IR 05000331/1993005
| ML20036A310 | |
| Person / Time | |
|---|---|
| Site: | Duane Arnold  |
| Issue date: | 04/29/1993 |
| From: | Lanksbury R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20036A301 | List: |
| References | |
| 50-331-93-05, 50-331-93-5, NUDOCS 9305110073 | |
| Download: ML20036A310 (14) | |
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i U. S. NUCLEAR REGULATORY COMMISSION
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REGION III
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h Report No. 50-331/93005(DRP)
I Docket No. 50-331 License No. OPR-49
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Licensee:
Iowa Electric Light and Power Company
't IE Towers, P. O. Box 351
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Cedar Rapids, IA 52406
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Facility Name: Duane Arnold Energy Center Inspection At:
Palo, Iowa t
Inspection Conducted:
February 23 through April 6, 1993 b
Inspectors:
M. Parker C. Miller J. Hopkins
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Approved:
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/Em 4l2'hln R. D. Lank fu c hist Date Reactor Projects Section 3B
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Inspection Summary Inspection on February 23 throuah April 6.1993 (Report N9. 50-331/93005(DRP))
Areas Inspected: Routine, unannounced inspect-ion by the resident and region based inspectors of licensee event reports followup, followup of events, operational safety, maintenance, surveillance, lead test assembly. inspections, and report review.
Results:
An executive summary follows:
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9305110073 930429 PDR ADOCK 05000331 g
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g EXECUTIVE SUMMARY
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Operations Operating history was good, with an operating capacity factor of 91.9 percent for 1993. On March 29, 1993, the control rods were pulled to their final "all rods out" position, and the end of full power capability was expected on about April 10, 1993. The plant operated at or near 100 percent power for the
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majority of the period with minor power reductions for surveillances and load.
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following. Several events occurred which either caused, or had the potential to cause, power reductions. These included one reactor recirculation pump
flow decrease, one reactor recirculation runback, cooling tower fans tripping due to ice damage, reactor recirculation pump seal failure, feedwater heater
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drain valve leakage, and emergency bearing oil pump upper bearing failure.
The inspectors performed a safety system walkdown on the direct current (dc)
distribution systems and noted some operating instruction discrepancies and some opportunities to improve the Emergency Operating Procedures (EOPs) for a complete loss of 125 volt dc (section 4).
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Maintenance / Surveillance Maintenance efforts to reduce and maintain the non-outage maintenance request
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backlog below 600 items were successful. A coordinated operations and maintenance effort to highlight and repair control room equipment prior to an NRC management visit was successful in correcting long standing control room problems. The inspectors noted that continued emphasis of these items through
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BS-5, " Control Room Panel Shift Check List," or other mechanisms during routine operations would help minimize out-of-service control room equipment.
Personnel errors contributed to a loss of plant equipment.
This included a
seized upper bearing on the emergency bearing oil pump due to a failure to lubricate the pump, and an instrument air transient caused by a failed insulator combined with an improper 36KV electrical lineup.
- A 7-day outage was scheduled for April 16, 1993, to replace the "B" reactor recirculation pump upper seal, which failed on March 30, 1993. However, the licensee received an incverect seal replacement part, which prohibited them from rebuilding a replacement seal in time for the outage.
The new outage date will depend on resolution of the replacement part (section 3a).
Enaineerina and Technical Support Engineering efforts were underway to correct problems with reactor recirculation pump speed control. Task group recommendations were not final, but have identified the need for speed controller changes. A non-cited violation was identified in the area of licensee event report followup for failure to install instrument racks in their seismically qualified configuration (section 2a).
Safety Assessment /0uality Verification I;
Management oversight and planning to minimize the effects of the Cedar River flooding were timely and effective (Section 3b).
