ML20140F957
| ML20140F957 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 04/28/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20140F949 | List: |
| References | |
| 50-498-97-02, 50-498-97-2, 50-499-97-02, 50-499-97-2, NUDOCS 9705060028 | |
| Download: ML20140F957 (29) | |
See also: IR 05000498/1997002
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ENCLOSURE 2
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION IV
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Docket Nos:
50-498, 50-499
License Nos:
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Report No:
50-498/97-02,50-499/97-02
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Licensee:
Houston Lighting & Power Company -
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Facility:
South Texas Project Electric Generating Station,
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Units 1 and 2
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Location:
8 Miles West of Wadsworth on FM 521
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Wadsworth, Texas 77483
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Jates:
February 23 through April 5,1997
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Inspectors:
D. P. Loveless, Senior Resident inspector
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J. M. Keeton, Resident inspector
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W. C. Sifre, Resident inspector
F. L. Brush, Resident inspector, Callaway
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D. B. Pereira, Reactor inspector
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Approved by:
J. l. Tapia, Chief, Project Branch A
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Division of Reactor Projects
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9705060028 970420
ADOCK 05000498
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EXECUTIVE SUMMARY
South Texas Project, Units 1 and 2
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NRC Inspection Report 50-498/97-02;50-499/97-02
This resident inspection included aspects of licensee operations, engineering, maintenance,
and plant support. The report covers a 6-week period of resident inspection.
Operations
Licensed operators in both units were routinely observed performing their duties in a
professional, effective manner, continuously aware of existing plant conditions with
a good focus on safety (Section 01.1).
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Safety system condition and availability were observed to be excellent. However,
the Main Steam to Auxiliary Pressure-Control Valve Outlet isolation was found
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misaligned. Oth9r valves in the system maintained the integrity of the system
flowpath (Section O2.1).
The licensed operator response to both Uny 2 reactor trips was considered
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excellent. Operators' actions to manually trip the reactor in response to loss of
feedwater was appropriate and conservative (Sections 01.2 and 01.3).
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One noncited violation was identified because Standby Diesel Generator 11 had
been inoperable for greater than the Technical Specification allowed outage time.
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This was an event-revealed and licensee corrected violation (Section 08.1).
Maintenance
The plant systems and equipment functioned as designed following both Unit 2
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reactor trips and the response was indicative of excellent material condition
(Sections 01.2 and 01.3).
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Corrective maintenance and surveillance activities were generally performed by
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knowledgeable technicians in a quality manner using effective communications and
in accordance with licensee procedures and Technical Specifications requirements
(Sections M1.1 and M1.2).
The surveillance procedure enhancement program was effective in addressing
procedural problems. Although minor deficiencies were noted, none of the
deficiencies affected either the validity of the test nor equipment operability
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(Section M3.1).
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A noncited violation was identified for the failure to test reactor trip bypass breakers
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prior to placing in service. This was a licensee-identified and corrected violation
(Section M8.1).
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A noncited violation was identified for the failure to test a relay contact in the load
shedding circuitry. This was a licensee-identified and corrected violation
(Section M8.2).
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Enaineerina
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Engineering personnel reviewing a Unit 2 reactor trip were thorough and supported
plant operations (Section 01.2).
Engineering products reviewed were thorough and, where applicable, contained
proper unreviewed safety question determinations (Sections E1.1 and E1.2).
A noncited violation was identified because licensee engineers failed to ensure that
an alternate power source met station blackout rule requirements. This was a
licensee-identified and corrected violation (Section E8.1).
Plant Suocort
The observed activities involving radiological controls, plant chemistry activities,
and the maintenance of emergency response facilities and equipment were well
conducted and controlled (Sections R1.1, P2.1, and P2.2).
On one occasion, a security officer demonstrated weak performance in conducting
a search of a package entering the protected area (Section S1.1).
