IR 05000331/1993017
| ML20059B351 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 12/20/1993 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20059B343 | List: |
| References | |
| 50-331-93-17, NUDOCS 9401040093 | |
| Download: ML20059B351 (14) | |
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i U. S. NUCLEAR REGULATORY COMMISS10t1 REGI0ti-III
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Report tio. 50-331/93017(DRP)
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Docket tio. 50-331 License fio. DPR-49
Licensee:
Iowa Electric Light and Power i
Company IE Towers, P. O. Box 351
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Cedar Rapids, IA 52406
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Facility flame: Duane Arnold Energy Center I
. Inspection At:
Palo, Iowa Inspection Conducted: October 15 through liovember 23, 1993 i
I Inspectors:
J. Hopkins
.'i C. Miller
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-Approved:
Id 2n @T R. D. Lanksbury, fiTeT
' Da".e Reactor Projects 3ection 3B
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t Inspection Summary inspection on October 15 throuah tiovember 23.-1993
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(Report flo. 50-331/93017(DRP))
Areas Inspected:
Routine, unannounced inspection by the resident inspectors of followup, licensee event reports followup, followup of events, operational
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safety, maintenance, surveillance, plant trips, regional requests, and report review.
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Results:
An executive summary follows:
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9401040093 931220
PDR ADDCK 05000331 G
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l-l EXECUTIVE SUMMARY Plant Operations The plant was operating at about 25 percent power at the beginning of the period, with scram time testing in progress. After power ascension, the
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reactor operated at about full power until October 26, 1993, when a scram occurred-due to a turbine control valve closure.
Following startup from the -
scram, the reactor operated up to full power during the remainder of the period.
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Failure of an operator to check reactor building crane hook clearance led to a t
collision of the main hook with the refueling bridge. The bridge sustained
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minor damage.
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Control room improvements have significantly reduced noise and distractions.
l Maintenance / Surveillance Contir.uing problems with both control building chillers eventually led the licensee to declare both chillers inoperable, and enter a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> administrative limiting condition for operation (LCO). A team consisting of the vendor representative, system engineer, and maintenance mechanics tested
and repaired both chillers within applicable LC0 time allowances.
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Troubleshooting and repair efforts for the turbine control valve (TCV) closure were timely and well coordinated.
Enaineerina System Engineering effort to coordinate troubleshooting and repair activities
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for the control building chillers was substantial, and effectively utilized
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operations, maintenance, and engineering resources.
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DETAILS k
1.
Persons Contacted
- J. Franz, Vice President Nuclear
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- D. Wilson, Plant Superintendent, Nuclear
- R. Anderson, Operations Supervisor r
R. Anderson, Outage Project Manager R. Baldyga, Supervisor, Maintenance Engineering
- P. Bessette, Supervisor, Regulatory Communications
- J. Bjorseth, Maintenance Superintendent D. Blair, Quality Assurance Assessment Supervisor C. Bleau, Supervisor, Systems Engineering
- D. Engelhardt, Security Superintendent
- R. Hannen, Outage Manager C. Kardos, Supervisor, Reactor and Computer Performance
- J. Kinsey, Licensing Supervisor J. Kozman, Supervisor, Configuration Control Engineering
- D. Lausar, Supervisor, Project Engineering
- J. Loehrlein, Engineering Supervisor i
- M. McDermott, Manager, Engineering
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- K. Peveler, Manager, Corporate Quality Assurance K. Putnam, Supervisor, Technical Support
- A. Roderick, Supervisor, Testing and Surveillance P. Serra, Manager, Emergency Planning -
- N. Sikka, Supervisor, Electrical Engineering A. Steen, Assistant Operations Supervisor S. Swails, Manager, Nuclear Training
- J. Thorsteinson, Assistant Plant Superintendent, Operations Support
- G. Van Middlesworth, Assistant Plant Superintendent, Operations and Maintenance
- T. Wilkerson, Radiation Protection Manager
- K. Young, Manager, Nuclear Licensing In addition, the inspectors interviewed other licensee personnel including operations shift supervisors, control room operators, engineering personnel, and contractor personnel (representing the licensee).
- Denotes those present at the exit interview on November 23, 1993.
2.
