IR 05000424/1993003
| ML20056C098 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 03/17/1993 |
| From: | Balmain P, Brian Bonser, Skinner P, Starkey R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056C097 | List: |
| References | |
| 50-424-93-03, 50-424-93-3, 50-425-93-03, 50-425-93-3, NUDOCS 9303300068 | |
| Download: ML20056C098 (17) | |
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UNIT ED STATES jo NUCLEAR REGULATORY COMMISslON
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Report Nos.:
50-424/93-03 and'50-425/93-03-l Licensee: Georgia Power Company
P. O. Box 1295
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Birmingham, AL 35201 l
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Docket Hos.:
50-424 and 50-425 License Nos.:
Facility Name: ' Vogtle 1 and 2
Inspection Conducted: January 31, 1993 - February 27, 1993
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Inspectoy: 'Dgd 0 p m tjy w 3 /7 93 -
cj/n B. R. B s'er, Senior Resident Inspector Date Signed
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3 1793
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1 key, Resident nspector Date Signed
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.3 Pf 9 V
. Ialgain, }esident Inspector Date Sign'ed
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Accompanied by:
J.L. Starefos.
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J./ M /
Approved by: _ P.~5kinner, Chief' /
Date Signed
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Reactor Projects Section 3B
Division of Reactor Projects iUMMARY i
Scope:
This routine, inspectit
' ailed inspection in the following
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areas: plant operatior.
'illance, maintenance, Engineered i
Safety Systems walkdown,
seling activities, and follow-up of f
open items.
i Results:
One non-cited violation was identified. The violation involved a failure by the licensee to incorporate the correct lif t settings in the Unit 2 Power Operated Relief Valves while relying on'these i
valves to meet Technical Specification (TS) requirements for the
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cold overpressurization protection system (paragraph 5.e.).
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A continuing weakness in the Unit 1 Class IE batteries was i
identified. During this inspection period four cells failed to t
meet TS requirements (paragraph 5.d.).
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9303300068 930317
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PDR ADOCK 05000424 G
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A review of Turbine Driven Auxiliary-Feedwater pump overspeed
trips was performed due to a generic concern on water build-up in the turbine casing.
There were no overspeed trips found related
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to this cause at Vogtle.
The design of the Vogtle~ steam trap
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system was found to be effective and was reliable in draining
condensate and preventing a buildup of water in the turbine casing
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(paragraph 5.e.)
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A concern was identified with wrong unit / wrong train errors by
Instrumentation and Control technicians. Three errors of this type have occurred ~in the last five months. Although these errors i
are relatively infrequent, they do continue to occur even though
licensee management has continued to stress the importance of self-verification (paragraph 4.b.)
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REPORT DETAILS 1.
Persons Contacted Licensee Employees J. Beasley, Assistant General Manager Plant Operations S. Bradley, Reactor Engineering Supervisor
- W. Burmeister, Manager Engineering Support
- S. Chesnut, Manager Engineering Technical Support
- C. Christiansen, SAER Supervisor C. Coursey, Maintenance Superintendent
- R. Dorman, Manager Training and Emergency Preparedness
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- G. Frederick, Manager Maintenance
- M. Griffis, Manager Plant Modi'ications M. Hobbs, I&C Superintendent
- Vs. Holmes, Manager Operations
- D. Huyck, Nuclear Security Manager
- W. Kitchens, Assistant General Manager Plant Support
- R. LeGrand, Manager Health Physics and Chemistry
- G. McCarley, ISEG Supervisor R. Moye, Plant Engineering Supervisor M. Sheibani, Nuclear Safety and Compliance Supervisor
- W. Shipman, General Manager Nuclear Plant C. Stinespring, Manager Administration
- J. Swartzwelder, Manager Outage and Planning C. Tynan, Nuclear Procedures Supervisor J. Williams, Supervisor Work Planning and Controls Other licensee employees contacted included technicians, supervisors, engineers, operators, maintenance personnel, quality control inspectors, and office personnel.
