency identified in the corrective action
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The licensee concluded that since this joint was improperly made'during original installation, the air piping for the remaining HCUs were suspect. The licensee's corrective action included using a "go-no-go" gauge between the adapter and the compression nut for the 185 HCUs. This will be performed during a future plant outage l
to ensure the activity will not cause inadvertent venting of the HCUs while at power. The l
WR for replacing the remaining SSPVs will be changed to add a step to use the gauge, c.
Gonclusions A mechanic's response to hold together a fitting that had been separated during a maintenance activity on the air piping for a SSPV, until tightened, was prompt and averted a manual scram. The licensee's investigation into the improper installation of the fitting was thorough. The inspectors concluded that the licensee's approach for investigating potentially improperly assembled air fittings on the remaining HCUs was appropriate.
M1.4 Failure on CCHVAC West Return Fan Bearina a.
Inspection Scoce (62707)
On April 19,1999, the licensee removed the Division CCHVAC system from service for a planned 4-day maintenance activity. Delays in completing the maintenance activity occurred when the licensee identified high temperature on the inboard bearing for the CCHVAC return fan during post-maintenance testing. Consequently, the fan was operated repetitively to determine the cause of the high temperature. The inspectors interviewed maintenance personnel and reviewed the following documents to determine the adequacy of the maintenance activity:
CARD 99-11926 " Division 2 CCHVAC Return Air Fan inboard Bearing High
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Temperature" Control Room Logs between April 19 and April 26,1999
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Limiting Condition for Operation (LCO) 99-0166 " Division 2 CCHVAC Outage
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LCO 99-0171 " Division 2 CCHVAC Return Air Fan Bearing -High Temperature"
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LCO 99-0175 " Division 2 CCHVAC Retum Air Fan inboard High Bearing
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Temperatures," and Maintenance Conduct Manual MMA03, Revision 4, " Preventive Maintenance and
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Periodic Calibration and Testing."
b.
Observations and Findinas On April 19, at 5:45 p.m., the operators entered a 7-day action statement per TS 3.7.2 (LCO 99-0166) to perform, among other activities, a 2-year preventive maintenance (PM)
on the Division 2 CCHVAC return fan. The PM required tensioning the fan belts,
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gressing the fan bearings and performing a sheave alignment. The licensee established 24-hour engineering coverage for the CCHVAC maintenance activity. After the mechanics completed the PM, engineering coverage ended and the operators exited LCO 99-0166 on April 22, at 9;48 a.m.
The licensee operated the fan until 8:20 p.m., when the fan was shutdown due to the inboard bearing temperature increasing to 154.9'F. The control room operators declared the system inoperable and entered the appropriate TS LCO (LCO 99-0171).
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Maintenance personnel replaced the belts that became loose during the run but did not seek system engineer guidance to resolve the high temperature problem and performed the PM again. Concluding that the high temperature was a problem with the bearing grease, the maintenance personnel deviated from the WR requirement and added 1 ounce (20 pumps) instead of.06 ounces (12 pumps) of grease, until the grease extruded from a bearing fitting. The failure to follow the WR constitutes a violation of minor significance and is not subject to formal enforcement action.
On April 23, at 5:56 a.m., operators started the fan and exited LCO 99-0171. The work week manager informed the system engineers of the high temperature at 6:00 a.m. At 7:30 a.m., bearing temperature increased to 162'F and, in response, the control room operators turned off the fan and contacted the engineers. At 8:15 a.m., the system engineers investigated the high bearing temperature and reduced vibration readings and determined that over-greasing had dampened vibrations and incorrectly determined that over-greasing of the bearing contributed to the high temperature. Consequently, the engineers established a new limit of 160*F for shutting down the fan. At 9:43 a.m., the bearing temperature increased to 161 *F and the operators shutdown the fan and entered LCO 99-0175. The operators appropriately set the time-clock at April 22,1999, 8:20 p.m., when the operators first noted the elevated bearing temperatures (LCO 99-0171).
At 10:00 a.m., system engineering personnel met, agreed that over-greasing was the cause and developed two approaches to the problem that included removing the old grease, inspecting the bearing and performing the PM again or replacing the bearing.
The engineers chose the first option. At 10:30 a.m., mechanics removed the cap on the bearing housing, checked bearing clearances, removed the old grease and added approximately 0.6 ounces of grease per WR 000Z991390. This solution was unsuccessful because, at 2:30 p.m., operators shutdown the fan when bearing temperatures fluctuated between 108* and 128'F.