Followuo (92701)
a.
(Closed) Unresolved item 50-331/91017-05:
Bypassing of Average
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Power Range Monitors (APRMs).
This unresolved item was issued to evaluate the licensee's practice of bypassing two out of six APRM channels during extended periods of power operation.
Technical Specification (TS) bases Section 3.1 indicated that each reactor protection trip system had one more APRM than is necessary to meet 3..
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the minimum number per channel to allow bypassing-an APRM in each I
channel for. maintenance, testing, or calibration.
The minimum i
number required by TS was two per channel, or four APRMs.
The licensee chose to keep two APRMs (A and D or B and C) with shared local power range monitor (LPRM) inputs bypassed on a long term basis to prevent inadvertent LPRM or power supply spiking
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from causing a reactor scram. This practice was described in
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Section 7.6 of the June 1992 revision to the Updated Final Safety Analysis. The licensee replaced the voltage regulators in the LPRM power supplies with a new design during refueling outage:12.
The new design should prevent.LPRM spiking when re-energizing the
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reactor protective system, and thus improve LPRM performance, as indicated by the licensee in a January 3, 1992, response to
. inspection report 50-331/91017.
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In addition, the licensee was finalizing a submittal request for a
TS revision to clarify the practice of continuous use of APRM
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bypass, similar to that granted by the NRC to another utility.
The technical review of this submittal by NRR will determine the acceptability of this practice on a long term basis. This unresolved item is closed.
b.
(Closed) Unresolved item 50-331/92017-02:
Failure To Perform Operator Rounds and Fire Watch. This unresolved item (URI)
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resulted from the inspection conducted under Temporary Instruction (TI) 2515/115, " Verification of Plant Records." The T1 addressed the potential for incomplete or inaccurate records at licensed facilities. The NRC reviewed this issue as an industry wide
concern and summarized the results in Generic Letter (GL) 93-03,
" Verification of Plant Records." Based on this review, a Notice
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of Violation was issued to the Duane Arnold Energy Center on
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October 15, 1993, for failure to maintain complete and accurate
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records, such as log keeping. Because the licensee identified the violation and the corrective actions were adequate to prevent
. recurrence, no response was required. Two related items were closed in inspection report 331/93012 (URI 331/92022-01 and licensee event report 331/92-017). This unresolved item is closed.
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(Closed) Unresolved Item 50-331/91019-02i Missing Backdraft.
Dampers. This unresolved item was issued to review the adequacy i
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of control building ventilation systems in light of numerous ~as-
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built discrepancies which had been discovered.
Corrective actions
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for these problems, including system walkdowns, are discussed in
section 3 of _this report. This unresolved item is closed.
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. No violations or deviations were identified in this area.
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3.
Licensee Event Reports Followup (92700) (90712)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, immediate corrective actions were accomplished, and corrective actions to prevent recurrence had been accomplished in accordance with technical specifications.
a.
(Closed) Licensee Event Report (LER)91-012 (331/91012-LL):
Reactor Water Cleanup (RWCU) Isolation Due to Deformed Connector Contacts. This LER documented a RWCU isolation due to sensed high differential flow in the system. This false signal occurred when an operator returned a RWCU flow summer module to its full in position in the instrument rack.
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Technicians discovered a bent alignment and retaining plate which applied opposing fcrce against full insertion of the module,- and l
which also inhibited alignment of the ribbon connector for the module. This misalignment apparently was the cause of bent
contacts found on the connector at the rear of the summer module.
Initial corrective actions involved reseating the ribbon connector, reinserting the module, and restoring the RWCU system
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to service.
Initially, the licensee hung a warning tag to alert operators to a potential for a RWCU isolation.
Later, technicians repaired the connector and the alignment plate, and verified circuit integrity at various summer module positions in the rack.
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The warning tag was then removed. The operator involved also provided other operators with a lessons learned brief on care in operation of these instruments. This LER is closed.
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(Closed) Licensee Event Report (LER)91-013 (331/91013-LL):
Lack of Backdraft Dampers in Standby Filter Units.
This LER documented backdraft dampers which were designed to be in the discharge ducts of each standby filter unit (SFU) train, but were never installed.