Oglethorpe Power Company Representative
- T. Mozingo NRC Resident Inspectors
- B. Bonser
- D. Starkey P. Balmain
- J. Starefos
- Attended Exit Interview of the inspection report.An alphabetical list of abbreviations is located in the la
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2.
Plant Operations - (71707)
a.
General
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The inspection staff reviewed plant operations throughout the i
reporting period to verify conformance with regulatory requirements, Technical Specifications, and administrative
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controls. Control logs, shift supervisors' logs, shift relief
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records, LCO status logs, night orders, standing orders, and l
clearance logs were routinely reviewed. Discussions were
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conducted with plant operations, maintenance, chemistry and health
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physics, engineering support and technical support personnel.
Daily plant status meetings were routinely attended.
j Activities within the control room were monitored during shifts
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and shift _ changes. Actions observed were conducted as required by j
the licensee's procedures.
The complement of licensed personnel
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on each shift met or exceeded the minimum required by TS. Direct observations were conducted of control room panels,
instrumentation and recorder traces important to safety.
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Operating parameters were observed to verify they were within TS i
limits. The inspectors also reviewed DCs to determine whether the
licensee was appropriately documenting problems and implementing i
corrective actions.
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Plant tours were taken during the reporting period on a routine
basis. They included, but were not limited to the turbine
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building, the auxiliary building, electrical equipment rooms, i
cable spreading rooms, NSCW towers, DG buildings, AFW buildings,
and the low voltage switchyard.
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During plant tours, housekeeping, security, equipment status and
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radiation control practices were observed.
The inspectors verified that the licensee's health physics policies / procedures were followed. This included observation of
HP practices and review of area surveys, radiation work permits, postings, and instrument calibration.
The inspectors verified that the security organization was f
properly manned and security personnel were capable of performing
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their assigned functions; pers'ons and packages were checked prior
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to entry into the PA; vehicles were properly authorized, searched,
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and escorted within the PA; persons within the PA displayed photo i
identification badges; and personnel in vital areas were i
authorized.
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b.
Unit 1 Summary
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The unit began the period operating at 100% power and operated at l
full power throughout the inspection period. On February 23 with
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the boron concentration less that 10 ppm, Unit I began to coast
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down in preparation for the refueling outage scheduled to begin on
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March 13.
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Unit 2 Summary
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The unit began the period operating at 100% power and operated at
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full power throughout the inspection period.
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d.
Diesel Generator Room Temperature
NRC inspection report 50-424,425/93-02 identified a problem with
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DG room HVAC dampers. As part of the review of this problem the
inspectors reviewed the licensee's documentation that justified
leaving DG room exhaust dampers open as a compensatory action for maintaining DG building ventilation operable. A licensee
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evaluation approved on January 28, 1993, detailed an engineering
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review of issues involving cold outside air temperatures. The i
results of this engineering review stated that should outside air I
temperatures drop below 32 degrees F with one or more DG room
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l ventilation exhaust dampers failed open, local temperatures around i
the DG pedestal bearing and governor should be monitored to ensure l
these temperatures do not fall below 50 degrees F.
If DG average
room temperature falls below 50 degrees F, the DG is no longer in j
its design range of temperatures and operability becomes questionable.
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On the night of February 18, outside air temperatures dropped into l
the mid-twenty degree F range with two sets of exhaust dampers
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failed open (2TV-12096 and 12096A, and 2TV-12097 and 12097A) in
the 2A DG room. Temperatures in the diesel room fell into the l
mid-fifty degree range. The licensee became concerned that room temperature would fall below 50 degrees F and affect 2A DG I
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operability.
In response to the decreasing room temperature, the licensee restored one damper to operability and closed it, and installed portable electric radiant heaters in the DG room.
One heater was placed close to the pedestal bearing on the generator end of the diesel. The other heater was placed at the other end
of the diesel close to the engine lube oil and fuel oil equipment
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and in the vicinity of the governor.
The inspectors observed the heater arrangement and found that the
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heater on the generator end of the DG appeared to be too close to
the DG excitor which caused a cable to be heated to greater than
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expected temperature. The inspectors were also concerned that the heaters could represent an ignition source since the coils on the heaters were exposed and gave off intense heat.