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DETAILS l
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Persons Contacted-j
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'*P. Bessette, Supervisor, Regulatory Communications j
- J. Bjorseth, Assistant Operations Supervisor
- D. Blair; Quality Assurance Assessment Supervisor sj
- C. Bleau, Supervisor, Systems Engineering
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- D. Engelhardt, Security Superintendent-
- M. Flasch, Manager, Engineering
J. Franz, Vice President Nuclear y
- J. Kinsey, Supervisor, Licensing
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D. Lausar,' Supervisor, Project Engineering l
- M. McDermott, Maintenance Superintendent
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C. Mick,- Operations. Supervisor
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- K. Peveler, Manager, Corporate Quality Assurance l
- K. Putnam, Supervisor, ' Technical Support
- A. Roderick,. Supervisor, Testing and Surveillance
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P. Serra, Manager, Emergency Planning
S. Swails, Manager, Nuclear Training
J. Thorsteinson, Assistant Plant Superintendent, Operations Support
.j G. Van Middlesworth,LAssistant Plant Superintendent, Operations and f
Maintenance; j
T. Wilkerson,~' Radiation Protection Manager j
- D. Wilson,' Plant Superintendent, Nuclear
- K. Young, Manager,' Nuclear Licensing
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In addition, thesinspectors interviewed other licensee personnel-inclu' ding operations shift supervisors, control room operators,. engineering personnel, d
and contractor personnel -(representing the licensee).-
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- Denotes presence at:the exit interview onTApril 6, 1993.
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Licensee Event Reports Followuo (92700)(90712)
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.t Through direct' observations,. discussions with -licensee personnel,- and :.
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review of records, the following event. reports were reviewed to L
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determine that reportability ~ requirements were~ fulfilled,Jimmediate-i corrective actions were accomplished, and corrective actions to prevent c;
recurrence' hadlbeen accomplished in accordance withitechnical'
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~i specifications.
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(Closed) Licensee Event Report (LER)91-010'(331/91-010-LL):
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Monitoring Instrumentation Not. Installed to Meet' Seismic.
j Requirements. On September 17,.199,1,- with the plant operating 'at
100 percent power, the licensee ~ identified four Foxboro instrument.
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racks' that'did not appear to meet their! seismic qualifications
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- The instrumentEracks were missing dummy circuit cards,Jcircuit j
card bumper: pads,~and mounting guide rails.. Thr seismic'
l qualification tests' by the manufacturer used racks which were j
configured with' dummy cards,7 bumper pads, and guide rails k The'
it missing; components' could:have rendered the instrument racksiand; j
their associated technical specification' (TS) instrumentation.
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and/or equipment inoperable during a-seismic _ event. The affected-y
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equipment provided control room indications for. accident
monitoring and a permissive function to prevent inadvertent operation of containment spray during accident conditions. This
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permissive function could have been manually overridden, as described in operating instructions and emergency operating procedures.
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The licensee's immediate corrective action was to install the missing components in.the affected instruments racks.
This was completed on September 18, 1991. The licensee performed an operability determination and concluded that without the missing components, the operability of the instrument racks could not be assured following the seismic event postulated by the manufacturer. However, the seismic qualification tests performed by the manufacturer used significantly higher accelerations than those postulated for the design basis event at the plant.
Additionally, the licensee determined that extensive testing would have been required to definitively determine the operability of the instrument racks without the missing components installed.
Since the instrument racks had been restored to their seismically qualified configuration, the licensee did not perform further qualification testing.
The licensee determined that the root cause for the instrument racks being installed in a seismically unqualified configuration was a combination of insufficient documentation of the seismically tested configuration, inadequate review of the qualification test report, and inadequate vendor installation instructions. As corrective action, the licensee issued a letter that described the event, provided guidance to the engineering and technical staff further clarifying the level of review expected for vendor documentation, and informed personnel of potential weaknesses in vendor supplied information. Additionally, the licensee conducted a walkdown of control room instrumentation' and reviewed appropriate vendor manuals, and determined that this was an isolated occurrence.
The inspectors reviewed the licensee's evaluation and documentation of the event and concluded that corrective actions for the subject LER appeared reasonable and adequate to prevent recurrence. Appendix B of 10 CFR Part 50, Criterion V,
" Instructions, Procedures, and Drawings," required, in part, that activities affecting quality be prescribed by documented instructions of a type appropriate to the' circumstances and be-accomplished in accordance with these instructions. The failure to install the subject instrument racks in accordance with instructions appropriate for the as-received condition of these racks was a violation. This violation was not cited because the licensee's efforts in identifying and correcting.the violation met the criteria specified in Section VII.B of the " General Statement of Policy-and Procedure 'for NRC Enforcement Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C (1993)).
