IR 05000341/1993007
| ML20045D202 | |
| Person / Time | |
|---|---|
| Site: | Fermi  |
| Issue date: | 06/21/1993 |
| From: | Burgess B, Falevits Z, Salehi K, Yin I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20045D191 | List: |
| References | |
| 50-341-93-07, 50-341-93-7, NUDOCS 9306280085 | |
| Download: ML20045D202 (12) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION III
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Report No. 50-341/93007(DRS)
Docket No. 50-341 License No. NPF-43 Licensee: The Detroit Edison Company 6400 North Dixie Highway
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Newport, MI 48166 Facility Name:
Fermi 2 Nuclear Power Station
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Inspection At:
Fermi 2 Site, Newport, MI
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Inspection Conducted: March 29-30, April 26-30, May 10-13, and June 2, 1993 Inspectors d ec qd["
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Approved By:,7' Bruce L. Burcjess, Cliief mn c<<y Date Operational Programs Section Inspection Summary
Inspection on March 29 throuah June 2. 1993 (Recort No. 50-341/93007(DRS))
Areas Inspected:
Routine, announced inspection to assess control and implementation of plant design changes, and corrective actions (IP 37700).
The inspection focused on the High Pressure Coolant Injection and Standby Feedwater systems.
Results: One violation with two parts was identified.
The violation concerned a lack of corrective action for a water hammer event and the failure to document the cause and corrective actions for an increased level of water
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contamination in the HPCI lube oil system.
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DETAILS 1.0-Persons Contacted Detroit Edison Company l
D. R. Gipson, Senior Vice President
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R. McKeon, Plant Manager
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P. Fessler, Technical Manager
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I J. Walker, Director, Plant Engineering W. Miller, Director, Nuclear Licensing V. S. Nuclear Reaulatory Commission (NRC)
B. L. Burgess, Chief, Operational Programs Section W. Kropp, Senior Resident Inspector The above individuals and other licensee and NRC individuals attended
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the exit interview on May 13, 1993. On June 2, 1993, a telephone exit was held with Mr. Fessler and others of your staff to discuss additional technical and regulatory issues.
Other individuals were contacted during the course of this inspection.
2.0 Introduction
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The objective of the inspection was to assess the licensee's engineering _.
and technical support activities. The effectiveness of the engineering organization in the performance of routine and reactive site activities was evaluated, including the identification and resolution of technical issues and problems. The inspection focused on the High-Pressure Coolant Injection (HPCI) and Standby Feedwater (SBFW) systems.
3.0 Permanent Desian Chances (PDC)
3.1 PDC 13623 During the review of PDC-13623, the corrective action document addressing repetitive motor failures for the HPCI Discharge Test Isolation Valve (MOV E4150F008), the inspectors noted that numerous DERs, EDPs and PDCs have been issued since 1984. 'In response to each motor failure, the licensee generated a number of documents, including DER 88-734, DER 90-0140, DER 92-0610, DER 92-0647, EDP-13464, EDP-13623, and PDC-13623. The motor for this valve operator has been replaced at least four times because'of motor burnout.
The following concerns were identified during review:
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A Part 21 report, issued by the vendor to address deficiencies in
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the motor insulation (RH) used on the new valve motor, resulted in the licensee placing it on the Restricted Engineering Component
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List (RECL). The RECL procedure required an evaluation and approval by engineering prior to use of the motor. This engineering evaluation and approval was not performed prior to motor use. The inspector questioned the controls used for equipment placed on the RECL, and whether additional RECL equipment had been installed in the plant.
A subsequent evaluation determined that RH insulation was acceptable for the installed motor environment.
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In late 1992, a MOV engineer evaluated the existing valve design parameters and determined that no additional engineering was required. Concurrently, a mechanical engineer performed a review and issued a PDC 13623 that recommended solutions and proposed dispositions. Had these recommendations been followed, the potential for identification of the cause and possible resolution to the motor failure problems was fairly good.
Furthermore, the HPCI plant engineer was not fully aware of planned corrective actions listed in the PDC. This issue raised concerns regarding the communication among engineers with common responsibilities to resolve system problems.