The mechanics used WR 000Z991390 to replace the bearing. While removing the bearing, the licensee discovered that the locking sleeve, which locks the bearing assembly in place, had slipped off the shaft and rubbed against the pillow block. This condition was not evident during the bearing inspection that the licensee conducted at 10:30 a.m. The licensee subsequently dete mined that the failure was age-related and was not caused by improper performance of previous maintenance activities. The inspectors reviewed the work history for this fan and determined that bearing work had never been performed over the 15-year life of the fan. The inspectors also reviewed the vendor's manual and did not identify a requirement, other than greasing, for periodic maintenance of the bearing. The licensee documented the occurrence of the bearing failure in their corrective action program in CARD 99-11926.
The mechanics replaced the bearing and, on April 24, at 5:25 p.m., operators started the fan. After several adjustments, the operators exited LCO 99-0175. Bearing temperatures and vibration readings were determined to be satisfactory.
c.
Conclusion One minor violation was identified when maintenance personnel did not follow a work request and over-greased the CCHVAC retum fan inboard bearing. Since maintenance personnel did not obtain engineering guidance to over-grease, engineering personnel
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incorrectly focused on over-greasing as a cause to the high temperatures. This caused unnecessary operation of the CCHVAC system and an additional operator burden in j
re-tagging the system.
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M8 Miscellaneous Maintenance issues (92902)
i M8.1 (Closed) LER 50-341/96009-00: " Engineered Safety Feature Actuation - Isolation of the i
Torus Water Management System (TWMS), While Replacing a Burned Out Indicating Lamp." An operator attempted to replace a bumed indicating lamp for the TWMS, and while replacing the lamp, the operator inserted it further than expected into the socket due to a crack in the socket causing a short circuit and the TWMS outboard isolation valves to close. Three weeks before this event, a repairman had inadvertently cracked the indicating lamp socket while performing routine maintenance. This was identified in a work request, but the operator was unaware of this since there were no tags or other indications of this condition. The licensee reviewed the work control process and
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improved it through increased usage of deficiency tags and other indications for j
component deficiencies. This issue was discussed in NRC Inspection Report 50-341/96005. The inspectom determined that the licensee's corrective actions were adequate to prevent event recurrence. This LER is closed.
M8.2 (Closed) LER 50-341/96012-00: " Engineered Safety Feature Actuation of Primary Containment isolation Valve B3100F014A." Valves B3100F014A and B3100F0148 are inboard primary containment isolation, air operated, valves in the Recirculation Pump Seal Purge System. While troubleshooting, an electrician lifted the leads for i
Valve B3100F0148 from the panel side of the terminal block rather than the field side, deenergizing the solenoid and causing Valve B3100F014A to reposition closed. The cause of this event was personnel error. Corrective actions included review of training provided to contract technicians and discussion of this event in continuing training for i
instrumentation and Control and Maintenance personnel. The inspectors determined that the licensee's corrective actions were adequate to prevent event recurrence. This LER is closed.
M8.3 (Closed) LERs 50-341/96017-00 and 50-341/96017-01: Failure of Safety Relief Valves to open within TS allowed tolerances. This involved the licensee's discovery that 11 of the 15 pilot valves inside the safety relief valves would not have lifted within the TS one percent allowable tolerance. These two LERs were closed with LER 50-341/96017-04 in NRC Inspection Report 50-341/98019.
Ill. Enoineerina E1 Conduct of Engineering E1.1 Error in Transoosino Control Rod Blade Informatio.n a.
Inspection Scope (37551)
On April 27,1999, while establishing the computer model for the design of the reactor core for Cycle 8, the licensee discovered an inconsistency between identification numbers of the control rod blades in the 3-D Monicore and on the fuel transfer forms used to document the locations where the control blades would be moved during RFO6.
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The 3-D Monicore calculates, among other things, thermallimits and power distribution in the core. The inspectors interviewed associated engineering personnel and reviewed the following documents to assess the cause of the error and the potential safety impacts:
CARD 99-13296 * Error in 3-D Monicore Data Map of Control Rod Blade Handle
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Identifications and Blade Depletion Arrays" Fermi - 2 Cycle 7 Operating Parameter List (OPL)- 7, " Control Blade Core Map"
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Special Nuclear Material Form / Component Transfer Form SNM-SPL-06-21,
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"RFO6 Control Blade Shuffle," and System Procedure 53.000.07, Revision 6," Process Computer Data Bank
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Verification" b.