This LER is closed.
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(Closed) Licensee Event Report (LER)92-004 (331/92-004-LL):
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Cable Spreading Room Fire Suppression System Test Results in Intrusion of Carbon Dioxide into Control Room. This issue was first documented in Inspection Report 331/90017, and unresolved item 331/90017-02(DRP) was opened. The inspectors reviewed and evaluated the licensee's root causes analysis and immediate and
long term corrective action in Inspection Reports (irs) 331/92006 and 331/92013. Unresolved item 331/90017-02(DRP) was closed in IR 331/92013. Since the LER concerns the same events, additional review was not required. This LER is closed.
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(Closed) Licensee Event Report (LER)92-005 (331/92-005-LL):
Primary Containment Isolation System Group III Isolation During Refueling Outage. On April 8, 1992, with the plant in cold shutdown for a refueling outage, a primary containment isolation system (PCIS) Group III isolation occurred. The isolation signal
was from the "A" logic channel. Plant operators confirmed that all required automatic actions occurred, and checked the initiation signals to determine the cause of the isolation.
None of the five initiating signals in the PCIS Group III "A" logic
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channel appeared to be the source of the isolation.
Further investigation was conducted to determine if blown fuses, cut wires, defective relays and/or power supplies, or outage related work was the source of the signal. The source of the signal was not positively determined. Since the cause of the isolation
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signal was not positively determined and all equipment had operated as required, the control room operators reset the Group III isolation signal and restored the affected systems to their required configurations.
I The inspectors reviewed the applicable documentation and concluded that the licensee's troubleshooting and investigation of the event were reasonable and adequate. This'LER is closed.
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(Closed) Licensee Event Report (LER)92-011 (331/92-011-LL).
Automatic Emergency Diesel Generators Start Due to. Momentary Emergency Bus Undervoltage During an Electrical Storm. On July 7, 1992,'with the plant operating at 100 percent power, the i
"A" and "B" emergency diesel generators (EDGs) automatically
started due to a momentary undervoltage condition sensed on each
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of their emergency buses. Although the EDGs started, they were not required to " pick up".their emergency buses. An electrical storm caused a momentary disturbance on the electrical distribution grid which in turn caused a momentary undervoltage condition on the emergency buses.
Plant operators verified that the EDGs were not required and secured the EDGs. 'Other equipment affected included one of the two main generator output breakers which opened, the "A" reactor water cleanup (RWCU) pump which tripped, and the supply transformer for the primary instrument and-service air compressors which deenergized.. The equipment was inspected and then restored to its. required configuration.
Plant safety was not jeopardized by.this event. Additionally, a recommendation was made to provide additional lightning protection
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to the electrical transmission lines for the. primary instrument -
and service air compressors.
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documentation and concluded that the investigation and corrective actions for the event were reasonable and adequate.
This LER is closed.
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(Closed) Licensee Event Report (LER)92-014 (331/92-014-LL):
Primary Containment Isolation System Actuations During Surveillance Testing. On August 31, 1992, with the plant operating'at 100 percent power, two PCIS isolations occurred during the performance of semiannual surveillance test procedure (STP) 41Al27, " Reactor Protection System (RPS) Motor Generator Set and Alternate Power Source Electrical Protection Assembly (EPA)
Functional Test / Calibration." The first was a Group V (RWCU)
isolation and the second was Groups 11 through V isolations along with an RPS channel "A" half scram signal and an RPS channel
"A" Group I (main steam. isolation valves) isolation signal.
The RPS channel
"A" Group I isolation signal was only one-half of the required signal needed to close the main steam isolation valves (MSIVs). After each event, plant operators confirmed that all
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automatic actions occurred, investigated the root causes for the isolations and half scram signal, and restored the systems to their required configurations.
Plant safety was not affected by.
these events.
The root causes for the first isolation (RWCU) were not determined.
Procedure STP 41A127 required the operator to manually hold the RWCU isolation relay in its energized position to prevent it from " dropping out" when the RPS bus power supply was shifted from the motor generator set to the alternate source.
The technician stated that he had held the relay but he was not positive that the relay had not momentarily " dropped out" when the power supply was shifted. This activity was performed several more times during the STP and no other problems were identified.