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During post-modification testing, after the motor was replaced, station engineers observed some unexpected valve cycling.
To temporarily address this problem, the engineer modified the operating logic of the valve and added the following note to the
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operating procedure, "in remote manual operation, upon indication of the closed-only indicating light, the operator shall remove his/her finger from the closing push button to prevent motor burnout." During discussion of this procedure with the licensee, an exact amount of time between release of the closing push button and motor failure was not determined, but was approximated as a few seconds.
If the operator became distracted by another alarm during closing of this valve operator, the valve motor could fail.
Based on this sequence, the inspectors concluded that reliance on the control room operators for safe motor operation was too
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dependent on operator judgement.
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Valve MOV E4150F008 has been used as a throttle valve. However, the vendor recommended that this valve was not suitable for j
throttle valve operation.
Based on the inspectors review, the licensee did not fully evaluate the vendor's recommendation.
3.2 EDP 13229 The EDP eliminated nuisance actuations of the HPCI Pump Suction High Al arm.
Section 10, pages 1 and 2 of the EDP delineated the detailed
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post-modification testing requirements; however, Part 10 of WR 000Z922036 documented the post-modification test steps to be performed.
Part 10 contained a statement that the test was accomplished "as per telecon with the NASS." No documented test signoffs were available to indicate that the test requirement steps were accomplished successfully.
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4.0 Licensee Corrective Actions The inspectors reviewed the following Deviation Event Reports (DERs),
and assessed licensee corrective actions.
4.1 DER 91-0889 This DER addresssed steam observed during the venting of a portion of the HPCI pump discharge piping on November 27, 1991.
During a followup surveillance test on February 13, 1992, three axial' pipe restraints were found pulled out from the wall due to water hammer effects and DER 92-0063 was issued.
DER 91-0889 was closed on September 10, 1992, after completion of the applicable corrective actions for DER 92-0063.
4.2 DER 92-0063
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This DER was issued on February 13, 1992, and closed on December 29, 1992. The cause of the HPCI discharge piping restraint. failures was determined to be a flow into void type water hammer. The licensee believed that the discharge pipe was being heated.to above 200 by the conduction of heat through the feedwater injection valve E4150F006, in close proximity to the HPCI steam line. When a vent path was opened,
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the water in the pipe would flash to steam.
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During Refueling Outage 2 (March 30 to June 10, 1991), the Feedwater (FW) injection valve was tested and.found to have.25 gpm leakage h
through the valve seat compared to the 1.0 gpm Technical Specification i
allowable.
Review of test records from November 1984 to October 1992-indicated that the valve seat was leaking at a rate between 0.02 and 0.06 gpm.
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The DER stated that five venting operations and two surveillance tests =
were performed from February 13 to September 1, 1992, and a water hammer
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event was not observed. The lack of a subsequent water hammer event formed the basis for closing the DER. The inspector retrieved the j
venting and test records, and observed that since February 13, 1992, when restraint damage was identified after a test, to September 1,1992, there had been eight venting and two surveillance tests performed.
The first surveillance test was done on May 9. 1992, one day after the
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venting, and the second test was dona July 29, 1992, the same day of the venting.
The inspectors concluded that both surveillance tests were pre-conditioned by completion of system venting, and that a water hammer could not occur.
An NRC walkdown of the HPCI system on April 27, 1993, identified several
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anchor bolts pulled out from wall. The licensee's followup inspection identified that all three restraints previously found loosened in DER 91-0889, plus restraint E41-3169-G10, located on the HPCI pump test
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line, were pulled away from the wall. Walkdown of the piping system and valve stroke tests performed by the licensee did not reveal additional deficiencies. HPCI was declared inoperable on April 27, 1993, and the NRC was informed via a 10 CFR 50.72 call.
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d The licensee met with the inspectors on April 28,.1993, to discuss proposed short term fixes to the water hammer problem. The licensee stated that all of the loosened bolts were re-torqued to specification and that venting of the HPCI discharge line will be performed for at least 30 minutes each week to minimize any steam void formation.