Observations and Findinas General Electric (GE) sent the preliminary OPL-7 document for the licensee to markup so that GE could use this copy to prepare the software for the 3-D Monicore to reflect control rod blade locations changed during the RFO6 shuffie. The licensee shuffles the control rod blades per the fuel transfer form so that burned-up blades would be relocated to low burn regions of the core,. Although the reactor engineer subsequently developed a fuel transfer form, the engineer urd a scrap piece of paper to communicate the planned RFO6 movements of the control blades to the nuclear fuel engineer. The quality assurance organization did not perform a quality verification of the paper and the inspectors verified that the licensee had no procedure requirement for quality verification of this information. The nuclear fuel engineer used the paper to markup OPL-7 but made an error in transposing the control rod blade movements and caused an inaccurate reflection of the control rod blade locations in OPL-7. The OPL reflected 9 of the 18 control rod blades in wrong locations. Consequently, the marked-up OPL-7 was sent to GE and the software tape was developed based on the inaccurate control rod blade locations.
After receiving the software tape from GE, a missed opportunity to identify the error occurred when the licensee used the OPL-7 to verify the software per Step 7.4.1 of Procedure 53.000.07. The error had no impact on actual control rod blade locations since the RFO6 control rod blade shuffles were conducted per the fuel transfer form, which was developed independent of OPL-7. The licensee verified the software and loaded into the 3-D Monicore during RFO6. A second missed opportunity to identify the error occurred when the fuel transfer forms were sent to the nuclear fuel engineer at the end of RFO6 for verification. During this review, the nuclear fuel engineer did not compare the fuel transfer form against OPL-7.
The errors in the 3-D Monicore data bank had no impact in calcuiating the TS required values for thermal limits and power distribution since the computer program assumes each control rod blade has the same neutron absorption capability. However, the error would impact control rod blade lifetime calculations (performed twice per cycle) with the first cycle calculation due in October of 1999.
The licensee initiated CARD 99-13296 to document this error. However, the licensee was unable to determine if the error was a human error or a transposition error since the piece of paper was lost. Corrective actions included the following:
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j a review of OPL-7 for similar problems was completed and no problems were
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to revise Procedure 53.000.07 to include the associated transfer form as the base
l document for validation of control rod blades, and to train reactor engineers and nuclear fuel engineers on not using informal
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communication methods when transferring data
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Conclusions l
The inspectors concluded that a human performance error and mis-communication between a reactor and a nuclear fuels engineer caused the core locations for the control rod blades in the 3-D Monicore to be incorrect. Further, the inspectors concluded that the licensee lacked proper administrative controls for exchanging this information between the engineering groups. The licensee noted at least two missed opportunities in identifying the incorrect control rod blade information. There were no safety consequences as a result of the error. The licensee efiectively identified the error that caused the control rod blades to be mispositioned in the 3-D Monicore and effectively placed this deficiency in the corrective action program. The licensee's investigation of this issue was thorough.
E4.
Engineering Support of Facilities and Equipment (37551)
E4.1 Effective Enoineerino Suocort of Plant Activities The inspectors observed engineering personnel providing support to maintenance personnel during the SSPV replacement and main condenser tube repair evolutions, and during routine and non routine maintenance and testing activities. The inspectors also observed engineering personnelinvolvement in the disposition of deficiencies
' documented in CARDS and in assisting shift supervisors with operability determinations.
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The inspectors determined that engineering personnel effectively supported maintenance and operations personnel based on observed activities.
E8 Miscellaneous Engineering items (92902)
E8.1 (Closed) Temoorary Instruction 2515/141: Review of Year 2000 (Y2K) Readiness of
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Computer Systems at Nuclear Power Plants The inspectors conducted an abbreviated review of Y2K activities and documentation
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using Temporary Instruction 2515/141, " Review of Year 2000 (Y2K) Readiness of Computer Systems at Nuclear Power Plants." The review addressed aspects of Y2K management planning, documentation, implementation planning, initial assessment,
detailed assessment, remediation activities, Y2K testing and validation, notification j
activities, and contingency planning. The reviewers used NEl/NUSMG 97-07," Nuclear
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Utility Year 2000 Readiness," and NEl/NUSMG 98-07," Nuclear Utility Year 2000 Readiness Contingency Planning," as the primary references for this review.
' Conclusions regarding the Y2K readiness of this facility are not included in this summary.
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l The results of this review will be combined with reviews of Y2K programs at other plants in a summary report to be issued by July 31,1999.