A violation was identified because licensee personnel failed to adequately perform
Technical Specification required containment inspection of the Unit 2 reactor
containment building resulting in bags of protective clothing remaining in
containment after containment integrity had been established. Several staff
members knew of the problem but none demonstrated adequate ownership to
document the problem to management. This licensee-identified violation was not
considered for enforcement discretion in accordance with Section Vll.B.1 of the
NRC Enforcement Policy because of the regulatory concerns and potential safety
significance associated with the operability of containment emergency sumps. In
addition, the corrective actions for Violation 498/96004-01 should have prevented
this event, and did not (Section R4.1).
Inadequate corrective actions taken following the identification of bags in the Unit 2
containment on February 24 resulted in additional loose debris remaining in
containment during power operations until March 27 (Section R4.1).
The fire watch personnel were knowledgeable in the classification of fires and the
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appropriate type of fire extinguisher to use for each. The licensee's fire protection
audit frequency was satisfactory (Section F8.1 and F8.2).
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Report Details
Summarv of Plant Status
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At the beginning of this inspection period, Unit 1 was operating at 100 percent reactor
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power. On April 4 licensed operators began reducing reactor power and on April 5, the
unit was removed from service for the purpose of testing rod cluster control assemblies.
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Following the completion of testing, the reactor was restarted and the main generator
breaker was closed. The reactor was at 15 percent power, and power escalation was
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continuing at the end of this inspection period.
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At the beginning of this inspection period, Unit 2 was in Mode 5, conducting Refueling and
Equipment Outage 2RE05. The reactor was restarted on February 24 and on February 25,
the main generator output breaker was closed. On March 1, following core physics
testing,100 percent reactor power was achieved.
On March 19, the Unit 2 reactor tripped when the main turbine inadvertently unlatched and
the turbine trip and throttle valves closed. This event is further described in Section 01.2
of this inspection report. On March 21, after correcting the cause of the trip, the reactor
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was restarted. On March 22, the main generator output breaker was closed. On
March 23, the unit achieved 100 percent power.
On March 26, licensed operators initiated a manual trip of the Unit 2 reactor following a
loss of feedwater to Steam Generator 28. This event is further described in Section 01.3
of this inspection report. After correcting the cause of the trip, the reactor was restarted
on March 28 and the main generator output breaker was closed. On March 29,
100 percent power was achieved. The unit was operating at 100 percent power at the
end of this inspection period.
1. Operations
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Conduct of Operations
01.1 Control Room Observations (Units 1 and 2)
a.
Insoection Scoce (71707)
Using Inspection Procedure 71707, the inspectors routinely observed the conduct of
operations in the Units 1 and 2 control rooms. Frequent reviews of control board
status, routine attendance at shift turnover meetings, observations of operator
performance, and reviews of control room logs and documentation were performed.
The inspectors observed portions of the following evolutions in addition to full
power operations:
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Unit 1 shutdown and rod cluster control assembly testing (April 5)
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Unit 2 postrefueling outage plant startup (February 23 through 25)
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Unit 2 reactor trip response and recovery (March 19)
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Unit 2 reactor trip response and recovery (March 26 and 27)
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Unit 2 posttrip plant startup (March 28)
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Observations and Findinas
During routine observations and interviews, the inspectors determined that the
control room operators were continually aware of existing plant conditions.
Operators responded to annunciator alarms in accordance with approved
procedures. Annunciator alarms were promptly announced to the control room staff
who, in turn, acknowledged by restating the announcement. The unit supervisors
remained cognizant of ongoing activities. Communications techniques utilized
during radio contacts routinely met management expectations.
The inspectors routinely attended shift turnover meetings. The on-shift operators
provided clear and concise information to the oncoming operators. Oncoming
operators routinely reviewed the control room logs, discussed current plant
conditions, and verified major equipment status. Plant managers and operations
department managers were often observed attending shift turnover meatings.
c.
Conclusions
The inspectors concluded that licensed operators in the control room performed in a
professional manner and were continuously aware of existing plant conditions with
a good focus on safety. Shift turnover meetings were thorough and routinely
attended by plant management.