The licensee's immediate corrective action was to restore the RWCU system to service. The long term corrective action was to revise the STP such that RWCU was secured-(except during cold shutdown)
when the procedure was performed.
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The root causes for the second isolations (Groups -II through V isolations along with an RPS channel "A" half scram signal and an RPS channel'"A" Group I (MSIV) isolation signal) were not determined.
While performing STP 41Al27 on the "B" RPS power supply, the EPA breakers to the "A" RPS bus opened and deenergized the bus.
The licensee's immediate corrective action was to verify the calibration o_f the EPA logic card.
No problems were identified. As a followup action, thermography inspections of the normal and alternate power supply breakers and the voltage l
regulators for the motor generator sets were conducted.
No problems were identified. The licensee planned to install upgraded EPA logic cards which " seal in" the trip signal during the next refueling outage.
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The-inspectors reviewed the licensee's evaluation and j
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documentation, and concluded that even though the root causes for
both events were not determined, the investigation and corrective a
actions were reasonable and adequate. This LER is closed.
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(Closed) Licensee Event Report (LER)92-019 (331/92-019-LL):
Loss-f of Control Building Air Conditioning due to Inoperability of Both
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Control. Building Chillers. On November 19, 1992, with the plant (
operating at approximately 85 percent power during a startup,.the
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"A" control building chiller tripped and could not be restarted
while the "B" chiller was out of service for maintenance. The "A" l
chiller tripped on low oil pressure due to low oil level. Oil was added-to the "A" chiller and it was restarted with no' additional
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problems. The "A" chiller was out of service for approximately l
5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The maximum control room temperature recorded during the
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event was 80 degrees F.
The normal temperature range for the
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control room was 73-75 degrees F.
Plant safety was not
jeopardized during this event. The control building chillers are
not TS related equipment, even though they are safety-related
equipment.
J The licensee's investigation determined that adequate oil was not j
added following corrective maintenance in October 1992 to ensure
that the chiller operated properly' under changing seasonal load j
conditions. Additionally, there was no followup inspection to i
periodically check chiller performance following maintenance-
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activities. Finally, chiller oil level was not a-required check.
on the auxiliary operator logs. The licensee's immediate-
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corrective action was to add oil to the "A" chiller and restart j
the control ~ building air conditioning system. 'The licensee.'s long
term corrective actions were to revise the auxiliary operator's.
log to check chiller oil level and other parameters in order to jl more closely monitor changes in chiller performance.
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The inspectors reviewed the applicable 1icensee's evaluation. and-documentation, and concluded that the investigation and corrective l
actions for the event were reasonable and adequate'. This LER is l
closed.
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(Closed) Licensee Event Report (LER)93-001 (331/93-001-LL):
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Automatic Emergency Diesel Generators Start Due to Momentary.
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Emergency. Bus Undervoltage During-an ' Ice Storm. On
February 11,'1993, with the plant operating at 100 percent power,.
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the "A" and "B" EDGs automatically started on three separate
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i occasions due to momentary undervoltage conditions' sensed on both~-
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emergency buses.. Although the EDGs-started, they were not.
required to " pick'up" their respective emergency buses. High
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winds and ice buildup on the transmission. lines caused momentary i
disturbances on-the electrical distribution grid which in' turn..
caused momentary undervoltage conditions on the~ emergency buses.
' After each; transient', plant operators verified that -the EDGs were not required, and. secured the. EDGs. : The events occurred at'
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5:21.p.m. (CST),'7:14 p.m., and 7:50 p.m.
At 8:20 p.m.. the i
licensee reduced' power to approximately 75 percent in~ anticipation
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of more severe disturbances and a possible reactor trip. On
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February 12, the weather conditions improved, and the plant was
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returned to 100 percent power.
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Other equipment affected during the three events included one of the two main generator output breakers which opened, the "A" RWCU pump which tripped, well water pumps (nonsafety-related) which tripped, instrument ac undervoltage alarms, and uninterruptible at inverter alarms. No equipment was adversely affected during the
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events. After each event, the affected equipment was inspected and then restored to its required configuration.
Plant safety was not jeopardized by these events.
The inspectors reviewed the applicable licensee's evaluation and documentation and concluded that the investigation for the events was reasonable and adequate.