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[v IV. Plant Support R1 Radiological Protection and Chemistry Controls R1.1 Effective Radioloalcal Practices (71750)
During routine tours of the plant, the inspectors noted personnel effectively use proper radiological protection practices. Personnel surveyed themselves and items as required while exiting the radiological controlled area and while entering the control room.
Personnel also used proper procedures while exiting contaminated areas regarding donning and removing protective clothing. The inspectors observed decontamination efforts following a maintenance activity. The technician decontaminated the area in accordance with procedures.
Health Physics personnel properly surveyed and posted areas due to changing radiological conditions, in particular, when operators increased hydrogen water chemistry flow, The changes in radiological conditions were communicated effectively by health
' physics personnel at the shift turnover meetings and by the radiation protection manager at the management meetings. The inspectors verified temporary lead shielding installed in the plant was identified and labeled per procedure. The inspectors confirmed that survey instruments and radiation monitors were calibrated. The inspectors observed potentially radioactive material being tagged per procedures.
V. Manaaement Meetinos
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Exit Meeting Summary The inspectors presented the inspection results to members of licensee management on May 18,1999. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
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PARTIAL LIST OF PERSONS CONTACTED.
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Licensee
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' S. Booker, Maintenance Superintendent ~
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D. Cobb, Operations _ Superintendent -
- R. Cook, Compliance Supervisor, Nuclear Licensing
' R. DeLong,- Superintendent, System Engineering R. Eberhardt, Superintendent, Outage Management
. P. Fessler, Plant Manager '
E. Heitzenrater, NSS, Operations K. Hlavaty, Assistant Superintendent, Operations
- T. Hsieh, Nuclear Fuels Supervisor
. W. O'Connor, Manager of Nuclear Assessment N. Peterson, Acting Director, Nuclear Licensing
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J. Piona,-Technical Director -
- T. Schehr, Operating Engineer S. Stasek, Supervisor, independent Safety Engineering Group J. Thorson, Nuclear Engineering Supervisor ;
- W.: Tucker, Supervisor Nuclear Fuels and Reactor Engineering Group NB_Q S. Campbell, Senior Resident inspector J. Larizza, Resident inspector
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INSPECTION PROCEDURES USED
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-IP 37551: - Onsite Engineering
- IP 62707: ' Maintenance Observation i
IP 71750 Plant Support Activities i
IP 71707:
Plant Operations.
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i IP 92700:
Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902:
Followup - Maintenance
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- ITEMS OPENED, CLOSED AND DISCUSSED Opened 50-341/99007-01
- URI. - EDG 13 maintenance activity with SLC Pump B inoperable
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50-341/99007-02
. NCV ' Failure to properly authorize overtime deviations Closed
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50-341/99007-02 NCV Failure to properly authorize overtime deviations 50-341/97002-07; VIO Inappropriate acceptance criteria in procedures 50-341/97002-08 1 VIO -
Failure to issue DERs.
- 50-341/96011-00 -
LER Emergency safety feature actuation of torus to drywell vacuum breaker
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. 50-341/96015-00 LER Emergency safety feature actuation of Division 2 EECW during fill and vent evolution 50-341/98002-01-URI Requirements for mixed atmosphere in containment
>50-341/96009-00 LER. Engineered safety feature actuation -isolation of the torus water Management system while replacing a burned out indicating lamp -
50-341/96012-00 LER Engineered safety feature actuation of primary containment isolation valve
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50-341/96017-00'
LER Failure of safety relief valves to open within TS allowed tolerance
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.50-341/96017-01 LER-Failure of safety relief valves to open within TS allowed tolerance
. Temporary Instruction Review of Y2K readiness of computer systems at nuclear 2515/141.
_ power plants Discussed '
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l LIST OF ACRONYMS USED CARD Condition Assessment Resolution Document
.CCHVAC Control Center Heating Ventilation Air Conditioning
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CFR Code of Federal Regulations l
DER Deviation Event Report EDG Emergency Diesel Generator EECW Emergency Equipment Cooling Water GE General Electric.
'GL Generic Letter HCU Hydraulic Control Unit ISEG Independent Safety Engineering Group LCO Limiting Condition for Operation LER Licensee Event Report MGA General Administration Conduct Manual NASS Nuclear Assistant Shift Supervisor NSS Nuclear Shift Supervisor OPL'
Operating Parameter List OT.
Overtime PM Preventive Maintenance RF Refueling Outage RFC Refueling Floor Coordinator SLC, Standby Liquid Control SSPV Scram Solenoid Pilot Valve TS
- Technical Specification TWMS Torus Water Management System URI Unresolved item VIO Violation WR :
' Work Request i
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