01.2 Reactor Trio Durina Electrohydraulic Control System Testina (Unit 2)
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inspection Scone (9370.2.J
At 3:55 p.m. on March 19, with Unit 2 operating at 100 percent of rated thermal
power, the reactor tripped when 2 of 4 turt,ine trip and throttle valves closed. The
inspectors responded to the control room and observed the licensed operators'
response to this event. In addition, a portion of the turbine-generator building was
toured to verify reports of minimal equipment failures. Following reactor coolant
system stabilization, the inspectors reviewed the following licensee documents:
Plant Operating Procedure OPOP05-EO-EOOO, Revision 8, " Reactor Trip or
Safety injection"
Plant Operating Procedure OPOP05-EO-ES01, Revision 12, " Reactor Trip
Response"
Plant Operating Procedure OPOP07-TM-0003, Revision 4, " Main Turbine
Emergency Trip System"
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Plant General Procedure OPGP03-ZO-0022, Revision 4, " Post-Trip Review
Report"
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Condition Report 97-5730
Event Review Team Report
Event Notification Worksheet
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b.
Observations and Findinas
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Prior to the reactor trip, operators were performing Procedure OPOP07-TM-0003, as
a postmaintenance test following the calibration of the main turbine electrohydraulic
control system fluid auto stop pilot pressure, high pressure switch. During the test
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performance, a licensed operator tripped one channel of the emergency turbine trip
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circuitry. During the time that the channel was tripped, a negative spike in
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electrohydraulic control system fluid pressure was indicated. Licensee engineers
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stated that this pressure spike most likely caused the turbine to unlatch. Nine
seconds after the spike, all four turbine trip and throttle valves shut. The reactor
automatically tripped on a main turbine trip signal generated when the first two
valves closed.
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All control rods fully inserted into the core and all safety systems functioned
properly following the trip. The main feedwater system isolated on low average
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temperature, and the auxiliary feedwater system actuated on low steam generator
water levels. The inspectors observed licensed operator response. Annunciator
alarms were observed and acknowledged quickly, plant parameters were controlled
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within normal ranges, and the emergency operating procedures were being
followed. The inspectors noted that the few secondary components that failed to
operate did not adversely affect plant trip response nor complicate the unit
recovery.
During troubleshooting activities, instrumentation and controls technicians identified
that the auto stop solenoids in the electrohydraulic control system Channel 2 were
chattering. Engineers determined that this may have resulted in the system
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pressure spike during testing of Channel 1. Further investigation identified that the
power supply inverter had failed and was intermittently providing reduced voltages.
The inverter was replaced along with all four auto stop solenoids. A review of a
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modification to the electrohydraulic system conducted during the recent refueling
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and equipment outage was addressed and documented in Section E1.2 of this
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inspection report.
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The inspectors reviewed the event review team's preliminary report and the
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licensee's posttrip review prior to the plant restart. No discrepancies nor new
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information were identified during the review. Engineering personnel effectively
supported plant operations in response to the event and in determining its cause.
Plant operators restarted the reactor and the unit was returned to 100 percent rated
thermal power.
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c.
Conclusions
Plant operators responded to the Unit 2 reactor trip in an excellent manner. Plant
equipment functioned as designed with a few minor exceptions indicating
outstanding material condition of primary and secondary systems. The engineering
review of the event was thorough and supported plant operations.
01.3 Manual Reactor Trio Followina Feedwater Reculatina Valve Failure (Unit 2)
a.
Insoection Scoce (93702)
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At 9:47 p.m. on March 26, with Unit 2 operating at 100 percent of rated thermal
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power, licensed operators initiated a manual reactor trip when Steam Generator 2B
water level reached 36 percent with no indicated feedwater flow. The inspectors
responded to the control room and observed the licensed operators' response to this
event. Following reactor coolant system stabilization, the inspectors reviewed the
following licensee documents:
Plant Operating Procedure OPOP05-EO-E000, Revision 8, " Reactor Trip or
Safety injection"
Plant Operating Procedure OPOP05-EO-ES01, Revision 12, " Reactor Trip
Response"
Plant General Procedure OPGP03-ZO-0022, Revision 4, " Post-Trip Review
Report"
Condition Report 9~7-6144
Event Review Team Report
Event Notification Worksheet
b.