A loss of air or control power to a SFU would have caused its
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isolation dampers to fail open. Had this occurred with one SFU in
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standby mode and one in run, some of the discharge from the running SFU would have short cycled back through the failed.open I.
isolation dampers of the standby unit.
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Inspection reports 331/93016 and 331/9101') documented the licensee's initial corrective actions, including implementation of I
a special order for manual actions needed to ensure SFU
operability, and a special test which was performed to evaluate
the as-found condition of the system. The licensee installed the
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missing backdraft dampers during refueling outage 12, and tested them satisfactorily on August 25, 1993.
The licensee completed a system walkdown of all safety-related duct work which was installed by the vendor who initially failed
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to install the backdraft dampers.
Results of this effort were documented in'a July 27, 1992, letter from Systems Engineering.
This walkdown discovered other discrepancies of system configuration as compared to the piping and instrumentation diagrams. The licensee evaluated each discrepancy and determined that the as-built configuration was acceptable.
The inspectors agreed that the licensee's evaluation of the as-built discrepancies appeared reasonable. However, the inspectors noted that the evaluations were not well documented, and the design-document changes, which were initiated approximately a year ago to correct the drawings, were not yet completed. This LER is closed.
c.
(Closed) Licensee Event Report (LER)92-015 (331/92015-LL):
Low Pressure Coolant injection (LPCI) Subsystem Inoperable Due to Personnel Error and Procedure Inadequacy. This LER documented the loss of power to the bus which supplied power to LPCI components (LPCI swing bus).
During the performance of a surveillance test, an operator incorrectly opened a 125 Vdc breaker which had supplied control power to one of two LPCI swing bus breakers (184401). This caused the other swing bus supply breaker (183401) to automatically close. Upon restoration of the 125 Vdc control power, operators then attempted to transfer the swing bus back to being supplied from 184401 by opening 183401. At this point, 184401 failed to close because a reset button at the breaker had not been reset.
This left the LPCI swing bus de-energized for about 2 minutes while operators reset the breaker locally.
Following proper restoration of the system, corrective actions for.
the operator opening the wrong breaker included a detailed review of the surveillance procedure to determine the factors which led to the error. Use of one way communications via radio, lack of self checking, and problems following the procedure from the field were contributors to the problem.
Licensee management emphasized the need for clear two way communications during routine operations and surveillance testing.
The operating crew involved briefed all other operating crews on the event, the need for self-checking, and other lessons learned.
On February 26, 1993, DAEC management issued a letter describing plant wide expectations for communications.
Corrective actions for the improper resetting of the. swing bus power supply involved correcting Annunciator Response Procedures (ARPs) 1C08B D5 and D7 to identify the need to push the local reset button in order to reset breakers 183401 and 184401.
This was accomplished on September 11, 1992. This LER is closed.
No violations or deviations were identified in this area.
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4.
Followuo of Events (937021-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:
October 15, 1993 - A 2 rod by 2 rod array failed-to meet scram time to
position 46.
(See Section 7 for details.)
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October 26, 1993 - Reactor scrarc due to TCV closure.
(See Section 8
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for details.)
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October 27, 1993 - Refuel floor cane impacted refuel bridge during spent fuel pool cleanup project.
November 11, 1993 - Entered 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> administrative LC0 due to both
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control building chillers being inoperable.
j Reactor Buildino Crane and Refuelina Bridae Collision
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On October 27, 1993, while the auxiliary hook of the reactor building
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crane was being used to transfer a load in the spent fuel pool (SFP),
the main hook of the crane impacted the DC-300 control cabinet on the
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refueling bridge. The DC-300 cabinet provided control and diagnostic
functions for the refueling bridge. The force of impact sheared the
nine one-quarter inch bolts which attached the cabinet base to the l
bridge structure, and tipped the cabinet forward. The crane and the load being transferred sustained no damage.
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The cause of the event was personnel error in that the crane operator failed to ensure that the main hook would clear all obstructions. - The
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operator had operated the main hook. prior to the event, but had not placed it in the full up position prior to maneuvering with the
auxiliary hook.
i Besides shearing the hold down bolts, and very minor denting of the cabinet cover, the DC-300 cabinet appeared unharmed. The inspectors and
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licensee examined the cabinet internals and. found no apparent signs of
damage.