These concerns
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deenergized (room temperature was no longer a concern). The licensee also evaluated the effect of the heat on the excitor
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cable and found that the cable ratings were higher than the l
temperature to which the cable was subjected.
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The licensee concluded that DG operability had not been degraded.
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The inspectors concluded that the licensee had not been well e
prepared to maintain DG operability with the cold outdoor
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temperatures. The engineering review that had been prepared and j
attached to the information LC0 stated that corrective action
should be taken should localized temperatures fall below 50
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degrees F.
Specific corrective action to maintain DG operability
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had not been formulated prior to the night of February 18.
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No violations or deviations were identified.
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3.
ESF System Walk-down (71710)
i On February 23, the inspectors completed a walk-down of both trains of
the Unit 1 DGs and their support systems. This included a review of the
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DG air, fuel oil, lube oil, Jacket water and ventilation systems. The
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inspectors reviewed the appropriate sections of the TSs, FSAR,
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procedures, and system P&lDs, and verified correct system alignment on (
Train B and_ randomly verified system line-ups on Train A.
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inspectors examined valves for packing leakage, bent stems, missing i
handwheels and improper labeling and recorded no significant problems.
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The inspectors did, however, identify a hose connected to a lube oil strainer drain line which should have been capped. The hose was removed
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by the PE0 on shift and the line was capped. The inspectors also inspected component condition, labeling, and general housekeeping and found them acceptable.
The inspectors also identified a number of degraded or temporary tags. The inspectors also confirmed that instrument calibration dates were current for a random sample of l
instruments on each train. With the assistance of the licensee, the
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inspectors examined the inside of the local control cabinet for both diesels. The inspectors did not identify any significant concerns as a result of this inspection. The discrepancies found were identified to p
the licensee for their action.
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No violations or deviations were identified.
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4.
Surveillance Observation (61726)
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General
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Surveillance tests were reviewed by the inspectors to verify procedural and performance adequacy.
The completed tests reviewed
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were examined for necessary test prerequisites, instructions, I
acceptance criteria, technical content, data collection,
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independent verification where required, handling of deficiencies
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noted, and review of completed work.
The tests witnessed, in
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whole or in part, were inspected to determine that approved procedures were available, equipment was calibrated, prerequisites were met, tests were conducted according to procedure, test results were acceptable and systems restoration was completed.
SURVEILLANCE No.
TITLE 14640-1 SSPS Slave Relay Train A Test Auxiliary Feedwater 14606-1 SSPS K618 Train A Test Safety Injection 93100-1 Verification of Fuel Handling Machine Interlocks and Physical
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Stops 14805-2 RHR Pump & Check Valve IST -
Train A 14810-1 TDAFW Pump & Check Valve IST b.
Wrong Unit / Wrong Train Errors On February 22, an 1&C technician was performing procedure 24765-2, Steam Generator 4 Level (Narrow Range) Protection Channel III 2L-548 ACOT.
During the execution of the procedure he mistakenly placed bistable switches in " test" on card 0833 instead of card 0834. These cards are located side by side in the same control room cabinet and are clearly and correctly labeled.
Control room operators immediately observed the incorrect bistable trip static lights, the procedure was stopped and the bistables switches were returned to their normal position. There were no unplanned actuations of equipment as a result of the technician's error. The technician was subsequently counseled on the importance of self-verification prior to manipulating plant equipment. This event was documented by the licensee in DC 2930016.
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The inspectors reviewed the deficiency card history of wrong unit / wrong train errors by IEC technicians and identified six such documented errors since 1989. Three of these errors, including the one just discussed above, have been made within the last five months. The other two recent errors are documented in DCs 2920274 and 1920074. The inspectors are concerned that wrong unit / wrong train errors have increased significantly in the last six months, although licensee management has continued to emphasize the importance of self-verification.
The inspectors will continue to closely monitor these types of errors.
No violations or deviations were identified.