This LER is closed.
No violbtions or deviations were identified in this area; however, one non-cited violation was identified.
3.
Followup of Events (93702)
During the inspection period, the licensee experienced several events, some of which required prompt notification of the NRC pursuant to 10 CFR 50.72. The inspectors pursued the events with licensee and NRC officials.
In each case, the inspectors verified that the notification was correct, timely, appropriate, that the licensee was taking prompt
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and appropriate actions, and that activities were conducted within
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regulatory requirements. The specific events were as follows:
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March 7, 1993 - Loss of condensate return tank pump and degradation of
packing exhauster vacuum.
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March 13, 1993 - Reactor recirculation motor generator runback and inverter transfer.
March 30, 1993 - Reactor recirculation pump "B" upper seal failure April 3, 1993 - Cedar River flooding a.
"B" Reactor Recirculation Pump Seal failure The "B" reactor recirculation pump had shown indications of a failed number two (upper) seal.
Between March 30, 1993, and March 31, 1993, the following parameters changed for the Byron Jackson pump which is equipped with two 100 percent capacity mechanical seals:
Number 2 seal stage pressure decreased from 500 psig to
50 psig and remained steady at 50 psig.
Drywell identified leakage increased from 1.5 gpm to 1.9 gpm
and remained steady at 1.9 gpm (TS limit is 25 gpm).
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"'B' Recirculation Seal Staging Flow Hi/ Low" annunciator
lit, givino indication of changing mechanical seal leakage.
The liceimee discussed failure indications and repair options with Byron Jackson, the resident inspectors, and Region III management.
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The licensee planned to rebuild and test a spare seal, and then
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enter a 7-day outage to repair the seal.
In the interim, operators were given direction to maintain constant speed on the
"B" reactor recirculation pump (minimizing stress on the seal),
and to enter single loop operations and secure the "B" reactor recirculation pump if drywell identified leakage reached 2.5 gpm
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(which would indicate possible degradation of the number one seal). The seal outage was initially scheduled to begin on April 16, 1993. However, the licensee discovered that the pressure cell which was ordered in mid-1992 and which arrived on April 5, 1993, was the wrong part. The licensee delayed the outage until a resolution on parts and the rebuild of a spare seal could be completed.
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Cedar River Floodina
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Due to unseasonably high rainfall and heavy spring runoff, river water flow increased significantly. The river water flew-rate peaked at approximately 10 times the normal flow rate, which resulted in elevated river water levels. The licensee coatinued to monitor river water levels due to local flood warnings.
The average natural grade around the plant varied from 746 feet to 750 feet. The plant finished grade is at an elevation of 751 feet. Technical Specifications specified an action level of 753 feet for additional monitoring of river conditions, due to the potential for site flooding.
In addition, declaration of an Unusual Event was required when river water level reached 753 feet.
On April 4, 1993, after significant spring runoff, the river crested at 745.5 feet, as measured at the river water intake structure. The river water flow was recorded at 70,900 cubic feet per seccnd. Although the plant did experience some site flooding,-
no plant structures were affected. The main impact to the plant was in accessibility to the intake structure, as the lower natural grade around the intake structure was completely surrounded by water.
In anticipation of high river water levels and some localized flooding on site property, the licensee made preparations to ensure that necessary equipment (i.e. sand, sandbags, stop blocks, etc.) was available in the event that level increased above protected levels. Also, the licensee brought in an emergency-diesel generator to supply power to the river water pumps in the event that the normal power supply was lost. Overall,_the licensee took significant steps in preparing for site flooding,.
and in monitoring and predicting river water level.
No violations or deviations were identified in this area.
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4.
Operational Safety Verification (71707) (71710)
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The inspectors observed control room operations, reviewed applicable l
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logs, and conducted discussions with control room operators during the
inspection. The inspectors verified the operability of selected
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emergency systems, reviewed tagout records, and verified proper' return to service of affected components. Tours of the reactor building and l
turbine building were conducted to observe plant equipment conditions, i
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including potential fire hazards, fluid leaks, and excessive vibrations,
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and to verify that maintenance requests had been initiated for equipment
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in need of maintenance.