Pieces of seven of the bolts which sheared,.however,. fell into.
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the SFP. One of the pieces was observed in between a spent fuel bundle
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and the SFP rack.
The licensee plans to inspect the SFP for the sheared bolts following
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the SFP cleanup project which is currently underway.
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maintenance to rebolt the cabiet, inspections and surveillance testing
of the refueling bridge revealev that all. tested functions were working l
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properly.
Some functions could not be tested until the next refueling
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outage. The licensee will track the final corrective actions on bridge testing and SFP cleanup under Quality Deficiency. Report number 93-188.
Licensee actions to prevent a future collision included:
refuel floor crew discussions with management on the details of the event, informal.
implementation 'of requirements for using an auxiliary signal man to
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verify that crane clearances are adequate prior to use, and use of radio head phones for the crane operator and signal man. A procedure change
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was also implemented to require a hook which is not in use to be in the full-up position. The licensee was still considering installation of a hardware change to the reactor building crane console to indicate full-
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1; up hook position.
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No violations or deviations were identified in this area.
5.
Operational Safety Verification (71707) (71710)
The inspectors observed control room operations, reviewed applicable logs, and conducted discussions with control room op3rators during the
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inspection. 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.
It was observed that the Plant Superintendent, Assistant Plant Superintendent of Operations, and the Operations.
Supervisor were well-informed of.the overall status of the plant and that they made frequent visits to the control room. The inspectors, by
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observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan.
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The inspectors observed plant housekeeping and cleanliness conditions and verified implementation of radiation protection controls.
These reviews and observations were conducted to verify that facility.
operations were in conformance with the requirements. established under
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technical specifications, Title 10 of the Code of~ Federal Regulations, and administrative procedures.
Control Room Imorovements The inspectors noted continued improvement in the shift turnover process. Thorough panel walkdowns and concise crew briefings with no distractions have become the norm. The shift supervisors, on occasion, have moved the crew briefing out of the control room when it was determined that the briefing would detract from critical plant evolutions.
The recent addition of a tagout window in the shift supervisor's office served to. keep traffic out of the control room proper.
This, in combination with stricter controls on control room and control panel area access, has significantly improved the ability of the.
operators to maintain a quiet work space with a minimum of distractions.
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t The licensee was completing efforts to remodel the control room and to l
implement stricter standards on operator attire at the close of the period.
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No violations or deviations were identified in this area.
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6.
ILonthly Maintenance Observation (627031 j
Station maintenance activities of safety-related systems and components
listed below were observed and/or reviewed to ascertain that they were.
conducted in accordance with approved procedures, regulatory guides, and
industry codes or standards, and in conformance with technical
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specifications (TS).
The following items were considered during this review:
the limiting 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 i
inspected as applicable; functional testing and/or calibrations were
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performed prior to returning components or systems to service; quality
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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.
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Work requests were reviewed to determine status of outstanding jobs and to assure that priority was assigned to safety-related equipment maintenance which might affect system performance.
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"A" control building chiller repairs
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"B" control building chiller repairs
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"B" main intake coil repairs
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- Refueling bridge inspection and repairs l
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- 1C2198 primary containment radiation monitoring panel solenoid
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replacements
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Control Buildino Chillers
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On October 20, 1993, the "B" control building chiller tripped due to low oil temperature. This placed the plant in a 30 day administrative-(not i
required by TS) LCO. Duane Arnold's "Special Order" number 92-47, dated-l November 15, 1992, detailed the administrative controls for the chiller,
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which were similar to TS.
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Repa'
to the chiller consisted of cleaning and replacing the valve internals of the 3-way temperature control valve (TCV) 6924B. The i
licensee determined that the root causes for the low oil temperature were silt in the upper diaphragm of TCV-6924B and worn valve internals
which allowed TCV-6924B to stick in one position. The "B" chiller again
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tripped on low oil temperature on October 2B during post-maintenance
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testing. The control spring for TCV-6924B was adjusted and post-maintenance testing was completed satisfactorily. The "B" chiller was returned to service on October 29.
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On November 3 the "B" chiller tripped on low oil level during startup.