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Maintenance Observation (62703)
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General l
The inspectors observed maintenance activities, interviewed j
personnel, and reviewed records to verify that work was conducted
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in accordance with approved procedures, TSs, and applicable j
industry codes and standards. The inspectors also verified that
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l redundant components were operable, administrative controls were
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correct replacement parts were used, radiological controls were proper, fire protection was adequate, adequate post-maintenance
testing was performed, and independent verification requirements i
were implemented. The inspectors independently verified that
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selected equipment was properly returned to service. Outstanding
work requests were reviewed to ensure that the licensee gave
priority to safety-related maintenance activities.
The inspectors witnessed or reviewed the following maintenance activities:
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MWO NOS.
WORK DESCRIPTION 29300521 Troubleshoot Cause of DG 2B PT fuse
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Failure 29300593 Recalibrate COPS Setpoints in Loops 2P-403 and 2P-405 29300684 Troubleshoot Wide Range T-Hot Temperature Instrument 2T-433B Failure 19300946 Replace Unit IC Battery Cell #4 l
19201673 Perform Pre-outage PM on Fuel Handling Machine 19300011 Replace Unit IA Battery Cell # 40 19203933 Instrument Air Compressor No. 1 Replace i
Installed Copper-tubed HX with Stainless
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Steel HX 29203444 Repair Jacket Water Leak on DG 28 29300062 Replace fuel Oil Relief Valve on DG 2B
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29300521 Investigate DG 2B Voltage / Frequency Swings
During Synchronization in Parallel Mode
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19300676 Replace Primary Power Supply in Cabinet 6, Control Group 2, Control Room Panel 1-1604-QS-PC2 l
29300428 Repair Aquarian 1000 Steam Drain Trap l
Level Switch on TDAFW
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Diesel Generator 2B Planned Maintenance Outage
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On February 3 at 5:53 p.m., Unit 2 entered a planned fifteen hour maintenance outage on the 28 DG. The purpose of the outage was to j
change out a fuel oil pressure regulating valve which was
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suspected of leaking; repair a jacket water leak; repair a lube oil leak on the turbo charger; and calibrate various instruments.
The jacket water and lube oil leaks were repaired with no difficulty. The replacement of the fuel oil system pressure i
regulating valve, 2-PSV-9083, took longer than expected due to unanticipated licensee questions concerning valve operation and setpoint adjustment.
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At 6:17 a.m. on February 4, following completion of scheduled maintenance on the 2B DG, the DG was. started per procedure 14980-2, Diesel Generator Operability Test.
The DG started and achieved rated voltage and frequency within the required time.
When the operator attempted to synchronize the DG with the 4160 volt AC bus, 2BA03, the "DG 2B Generator Trouble" annunciator was received, the synch meter began oscillating erratically, and DG frequency and voltage readings indicated zero. The operator then turned the synchroscope off and voltage and frequency returned to normal. A normal shutdown of the DG was then performed.
Troubleshooting by maintenance revealed that the operator had initially incorrectly operated the synchronizing switch for the emergency incoming breaker 2BA0305 to bus 2BA03 rather than the synchronizing switch for the DG 2B output breaker 2BA0319 as he had intended. He recognized his error, turned off the incorrect synch switch and turned on the correct synch switch.
He did not detect that upon turning off 2BA0305 synch switch that the synch
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meter did not return to its normal de-energized position, I
indicating that the switch contacts were still made, even though the switch position indicated off.
Consequently, when the correct synch switch, 2BA0319, was turned on, PT fuses in the generator control cabinet were blown. The synchronization circuitry is not designed to have two synchroscopes in operation simultaneously, which occurred when the contacts on 2B0305 did not disengage and the switch for 2BA0319 was turned "on."
Normally this situation could not occur since there is only one control handle for the synch switches and that control handle must be moved from one switch to another and can only be removed from a synch switch when the switch is in the "off" position.
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The PT fuses were replaced and a " Caution Tag" was placed on the i
synch switch for 2BA0305 warning that its contacts may stick in j
the "on" position and that "off" can be verified by ensuring that
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the synch meter needle is in the 2 to 3 o' clock position. The
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operator involved was " coached" by his supervisor on proper self-i verification techniques.