Observations and Findinos
Prior to the trip, the primary reactor operator responded to an annunciator alarm
indicating a mismatch between steam flow and feedwater flow in Steam
Generator 28. The operator observed a reduction in feedwater flow to
Generator 28 with an associated drop in water level. The operator placed
Feedwater Regulating Valve 2B in manual and attempted to open the valve.
However, the valve's controller already indicated a 100 percent demand signal.
When the Steam Generator 2B water level decreased to approximately 36 percent
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on the narrow range levelindicators, the shift supervisor directed the reactor
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operator to manually trip the reactor.
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All control rods fully inserted into the core and all safety systems functioned
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properly following the trip. The main feedwater system isolated on low average
temperature and the auxiliary feedwater system actuated on low steam generator
water levels. The inspectors observed licensed operator response. Licensed
operators followed plant operating procedures throughout the recovery. Controls
were manipulated in a careful and methodical manner. Shift supervision provided
appropriate levels of oversight in ensuring that plant parameters were being
maintained.
Investigation revealed that a relay in the actuation circuitry for Feedwater Regulating
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Valve 2B had failed. This failure caused the valve to close despite automatic and
manual demand for the valve to open. The resulting loss of feedwater to the Steam
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Generator 2B resulted in an unrecoverable loss in water level. Reactor operators
responded appropriately and conservatively in performing a manual reactor trip.
The inspectors reviewed the posttrip review. No deficiencies were noted. The
plant responded well following the trip. All plant equipment functioned as expected
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with the exception of one additional secondary system valve. This was indicative
of outstanding plant system and equipment material condition prior to the trip.
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Conclusions
The licensed operators decision to manually trip the reactor was both appropriate
and conservative. Operator response following the trip was considered excellent.
The response of plant systems and equipment following the reactor trip was
indicative of excellent material condition.
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Operational Status of Facilities and Equipment
02.1 Plant Tours (Units 1 and 2)
a.
Inspection Scoce (717071
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The inspectors routinely toured the accessible portions of plant areas in Units 1
and 2. Areas of special attention during this inspection period included:
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Units 1 and 2 standby diesel generators
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Units 1 and 2 isolation valve cubicles
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Units 1 and 2 turbine-generator buildings
Unit 1 essential cooling water pump cubicles
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Units 1 and 2 fuel handling buildings
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Units 1 and 2 mechanical auxiliary buildings
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Unit 2 reactor containment building
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b.
Observations and Findinas
The inspectors found that plant equipment was maintained in excellent material
condition. Plant housekeeping was good. However, several minor deficiencies
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were noted, including debris located inside the reactor containment building as
documented in Section R4.1 of this inspection report. All deficiencies were
communicated to the appropriate shift supervisor and were corrected. Licensee
managernent was routinely observed in the plant monitoring plant equipment and
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work activities for proper implementation of expectations.
On March 26, during a routine tour of the Unit 2 turbine-generator building, the
inspector observed that Valve 2-MS-0214, the Main Steam to Auxiliary Steam
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Pressure-Control Valve Outlet Isolation, was closed. A review of the associated
piping and instrumentation diagram and plant operating procedure indicated that the
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valve was improperly positioned. Operators verified the appropriate alignment and
opened the valve. The mispositioning was not considered to be safety significant
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because additional valves in the system maintained the integrity of the system
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flowpaths.
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Condition Report 97-6118 was written to address the issue. Operations personnel
reviewed the event and determined that the valve had been mispositioned during a
diagnostic leak search. Management stated that corrective actions would be taken
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to prevent recurrence.
c.
Conclusions
The inspectors concluded that equipment material condition and safety system
availability were excellent. Licensee management was actively monitoring plant
areas for material condition. One main steam system valve was found to be
mispositioned, but other valves in the system maintained integrity of the system
flowpath.