It was observed that the Plant Superintendent,
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Assistant Plant Superintendent of Operations, and' the Operations l
Supervisor were well-informed of the overall. status of the plant and
that they_ made frequent visits to the control room. _ The inspectors, by.
l observation and direct interview, verified that the physical security i
plan was being implemented in accordance with the station security plan.
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The inspectors observed plant housekeeping and cleanliness conditions
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and verified implementation of radiation protection controls. These
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reviews and observations were conducted to verify that facility
operations were in conformance with the requirements established under i
TS, 10 CFR, ard administrative procedures.
I Safety System Walkdown
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The inspectors walked down portions of the 250 volt,125' volt, and
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24 volt dc (Vdc) distribution systems, including-a comparison of prints,
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operating instructicns, and plant hardware. No problems were found with
equipment.
The inspectors found two discrepancies with the load i
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description given in Operating Instruction (01) 388, "250 VDC Powerz
Distribution System," for breakers 1D41, circuit.6, and ID41, circuit q
14. Although the breakers themselves were properly labelled, 01388
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identified valve MO-2312 as the "HPCI discharge valve" when it was
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actually the "HPCI injection valve," and valve M0-2247 as the " booster.
pump drain valve" when it was actually the " lube oil and condenser; cooling supply valve." The inspectors discussed these discrepancies
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with the responsible system engineer. The system engineer submitted
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procedure change forms to correct-the problem at. the. end' of. the.
inspection period.
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The inspectors also reviewed _the results of the Duane Arnold Energy
pertained to dc distribution systems.. A loss of.both 125 Vdc busses is-i the. only sequence that meets the 1 X 10-' per year screening criteria of J
Generic letter 88-20, " Individual Plant-Evaluation For Severe Accident !
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Vulnerabilities - 10 CFR 50.54.f."
This sequence comprises 13 percent
of the total core damage frequency (CDF). - The _IPE indicated,that not i
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having a procedure to: guide operators with _ issues' unique 'to a _ complete
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loss' of.125-Vde, such as determining which breakers.are available-for
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manual operation and where. to. hook up portable power sources,.was a _
major factor influencing this. sequence.
The inspectors spoke with.the-
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system engineer to determine if' procedure improvements _were planned; to '
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reduce CDF for the loss of 125 Vdc sequence.
The system engineer had
not reviewed the results of the DAEC IPE-as it pertained to his system.
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-The inspectors found that no. systematic effort was underway to~ inform
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engineers of the IPE results so that safety improvement considerations
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could be made, and discussed this finding with the Engineering Manager.
At the end of the period, the licensee had assigned action item topics, dates, and individuals for review of IPE potential improvements, and was
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working on improving communication of the IPE results to plant personnel, i
No violations or deviations were identified in this area.
5.
Monthly Maintenance Observation (62703)
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
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industry codes or standards, and in conformance with TS.
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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
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t inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and fire prevention controls were implemented.
Work requests were reviewed to determine status of outstanding jobs-and to assure that priority was assigned to safety-related _ equipment maintenance which might affect system performance.
Portions of the fol!owing maintenance activities were observed and/or~
reviewed:
- Posidual heat removal (RHR) pump "A" discharge piping monitoring
- Rhk service water crosstie manual isolation drain valve, V13-16, replacement
- Steam jet air ejector (SJAE) condensate return pump, IP133B, repair
- Lead test assembly (LTA) disassembly and inspection
- Reactor recirculation pump speed control troubleshooting
- Containment hydrogen and oxygen analyzer troubleshooting and repair Following completion of maintenance on the RHR system, the inspectors verified that this system had been returned to service properly.
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Reactor Recirculation ~ Speed Control Problems
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P The licensee continued to experience problems with reactor recirculation speed control circuitry. Several recirculation motor generator (MG)
scoop tube lockups and two recirculation runbacks occurred during the
period.
q On March 13, 1993, the "A" recirculation MG received a 45' percent speed t
runback signal. Reactor power decreased to below 80 percent. The'
runback resulted from an instrument alternating current (ac) inverter
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transfer which caused fluctuations on the lY11 instrument bus. The-
reason for the-inverter transfer was unknown. The licensee suspected l
the recirculation runback resulted from a relay which dropped out during a short (several millisecond) voltage fluctuation on lYll. The j
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responsible system engineer was; evaluating the importance' of relay
timing on this and possible future events.