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i The licensee determined that this was an invalid DG failure since
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it represented a malfunction of the synchronizing circuitry which
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is not operative in the DG emergency operating mode. The inspectors reviewed Regulatory Guide 1.108, Periodic Testing of i
Diesel Generator Units Used as On-site Electric Power Systems at j
Nuclear Power Plants, and agreed that this was an invalid failure
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as defined by the Regulatory Guide. The inspector had no further i
concerns. The 2B DG was successfully run and returned to service l
at 8:46 p.m. on February 4.
The duration of the 2B DG outage was l
approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> longer than the planned 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> due tc the
delays described above.
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Review of TDAFW Overspeed Trips
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During this reporting period the inspectors were informed of TDAFW I
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turbine overspeed trips at South Texas Project Units 1 & 2.
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preliminary determination was that water had built up in the
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turbine casing from a steam admission line drain trap that did not
properly drain and/or leakage by the turbine trip and throttle valve which is normally closed.
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j In response to these events the inspectors reviewed the recent i
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operating history of the TDAFW pumps at Vogtle with particular l
emphasis on proper operation of steam admission line drain traps
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and any past overspeed trips which could have been caused by water
in the turbine casing. At Vogtle, condensation which collects in j
i the TDAFW steam line drain traps (two traps per TDAFW) drains i
through a flow orifice and then to the shell side of the main i
e condenser. A motor operated bypass valve around the flow orifice i
i opens on a high level in the drain trap if the amount of collected
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condensate exceeds the capacity of the. flow orifice to drain the trap. The bypass valve receives an open' signal from either of two conductivity probes which detect level in the drain trap. These particular level detectors were installed during the last i
refueling outage for each unit and are designed to differentiate-
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between steam and water in the drain trap.
Either of the two
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level switches will cause the flow orifice bypass valve to open
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when a high water level condition is detected in the trap.
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after a time delay, the water level does not decrease below the j
high level setpoint or the bypass valve does not close, then a l
trouble alarm is annunciated in the main control room requiring
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specific action by tne operator.
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f One of the contributing factors noted at South Texas was leakage
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by the normally closed trip and throttle valve.
The valve
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alignment at Vogtle is different in that the T&T valve is normally
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open and closes on either a mechanical or electrical overspeed
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trip of the TDAFW. The Vogtle T&T valve also has drain lines to l
route any accumulated condensation to a floor drain.
The inspectors reviewed MW0s and DCs on the TDAFWs for the last eighteen months for overspeed trips which could have been caused
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from water in the turbine casing. Although there were at least
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four electrical / mechanical overspeed trips during the period, none
were related to faulty draining of steam traps or leaking valves.
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The four trips were attributed to faulty resistors in the governor j
control circuitry (NRC IR 50-424,425/92-14) and failures in the
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mechanical trip system (NRC IR 50-424,425/92-20). One open MWO on l
the Unit 2 TDAFW drain trap level controller indicated that the
steam / water differentiator level controller had malfunctioned and
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was showing both a steam and a water condition in the trap. The
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drain trap orifice bypass, which was closed, should have opened on
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the receipt of the water indication. Maintenance personnel discovered a loose terminal strip at the MCC power supply to the
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l motor operated bypass valve which prevented the valve from I
opening. The conflicting steam / water indication on the drain trap
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level controller was caused by condensation forming inside the
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i level probe conduit. The licensee initiated a NWO to install a
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drain in the conduit to prevert accumulation of condensation and
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repaired the loose terminal strip. The inspector was satisfied j
j that appropriate corrective actions were taken on the
malfunctioning drain trap.
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The inspectors were satisfied that events similar to these at South Texas have not occurred at Vogtle and that the Vogtle TDAFW j
design should prevent similar TDAFW overspeed trips. Appropriate
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corrective action has also been initiated on the problems
I associated with moisture in the drain trap level controller i
conduit. A shift briefing item was presented to all operations
shift personnel concerning the TDAFW trips at South Texas and cautioned personnel to pay close attention to all activities
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associated with TDAFW operation.