During this meeting, the inspector questioned the basis for the seven day interval. The licensee was unable to provide a technical basis for the interval; however, indicated that in addition to venting, a walkdown will be performed after each HPCI pump run. The proposed long term fix
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will include a method to stop valve back leakage from the feedwater system into the HPCI discharge piping. HPCI was declared operable on April 28, 1993.
On May 12, 1993, the inspectors reviewed the venting and test records i
for the period September 1, 1992, through April 27, 1993,' and identified seven venting operations, two surveillance tests, and one HPCI i
actuation.
In addition, the HPCI test line to CST boundary valve (F008)
was found to be less susceptible to leakage due to an increase in the MOV close torque switch setting.
The first test was done on November 6, 1992, four days after
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system venting.
HPCI actuation occurred on November 18, 1992, without prior
venting of the system.
The second test was done on January 15, 1993, 14 days after system
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venting.
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The restraint damage identified by the NRC in April could have occurred during any, or all, of the above events due to temperature and pressure buildup between the feedwater injection valve F006, the test line.
boundary valve F008, and the HPCI pump discharge line check valve F005.
During the opening of F008, the pressure within these lines is released and flashing and void formation would occur, causing a water hammer. No i
restraint damage was identified by the licensee because the corrective actions required by DER 92-0063 were completed in September 1,1992, and system walkdowns were no longer performed after each test or system actuation.
On May 5, 1993, the licensee re-tested the system after the restraint failure identified by the NRC on April 27, 1993. Also, the test was performed after a seven day waiting period following the venting of the system. Water hammer was observed by the licensee during the test, and all four restraints that had failed previously, failed again.
During the performance of torquing checks recommended by the inspectors, the licensee found one~ additional loosened bolt on a pipe restraint. The system was again declared inoperable.
On May 6, 1993, a modification was completed to three of the five failed restraints by replacing the existing bolts with a larger size bolt. The two remaining restraints were torqued to design specifications
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ff On May 7, 1993, the licensee re-tested the system with a revised surveillance procedure. The HPCI surveillance test started with the min-flow valve open, and the test line valve closed. After the pump started and line pressure increased to normal operating pressure, the test line valve was opened and the min-flow line closed. No water hammer was observed, and the system was declared operable.
Prior to the conclusion of the inspection, the licensee issued a calculation, DC 2660, HPCI Pump Discharge Piping Operability Evaluation, j
Revision 0, dated May 12, 1993. The inspector reviewed the analytical i
methods, assumptions, modeling of the system, and acceptance criteria, and had no adverse comments.
However, this operability evaluation should have been done in-February 1992, when the licensee first identified the restraint _ damage.
The lack of timely completion of corrective action for a condition adverse to quality, the water hammer event of February 1992, is considered to be a violation of 10 CFR 50, Appendix B, Criterion XVI (341/93007-Ola).
4.3 DER 91-0787 In October 1991, a sample from the HPCI turbine lube oil system was found to have 2.4 percent water and sediment, above the procedural requirement of 0.5 percent. A DER was issued on October 4, 1991, and closed on February 6, 1992.
A program to evaluate oil samples and trend water contamination levels had been implemented in January 1991.
After identification of water contamination levels in excess of 2.4 percent on October 4, 1991, the licensee deleted the procedural requirement of 0.5 percent on November 13, 1993.
_This action was based on proven HPCI operability due to the successful completion of several HPCI surveillance tests with known water contamination levels in excess of 0.5 percent. However, no evaluation was performed to determine the potential consequences of the long term effects of excessive water contamination in the HPCI pump lube oil system.
Oil samples taken on November 22, 1991, indicated 1.2 percent water contamination, and 0.6 percent water contamination after oil purification was performed to the system on the same day.
The procedural requirement for water and sediment level in excess of 0.5 percent was reinstated on September 10, 1992.
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The cause of water contamination in the HPCI lube oil system was determined to be a HPCI pump turbine steam gland seal leak. The licensee stated in their corrective action to the DER dated November 5, 1991, that since the steam gland seal clearances change during turbine warm-up and operation, adjustment to prevent steam and water flow into the oil system is very difficult. A more practical approach is to periodically drain off accumulated water. The frequency of draining accumulated water will be determined empirically and adjusted over time.
However, draining of accumulated water did not stop the steam gland seal leakage into the lube oil system.