The plant again entered the 30 day administrative LCO. After a
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discussion with the vendor and adding oil to the
"B" chiller, the
chiller was restarted for additional diagnostic testing. The "B"
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chiller was considered inoperable.
On November 11, with the plant at approximately 100 percent power, the
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"A" chiller tripped. This placed the plant in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> ad:ainistrative LCO in accordance with the special order 92-47 due to both control
building chillers being inoperable.
l A team comprised of a vendor representative, the system engineer, and
maintenance mechanics worked with operators to test and troubleshoot
both chillers.
Repairs to the "A" chiller included cleaning the 3-way
temperature control valve, applying thermogrease to the oil cooler
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temperature control valve probe and inserting it properly, and adjustment of the expansion valve to prevent floodback of_ refrigerant to
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the compressor. After a satisfactory performance test and the addition of increased monitoring using a chart recorder, the "A" chiller was
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declared operable.
This action restored the licensee to a 30 day admi + tn,tive LCO due to the "B" chiller being inoperable.
Repa:
t the "B" chiller included greasing and properly installing the oil n
=ce temperature control valve probe, adjustment of the expansion valve o Nevent floodback, and removal of approximately 140 pounds of freon.
'screased monitoring of parameters using a chart recorder was implemented for the "B" chiller, and it was tested satisfactorily and declared operable. Additional maintenance was planned to correct the performance of the hot gas bypass valve when parts become available.
The degraded condition of this valve put an increased load on the chiller, but the licensee had evaluated that the effect of this load was
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not significant. The licensee had also planned to implement increased preventive maintenan n frequency for components such as the 3-way bypass valve and oil cooler temperature control valve probe.
Following completion of maintenance on the control building chillers, the inspectors verified that they had been returned to service properly.
l The inspectors will continue to monitor control building chiller performance and the licensee's corrective actions.
No violations or deviations were identified in this area.
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Monthly Surveillance Observation (61726)
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The inspectors observed TS required surveillance testing and verified that testing was performed in accordance with adequate procedures, that test instrumentation was calibrated, that limiting conditions for
operation were met, that removal and restoration of the affected components were accomplished, that test results conformed with TS and procedure requirements and were reviewed by personnel-other than the
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individual directing the test, and_ that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
i The inspectors witnessed portions of the following test activities:
STP-43D002
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Scram Insertion Time Testing.
STP-45D003-A -
High Presure Coolant Injection System Simulated I
Automatic Actuation.
STP-48A001-M -
Standby Diesel Generator Monthly Operability Test.
STP-48C001-Q -
Emergency Service Water Quarterly Operability Test, i
Scram Insertion Time Testina l
On October 15, 1993, at approximately 1:50 a.m (CDT), during the
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performance of STP 43D002, " Scram Insertion Time Testing," the licensee determined that two diagonally adjacent control rods in a 2 X 2 array
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were slow and caused the allowed average insertion times in TS 3.3.D.2
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for a 2 X 2 array to be exceeded.
The average scram insertion times fo.
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the three fastest control rods in the 2 X 2 array from full out to position 46 was 0.385 seconds. The TS maximum limit was 0.37 seconds.
- The TS required that the reactor be taken to cold shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if the times were exceedr The reactor was at approximately
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31 percent power while STP 43D002 Nq performed. All of the other
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control rods had been tested and nu v.3 c problems had been identified.
The licensee reviewed the TS and concluded that subjecting the plant to a shutdown transient to repair the two control' rods and then returning
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the plant to approximately 31 percent power to conduct post maintenance testing was not in the best interest of safety. The licensee contacted i
NRC management (Region III and NRR) to discuss enforcemant discretion to
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repair the scram pilot solenoid ' valves for the two control rods while-
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remaining at power..The NRC concluded that declaring the two control
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rods inoperable and taking _ the actions required by TS for an inoperable
control rod (inserting them to 00) was the best course of action to satisfy the intent of the TS. At 11:06 a.m. the two control rods were declared inoperable, and the reactor shutdown action statement for the
TS was exited. The scram pilot solenoid valves for control rods 14-23
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and 18-19 were repaired and satisfactorily tested with insertion times
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of 0.37 seconds and 0.38 seconds respectively, which satisfied the'
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2 X-2 array TS insertion 'iming requirements.