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Unit 1 Battery Cell Failures
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During this inspection period there were four instances where l
entry into Unit 1 TS LCOs were required due to low individual cell i
voltage readings during surveillances. On February 1, cell #40 in
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the A battery was measured at-2.09 volts; on February 11, cell #38
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in the D battery was measured at 2 046 volts; and on February 17, cell #4 in the C battery was also measured at 2.046 volts. All of
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these readings were below the Category B: allowable float voltage
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limits (2.10 volts) required by TS 3.8.2.1, D. C. sources. The
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licensee entered the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> LC0 in each case and replaced.each cell within the 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. On February 24, cell #19 on the C battery was measured at 2.061 volts. The licensee planned to replace this cell, but while moving the replacement cell in the
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warehouse in preparation to take it to the control building, it
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was dropped and damaged. As a result, the licensee jumpered out l
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cell #19.
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The inspector considers these failures and the recent increasing
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failure rate a continuation of the declining trend in the
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performance of the Unit 1 Class IE batteries which was identificd
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in NRC IR 50-424,425/92-23.
The inspectors have questioned the
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reliability of the batteries and found that testing of most of.the
cells subsequent to their removal has shown their capacity to be
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greater than 100%. This indicates the battery would have i
fulfilled its safety function.
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Nonconservative Unit 2 PORV Cold Overpressure Protection Setpoints
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i On January 26, the inspector relayed a technical concern to the
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licensee regarding the determination of low temperature
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overpressure protection setpoints without considering the effect of pressure drops due to RCS piping losses. On January 28, the licensee found, during a review of scaling calculations and-
calibration procedures, that the Unit 2 COPS setpoints were set
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with Unit I values. This was nonconservative and.potentially
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cutside of the design analysis.
The licensee then declared the
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COPS function of both Unit 2 PORVs _. inoperable and initiated an-information LC0 to prohibit their use in Modes where COPS is-
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required.
When the Unit is operating in Modes 4, 5, and 6 with the reactor
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vessel head on, TS 3.4.9.3, Cold Overpressure Protection Systems,
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requires that either the PORVs with variable lift settings, or the
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RHR suction relief valves, or an RCS vent opening, be operable.
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The bases for this TS is to ensure the RCS will be' protected from brittle fracture or failure due to pressure transients. The PORV
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setpoints' for COPS are unit specific and are given in TS figure 3.4-4a for Unit I and figure 3.4-4b for Unit 2.
These values. are
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based on reactor vessel integrity pressure / temperature limits in j
accordance with 10 CFR 50 Appendix G criteria for operation up to
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16 EFPY. The difference between units is due to the difference in--
i material composition of the reactor vessels.
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Calibration procedures and scaling calculations for the PORV setpoints are based on values provided in the Westinghouse'PLS i
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document. The original Unit 2 COPS scaling and calibration i
procedures were developed in April'1988 prior to initial operation-j
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and based on Revision 2 of the PLS, which included a common COPS.
setpoint for_both units. Revision 3 of the PLS was issued;in August 1988, with unit specific COPS setpoints.
This change was
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not identified by the licensee or incorporated into the Unit 2 l
calibration procedures (24518-2 and 24819-2).
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following identification of the incorrect setpoints, the licensee
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performed a review of control room logs and identified several
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instances where the Unit 2 PORVs were used for RCS Cold Overpressure Protection per TS 3.4.9.3.
No pressure transients occurred on Unit 2 which opened the PORVs.
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The licensee took corrective action to revise the Unit 2 l
calibration procedures.
The inspector observed the licensee
recalibrate the COPS setpoints and verified that the correct
setpoints were installed.
The licensee also reviewed the current I
revision of the PLS document and did not find additional unit
>
specific setpoints that were overlooked.
In addition to these
corrective actions, the licensee reevaluated the design analysis.
This evaluation determined that the 10 CFR 50 appendix G limits
for the actual operation of 3.17 EFPY on the Unit 2 vessel are
,
higher than the Unit I setpoints that are based on 16 EFPY. Unit i
2 had, therefore, remained within its design basis.
j i
Relying only on the Unit 2 PORVs for COPS on several occasions
!
while in Modes 4, 5 or 6 represents a violation of TS 3.4.9.3.