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4.4 DER 91-0878 Issued on November 20, 1991, this DER addressed the failure of HPCI.to start during a surveillance test.
Licensee root cause analysis-and investigation identified the Woodward Governor as the malfunctioning component preventing HPCI start. The hydraulic actuator within the governor was found stuck in place, and prevented the HPCI turbine
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governor control valve from opening.
Subsequent inspection by the vendor identified rust and moisture as the contributing factors to the stuck hydraulic actuator. Water contamination in the HPCI lube oil system was identified as the source of the moisture found in the hydraulic actuator.
A licensee evaluation dated December 19, 1991, identified that the HPCI barometric condenser vacuum pump, which collects and condenses steam leakage from the HPCI turbine shaft seals, stop valve and governor
control valve steam leak-offs, was not providing sufficient vacuum to prevent steam condensate leakage into the control and lube oil systems.
As a result, the barometric condenser vacuum pump was replaced.
Additional inspection of the HPCI turbine identified that HPCI turbine gland seals and lube oil system sealing components (carbon rings and dust collar) were degraded.
The degraded components were replaced.
Each of these components could have contributed to the water contamination in the lube oil system
During discussions with system engineers, and review of the equipment concerns list, the HPCI steam inlet valve (F001) was found to be leaking.
Leakage of condensate and steam past this valve created'a moisture environment within the turbine internals, contributing to the
failure of six HPCI gauges. Although the gauges were fixed and F001
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repaired, the valve leakage problem, the failure of the six gauges and the corrective actions taken to repair the valve and the gauges, were
not included as an update to the above DER. Without documenting the valve leakage problem and the subsequent failure of the gauges, in
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addition to the corrective actions taken to repair these problems, the potential exists that leakage past past F001, and the subsequent impact on system gauges, could go unrecognized.
10 CFR 50, Appendix B, Criterion XVI requires that the identification of significant conditions adverse to quality, the cause of the condition, and the corrective action taken shall be documented.
The failure to document the cause and corrective actions for a significant condition adverse to quality, the leakage past F001, is considered an example of a violation of Criterion XVI to 10 CFR 50, Appendix B (341/93007-Olb).
During the review of this DER, the inspector identified that the amount of work. assigned to several system engineers could be excessive.
In the past, the HPCI system, in addition to other plant systems, was assigned to a single system engineer.
Based on interviews with past HPCI SEs, the number of problems that occurred on the HPCI system alone could
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occupy one person full time.
The burden of additional systems assigned
to the HPCI system engineer may have contributed to the slow resolution of HPCI system problems including the water contamination of the HPCI I
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lube oil system and the water hammer events. At present, the HPCI system is distributed among four SEs.
An additional concern identified during review of this DER was the i
communication paths available to the system engineers. Although the system engineers are apparently comfortable with contacting the appropriate vendors for problem resolution, the onsite. design ~
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engineering organization is not routinely contacted to support system engineering in resolution of system problems. During followup with the
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appropriate design engineer regarding the water contamination of the i
HPCI lube oil system, the inspector was informed that design engineering was fully aware of the problem, but had not been contacted by system
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engineering. A recent major engineering organization restructuring should improve the interaction between design engineering and system engineering.
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The DER documented a hanger bent during fill and vent of the standby
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feedwater system (SBFW). The inspecter reviewed the DER and examined the circumstances that led to this event.
A fill and vent procedure in the SBFW system, per 24.107.03 Section 5.1, required the cycling of an isolation valve, N21-03-F001. Opening of the valve caused the pipe and its support to move. The pipe moved between one-half inch to an inch and the pipe support was slightly bent.
The deviation report included a claim of pipe movement from four to six inches.
However, an engineering evaluation and analysis verified that the largest pipe movement would have been less than an inch under the specific conditions. Analysis
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also verified that the bent hanger, if it was due to this event, was
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insignificant.
Engineering involvement and evaluation of this event
were good. The analysis and the calculation appeared adequate.
4.6 DER 93-007 Between 1989 and 1993 there were 26 work requests issued to repair two-inch drain valves in the Division 1 Non-interrupting Air Supply (NIAS)
prefilters.