Control rod 14-23 was declared operable at approximately 4:00 p.m. and rod 18-19 was declared operable at approximately 5:22 p.m.
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No violations or. deviations were identified in this area.
8.
Plant Trios (93702)
Following the plant trip on October 26, 1993, the inspectors ascertained the status of the reactor and safety systems through observation of control room indicators, emergency system status, and reactor coolant chemistry, and discussions with licensee personnel concerning plant-parameters. The inspectors verified the establishment of proper r
communications and reviewed the corrective actions taken by the l
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licensee.
The reactor automatically scrammed on APRM high flux and turbine control j
valve fast closure signals. The closure of the turbine control valve i
caused reactor pressure and, subsequently, reactor power to increase.
The turbine control valve closure and scram took place concurrencly with l
an instrument and control technician pulling a power lead to a turbine
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control cabinet cooling fan. When the technician pulled the lead, the
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pliers he was using inadvertently touched the cabinet causing the lead
to short to ground. All engineered safety features responded as
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expected including groups II through V primary containment isolations resulting from reactor vessel level shrink during the scram.
During troubleshooting of the event, technicians found a grounded y
connector which supplied power to the fast acting solenoid-valve (FASV)
.j for TCV number three. The licensee determined that-the additional path to ground, which was developed when the cabinet cooling fan lead was i
pul%d, allowed the FASV to energize momentarily. This action caused
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the TCV to shut.
The licensee repaired the grounded connector, and verified that there were no grounds remaining on the other TCVs, stop valves, or combined intermediate valves. Plant management had contacted Region III management to indicate that the'startup would proceed, despite being in an administrative (not required by TS) limited condition for operatien due to the "B" control building chiller being inoperable.
Region.III management agreed that the licensee's course of action for repair and documentation was acceptable.
Following other minor repairs, the licensee commenced startup on October 28, 1993. The reactor was taken critical and the turbine generator synchronized to the grid on on the same day. The inspectors will continue to follow the licensee's corrective actions resulting from the scram.
No violations or deviations were identified in this area.
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9.-
Reaional Reauests (92701)
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a.
Core Shroud Inspections The inspectors responded to a request from Region III for information concerning the integrity of. core shroud welds due to-reports of core shroud weld cracking at two boiling water reactors (BWRs). During the recent refueling outage (RF0 12), DAEC e
increased the in-service inspections.to include an inner-diameter
.i visual. inspection of accessible core shroud welds with a 1 mil
wire resolution. This inspection was added in a very timely t
fashion lased on reports of shroud cracking at another BWR.
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licensee performed the inspection with the aid of'a General
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Electric representative who had observed the shroud cracks at the
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other BWR, and found no indications of cracking.
The licensee was discussing with General Electric whether further evaluations were necessary, since the welds were not brushed before examination.
Duane Arnold has injected hydrogen since 1987, resulting in very good reactor sater chemistry, but the hydrogen was not injected at
a rate thought to protect reactor vessel internals.
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was still evaluating actions necessary to ensure that core shroud
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integrity was not a problem at DAEC.
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Shift Technical Advisor Duties i
In response to a regional request, the inspectors reviewed the l
licensee's procedures and practices for use of shift technical advisors (STA) on shift. At DAEC, STAS are a dedicated shift position, separate from the shift supervisor function. They are
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not required to be in the control room at all times, but are required to be within ten minutes of the control room. The STAS-
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participate in shift functions such as turnover, log. review, and i
surveillance reviews; and take part in crew training, including-l simulator scenarios.
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10.
Report Review (90713)
During the inspection period, the inspectors reviewed the licensee's monthly operating report for October 1993. The inspectors confirmed
-
that the information provided met the requirements of TS 6.11.1.C and
.
,
No violations or deviations were identified in this area.
11.
Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Section 'l)
u November 23, 1993, and informally throughout the inspection period and. summarized the scope and findings of the inspection activities. The inspectors also discussed the likely information content of the
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inspection report with regard to documents or processes reviewed by the
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inspectors.
The~ licensee did not identify any.such-documents or
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processes as proprietary. The licensee acknowledged the findings of the '
inspection.
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