The violation was due to an inadequate review of setpoint
<
documentation revisions and the resultant failure to maintain
!
adequate calibration procedures. The inspector found the i
corrective actions discussed above to be adequate, and concluded i
based on the evaluation of the design basis, which considered actual operation on the Unit 2 vessel, that the setpoint error was
',
of minor safety significance.
,
This violation will not be subject to enforcement action because the licensee' efforts in identifying and correcting the violation meet the criteria specified in Section Vil B of the NRC Enforcement policy.
This violation is identified as NCV 50-425/93-03-01, Inadequate Calibration of COPS Setpoints Leads to TS Violation.
One non-cited violation was identified.
6.
Refueling Activities (60710)
On February 17, the inspectors observed the pre-refueling checkout and surveillance of the spent fuel pool fuel handling machine. These activities were performed in accordance with procedure 93100-C, Refueling Tools and Equipment Pre-service Inspection / Checkout.
The inspectors witnessed Section 4.9, fuel Handling Machine, which was performed to fulfill TS Surveillance requirement 4.9.7 to verify that the crane interlocks and physical stops prevent crane travel over fuel assemblies in the storage pool with loads in excess of 2300 pounds. The inspectors observed that this surveillance was completed satisfactorily and also noted that contractor refueling personnel identified and corrected several minor procedure discrepancies which were encountered
'
during the checkout.
I 7.
Follow-up of Open Items (90712) (92700) (92701) (92702)
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l
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'
The Licensee Event Report and follow-up items listed below were reviewed to determine if.the information provided met NRC requirements.
The determination included:
adequacy of description, verification of TS'
,
compliance and regulatory requirements, corrective action taken,
!
existence of potential generic problems, reporting requirements
!
satisfied, and relative safety significance of each event.
!
a.
(Closed) IFI 424,425/92-23-01, Evaluation of Battery Cell l
Failures.
l t
Two battery cells were sent to C & D, the battery manufacturer, i
for evaluation and laboratory testing following low voltage i
failures which occurred in late 1992. The inspector reviewed the i
results of this testing which are documented in a January 25, 1993, letter to the licensee.
Laboratory testing consisted of discharge capacity testing, periodic voltage and current i
measurements, and a cell disassembly and internal inspection.
l Both cells exceeded 100% capacity during the discharge capacity
,
tests.
Erratic float voltages that are experienced in the plant J
were not duplicated during laboratory testing.
l i
Internal inspection of one of the cells revealed that an unusual localized mound of sediment accumulated next to the inner wall of j
the support bridge. This sediment contacted the positive and i
negative plates and caused a high resistance short circuit. This confirmed the licensee's initial suspicions that the voltage
problems were caused by high-resistance shorting within the cells,
however, the cause of the sediment mounding and the plate
!
degradation was not determined. The composition of the sediment i
mounds was found to be active positive plate material.
Some
sediment deposition is normal and 1/4 inch of sediment material was present in the bottom of the cell. This was determined to be
a normal amount of deposition for a cell in service for eight j
years.
To fully investigate the continuing battery problems, the licensee established a nuclear battery task force. This group is composed l
of members from SNC, SCS, GPC,'and APC0.
In addition, two of the
'
members are battery specialists who are also IEEE-450 committee members.
The goal of this group is to investigate and evaluate
common battery problems at the three Southern Company plants. The i
task force has met three times to date and the meetings have-focused on the low voltage failures at Vogtle. The task force has
.
also recommended corrective actions such as a long term equalize q
charge.on one of the batteries, and additional data collection and J
measurements on failed cells. The licensee has also initiated
)
REAs to change TS voltage requirements and to evaluate the
"
replacement of batteries with another battery type.
Based on the review of the C & D battery testing results and the licensee's continued actions to identify the cause of battery cell failures, the inspector concluded that the licensee is taking
--
.~
h
?
!
l
appropriate action to resolve the battery voltage proDlens and=
!
considers this item closed.
.!
b.
(Closed) VIO 50-424/91-30-03, Failure to Make a Four Hour Report
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Upon Loss of RHR Safety Function
!