The repairs required unclogging valves P5000F539A & B,
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located on the bottom of the NIAS dryer prefilters.
Clogging of these valves had the potential impact of raising water level in the air supply dryer prefilters, ultimately making the NIAS inoperable.
Repeated clogging of the valves prompted maintenance staff to issue DER 93-007 and DER 93-008, requesting design changes for these valves.
Plant engineering evaluated these DERs and determined that the design changes for these valves would be accomplished consistent with the priorities of
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the plant's five-year plan. The plant manager intervened and requested
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an Urgent Design Change to be completed by August 1993.
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4.7 QER 92-0068 Erratic operation of HPCI barometric condenser pump was the subject of this DER. A Nuclear Power Plant Operator (NPPO) had agitated the pump motor during a surveillance test to keep the motor operating even though
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visible arcing was observed from the motor's brushes.
During this erratic operation, the motor ammeter had full scale swings.
Subsequently, the ammeter failed downscale.
DER 92-0227 replaced the HPCI barometric condenser pump motor and problems with brush and commutator wear were found. Another problem was caused because the
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motor leads on the new motor were too short.
Ordering information for the new motor had not been updated to reflect actual requirements. The agitation of malfunctioning plant equipment during a surveillance test can lead to adverse consequences.
However, this was the only instance identified during this inspection.
During discussions with plant management prior to and during the exit, the inspectors were informed that plant management would not condone this attitude toward plant equipment.
4.8 DER 91-0188 and GE SIL 531 This DER required replacement of an 0-ring on the HPCI Steam Line Drain Pot Level Switch every two years.
This was done in response to GE SIL 531 recommendations.
Preventive Maintenance (PM) was initiated in May 1991, to change the 0-rings. However, in June 1992, a Corrective Maintenance (CM) work request was initiated to repair, calibrate and perform a functional check on the HPCI Drain Pot Level Switch. The licensee erroneously took credit for the completion of the CM activity as an activity that also satisfied the PM requirement. However, the CM did not replace the 0-ring.
The inspectors questioned the CM activity, and as a result, the 0-rings were replaced on May 6, 1993. Additionally, DER 93-0242 was written to determine the operability of this instrument.
Licensee review of other PMs credited as completed by the performance of an associated CM work request found no additional deficiencies or operability concerns. The inspectors determined that this problem resulted due to miscommunication between maintenance and system engineering.
4.9 DER 93-0053 This DER identified high resistance on HPCI relay contacts during a surveillance test.
The inspectors reviewed the DER and identified the following concerns:
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No acceptance criteria for contact resistance was specified in the surveillance procedure.
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No requirement existed for documenting the as-found data during the surveillance.
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There was no trend data available for review, even though the DER stated, "This event will be trended by the DER Program."
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No PM program existed to generically address high relay contact resistance (GE SIL 332 recommended a relay and contact cleaning procedure).
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The inspectors noted that similar contact resistance problems were identified in 1989 on a HPCI relay. Also, DER 93-0029 was issued to address an inadvertent HPCI auxiliary oil pump trip.
Dirty CMC contacts were suspected as the cause of trip.
To address this concern, a Nuclear Generation Memorandum dated May 13, 1993, was issued, which provided guidance and acceptance criteria for relay contact resistance.
4.10 Information Notice 84-20 This information notice (IN) concerned service life of relays in safety related systems. _The licensee's original review of IN 84-20 did not identify all safety related, normally energized Agastat GP relays at Fermi. Consequently, PMs were not created for some of these relays.
On January 4, 1993, relay E41A-K92 failed on demand. This relay failure prevented both manual and automatic actuation of the HPCI Steam Inlet Valve E41-F001. HPCI was declared inoperable and LER 93001 was issued.
5.0 Root Cause Analysis (RCA)
The Independent Safety Evaluation Group (ISEG) assigned cause codes to all DERs; however, it was not evident that the ISEG review is being utilized by management and design and system engineering for identifica-tion of adverse trends.
The licensee's Deviation and Corrective Action Reporting procedure FIP-cal-01, Revision 12, required that a root cause analysis be performed on a DER only if the DER involves a "significant condition adverse to quality, that if uncorrected would have a serious effect on safety or operability." Review of various DERs indicated that many documented equipment failures and problems were not designated significant conditions adverse to quality; consequently, no root cause analysis was required.