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t On March 27, 1993, the "A" reactor recirculation pump speed dropped -.
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0.4 million 1b/hr, lowering reactor power by 10 megawatts thermal. The-
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licensee attributed this problem to dirty. speed control potentiometers, i
and subsequently cleaned them.
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t The licensee's working group to resolve recirculation speed control
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problems expected to issue their rccommendations on speed control t
shortly. Replacement of the aging speed controllers during the upcoming-refueling outage was one of the possible near term fixes being
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No violations or deviations were identified in' this area.
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6.
Monthly Surveillance Observation (61726)
j The inspectors-observed TS required. surveillance testing and verified
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I that testing was performed'in accordance with adequate procedures; that test instrumentation was calibrated, that limiting. conditions for-e operation were met,'that removal and restoration of the;affected
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components were accomplished,-that test results conformed with TS'and_
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procedure requirements and_were reviewed by personnel'other than the:
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individual-directing the test,- and that..any deficiencies identified-
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during the testing were properly reviewed and resolved by appropriate
.a management personnel.
f The inspectors also witnessed portions of _the following test activities:
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-STP-42A014-
--Main Steam Line Leak Detection Functional' Test.
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STP-428017-Q
-: Recirculation Riser D/P A>B; Quarterly l Instrument.
Calibration
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jj STP-428032-A
-: 4KV Emergency Bus Sequential Loading' Relay AnnualL Function Test and Calibration!
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STP-45A001-Q
~- Core Spray System Operability. Tests
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STP-45A002-Q,CY - Low Pressure Coolant Injection (LPCI) System
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Operability Tests STP-45D001-CY
- High Pressure Coolant Injection (HPCI) System Cycle Operability Test STP-450001-Q
- HPCI System Quarterly Operability Test STP-45E001
- Reactor Core Isolation Cooling (RCIC) System Quarterly Operability Test STP-45J002-Q
- River Water Supply System Operability Test No violations or deviations were identified in this area.
7.
Lead Test Assembly (LTA) Inspections (60705)
On March 2,1993, the licensee commenced disassembly and inspection of five LTAs and inspection of several spent fuel bundles in conjunction with General Electric (GE). The project plan was to collect 38 fuel pin segments (4 segments per fuel pin) from a specially designed LTA for shipment to GE, and to inspect several other LTAs and GE 8x8 fuel bundles with a fiber optic scope.
On March 3,1993, the licensee observed degassing on one pin segment just after it has been screwed into another segment. The licensee had discussed the possibility of degassing during prejob planning and briefings.
Radiation surveys and air samples taken on the refuel ' floor did not indicate any readings higher than background. The segment
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stopped degassing when the segment was joined with Other segments into a
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reconstituted pin. The fuel segment appeared to have failed during handling, releasing fission product gasses. The licensee did not intend to ship this segment with the shipment of 38 other segments.
Fuel pin collecting and inspection were complete, and the licensee was finalizing plans to ship the spent fuel pin segments to a GE facility in California.
Planning and execution of this project was excellent, and resulted in successful completion with no major technical.or radiological problems.
No violations or' deviations vere identified in this area.
8.
Report Review (90713)
During the inspection period, the inspectors reviewed the licensee's monthly operating report for February:1993.
The inspectors confirmed that the information provided met the reporting requirements of TS 6.11.1.C and Regulatory Guide 1.16, " Reporting of Operating Information."
No violations or deviations were identified in this area.
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9.
Items for Which a " Notice of Violation" Will Not Be Issued
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During this inspection, certain activities, as described above in paragraph 2.a, appeared to be in violation of NRC requirements.
However, the licensee identified this violation and it will not be cited
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because the criteria specified in Section VII.B of the " General Statement of Policy and Procedure for NRC Enforcement Actions,"
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(Enforcement Policy, 10 CFR Part 2, Appendix C, (1993)), were satisfied.
P 10.
Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Section 1)
on April 6,1993, 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 inspection report with regard to documents or processes reviewed by the inspectors. The licensee did not identify any such documents or processes as proprietary. The licensee acknowledged the findings of the inspection.
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