!
The licensee responded to the violation in correspondence dated
-
February 13, 1992. The violation involved a. failure by the j
licensee to notify the NRC within four hours of.an event that
!
could have prevented the fulfillment of the safety function of systems needed to remove residual heat. This case involved a'
cavitation problem with the Unit 1 RHR pumps.
The licensee
!
conducted training on reportability for licensed personnel during
!
routine requalification training. The personnel trained included
key managers and supervisors involved in reportability decision i
making.
The training emphasized that consideration for
!
reportability should include whether an event could have prevented I
,
j the fulf.111 ment of a safety system function not whether the' event
>
actually resulted in a loss of safety function. Also, licensee
"
management has stressed to on-shift personnel the need to consult
.
with management when making reportability determinations.
i
<
Based on this review of the licensee's corrective actions', this
!
item is closed.
i
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c.
(Closed) LER 50-424/91-09, Rev.0, Loss of Residual Heat Removal
Pump Flow During Draindown of Reactor Cavity
,
up of NRC violations 50-424/91-30-01 and 50-424/91-30-02, and
_
f The corrective actions for this event were reviewed in the follow-j t
closed in NRC inspection report 50-424, 425/92-12. The corrective
actions for this LER were similar to the corrective actions for
!
i the violations, with one exception. The LER contained an l
additional action which involved a review of the adequacy of A0P
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18019-C, Loss of Residual Heat Removal, for actions to stop a RHR
-
l pump, or actions to take after indications of vortexing or pump i
cavitation are observed. Procedure 18019-C was revised to j
specifically address actions to be taken for a loss of RHR while
j at mid-loop.
<
Based on this and the previous review, this LER is closed.
,
i i
No violations' or deviations were identified.
j
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8.
Exit Meeting l
t The inspection scope and findings were summarized on February 26, 1993,
'
,
with those persons indicated in paragraph 1.
The inspector described the areas inspected and discussed in detail the inspection findings-listed below. No dissenting comments were received from the licensee.
j-The licensee did not identify as proprietary any of the. material
~
provided to or reviewed by the inspectors during the inspection.
,
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ltem No.
D_escriotion and Reference NCV 50-425/93-03-01 Inadequate Calibration of COPS Setpoints Leads to TS Violation (paragraph Se)
9.
Abbreviations ACOT
- Analog Channel Operational Test AFW
- Auxiliary feedwater System AOP
- Abnormal Operating Procedure APC0
- Alabama Power Company CFR
- Code of Federal Regulations COPS
- Cold Overpressure Protection System
.
- Deficiency Card DG
- Diesel Generator EFPY
- Effective Full Power Years ESF
- Engineered Safety Feature F
- Fahrenheit FSAR
- Final Safety Analysis Report GPC
- Heating Ventilation Air Conditioning HX
- Heat Exchanger I&C Instrumentation and Control IEEE Z Institute of Electrical and Electronics Engineers IFI
- Inspector Follow-up Item IR
- Inspection Report ISEG
- Independent Safety Engineering Group IST
- In-Service Test LC0
- Limiting Condition for Operation LER
- Licensee Event Report MCC
- Motor Control Center MWO
- Maintenance Work Order i
- Non-Cited Violation
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NPF
- Nuclear Power Facility-l NRC
- Nuclear Regulatory Commission
_
i HSCW
- Nuclear Service Cooling Water System
!
- Piping and Instrumentation Diagram
,
- Protected Area
_
,
PE0
- Plant Equipment Operator
!
- Precautions, Limitations and Setpoints l
.
- Preventive Maintenance a
i PORV
- Power Operated Relief Valve
'
ppm
- Parts per Million PT
- Potential Transformer
REA
- Request for Engineering Analysis RHR
- Residual Heat Removal-l SAER
- Safety Audit And Engineering Review
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SCS
- Southern Company Services
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- Southern Nuclear Company i
SSPS
- Solid State Protection System j
c
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T&T
- Trip and Throttle TDAFW
- Turbine Driven Auxiliary Feedwater System i
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TS
- Technical Specifications t
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