Examples included DERs 92-0062, 92-0068, 93-0003, and 93-0053. The apparent cause was because the trend data base used by ISEG was not user friendly. The inspectors were informed that a more comprehensive trending program was in the progress which should address concerns in this area.
During review of the engineering training program, specifically on root cause analysis, the inspectors determined that 400 individuals received training on root cause analysis techniques.
However, recently completed licensee Audit 93-0115 identified that 2 out of 7 completed DERs and 5 of the open DERs had root cause analyses performed by individuals that were not qualified in accordance with the training program.
However, review of the DERs by individuals trained in root cause analysis techniques did not identify any discrepancies. The licensee is in the process of upgrading the root cause analysis training program based on audit and NRC findings.
6.0 Review of Electrical Desian Drawings and Field Installations The inspectors performed a design review of the schematic, wiring and logic diagrams for HPCI Steam Supply Valve E41-F001.
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inspectors performed a field inspection of selected portions of 250Vdc MCC 2PB-1, HPCI relay cabinet H13-P620, instrument rack H21-P014 and termination cabinet Hil-P821. The inspectors examined as-built configuration relative.to the design drawings including modifications.
The review and inspection indicated that the design drawings reviewed
conformed to engineering requirements and field installations were in conformance with the design drawings.
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During the field inspection, the inspectors noted that the flexible conduit to limit switches of valve E41-F068 was broken and separated from the coupling. The 1 n.ensee promptly wrote WR 2931684 to address the problem.
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7.0 MOV Thermal Overload Protection Fermi had sized MOV thermal overloads on safety related systems using the philosophy that operation of the valve motors when needed superseded any concern with degradation or failure of the motor due to excess heating during a locked rotor amps (LRA) condition.
IEEE 741, issued in 1992, changed the old practice of allowing the motor to burn on LRA and recommended that safety related motors be protected on LRA conditions.
The licensee has recently changed thermal overload protection for valve E4150F008 and installed a smaller size thermal overload heater element to protect the motor on LRA. However, this philosophy has not been adopted for other safety related MOVs. The inspectors informed the licensee that consideration should be given to re-sizing the safety related MOV thermal overloads as PM activities are performed.
8.0 Licensee System Enaineers Performance The inspectors interviewed system engineers, examined the assignment of
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responsibilities and recent redistribution of systems among various system engineers. The inspection resulted in minor concerns involving recent reassignments of single sy. stem responsibilities among several system engineers, or the assignment of primary responsibility for several complex systems to one system engineer. Also, some apparent uncertainties existed concerning which system engineer, if any, would be contacted if a problem occurred in a particular system.
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9.0 Review of Licensee Audit Reports Several audit reports were reviewed, including an audit of the Power Uprate modification.
The review of the power uprate modification exhibited excellent engineering involvement and thorough and comprehensive engineering evaluations.
Excellent coordination was identified between the plant, corporate and contract organizations.
Another QA audit reviewed related to a lack of independent audits performed by the Special Nuclear Material Manager (SNMM) for inspections completed by the site special nuclear material custodian. 'Specifically, the missed audit by the SNMM was for a semi-anrual audit of SNM material g
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inventories in the spent fuel pool. The inspectors evaluated corrective actions in response to the audit finding an found them to be adequate.
The inspectors reviewed licensee audits performed in 1992 and 1993 in the area of corrective action program implementation, and concluded they were mostly programmatic in nature and lacked in-depth technical evaluation of the areas inspected.
This issue had been identified by a independent third party and by the licensee.
During discussions with the QA manager, changes are planned to provide more indepth technical audits of the various plant programs reviewed.
10.0 Exit Interview The inspectors met with the licensee representatives (denoted in Paragraph 1) on May 13, 1993, at the conclusion of the inspection.
The inspectors summarized the purpose and findings of the inspection. The inspectors also discussed the likely informational content of the inspection report with regard to documents or processes reviewed during the inspection.
A discussion regarding additional regulatory and technical issues was held between the NRC and licensee representatives on June 2, 1993.
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