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Miscellaneous Operations issues (92901)
08.1 (Closed) Licensee Event Report (LER) 50-498/94-012: Failure to meet the
requirements of Technical Specifications. Standby Diesel Generator 11 was
inoperable as a result of an intermittent failure of the K1 contactor for the
voltage-regulator / field-flash circuit on February 3, and March 1,1994. Technical Specification 3.8.1.1.b required restoration of an inoperable diesel generator to an
operable condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
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The February 3,1994 failure was erroneously diagnosed as faulty contacts on the
VR1 (voltage release) relay that supplied power to the field flash relay. The
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normally closed contacts were found to be intermittently open, discolored, and
badly pitted. The VR1 relay was replaced, but other similar relays and the K1
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contactor were tested satisfactory. The standby diesel generator was retested and
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placed back in service. Three subsequent surveillance tests of Standby Diesel
Generator 11 were conducted satisfactorily.
On March 1, during the fourth start subsequent to the February 3rd failure, the
diesel generator again failed to obtain normal voltage and frequency during its
emergency-mode start test. Subsequent troubleshooting determined that the K1
contactor periodically failed to reset. Therefore, the licensee determined that
Standby Diesel Generator 11 had been inoperable since February 3, based on a
failed K1 contactor. This exceeded the Technical Specification limiting condition for
operati'1 allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The cause of not meeting the
requirements of the Technical Specifications was stated to be the lack of
recognition that the intermittent failure of the K1 contactor was the cause of the
February 3 event.
The following corrective actions were performed:
Voltage release relays in voltage regulator circuits and the K1 contactor of
Standby Diesel Generator 11 were replaced.
The preventive maintenance activity for the K1 contactor was enhanced.
Preventive maintenance procedures for the field-flash circuits of all six
standby diesel generators were developed.
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The inspector determined that these corrective actions were satisfactory to prevent
recurrence. The failure to restore the inoperable diesel generator to an operable
condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> was a violation of Technical Specification 3.8.1.1.b.
However, because the failure was intermittent, the K1 contactor had tested
satisfactorily during the troubleshooting activity and subsequent successful starts.
This self-disclosing event and licensee corrected violation is being treated as a
noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
(498/97002-02).
11. Maintenance
M1
Conduct of Maintenance
M 1.1 General Comments on Field Maintenance Activities
a.
Inspection Scope (62707)
The inspectors observed portions of the following on-going work activities identified
by their work authorization numbers:
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Unit 1:
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Calibration of Train A Essential Chiller Air Handling
Unit 11 A High Temperature Switch
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45446
Internal Inspection and Overhaul of Essential Cooling
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Water Self-Cleaning Strainer 1 A
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45395
Inspection and Replacement of Essential Cooling
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Water 1 A Motor Air Filters
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Service the Coupling on Essential Cooling Water Screen
Wash Booster Pump
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Unit 2:
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Hydrostatic Test of the Drain Line for Auxiliary
Feedwater Pump 24
106804
Replacement of a Main Turbine Electrohydraulic Control
System Channel 4 Inverter
b.
Observations and Findinas
The inspectors found that the work performed during these activities was
conducted in a thorough and professional manner. The work was performed by
knowledgeable, qualified technicians utilizing approved procedures. Prejob briefings
were thorough and prejob work risk assessments were performed and approved in
accordance with Plant General Procedure OPGP03-ZA-0090, Revision 8. " Work
Process Program." System engineers were observed providing quality technical
support as needed.
On one occasion, during the replacement of an electro-hydraulic control system
inverter, the inspectors observed a supervisor performing direct work activities.
Licensee management concurred that this was contrary to management's
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expectations for craft supervision in the field.
c.
Conclusions
The activities observed were conducted by qualified technicians in a professional
manner. Personnel involved were thorough in the implementation of the related
maintenance program requirements. On one occasion, a supervisor performed
direct field work, contrary to managements expectations.
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M1.2 General Comments on Surveillance Testina
a.
Insoection Scope (61726)
The inspectors observed portions of the following surveillance activities:
Unit 1:
Plant Surveillance Procedure OPSP02-CM 4105, Revision 0, "Cc,ntainment
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Hydrogen Analyzer"
Plant Surveillance Procedure OPSP02-PK-0003, Revision 3, "4.16 KV
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Class 1E Undervoltage Relay Channel Calibration /TADOT - Channel 3"
Plant Surveillance Procedure OPSP06-PK-0007, Revision 5, "4.16 KV
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Class 1E Degraded Voltage Relay Channel Calibration /TADOT - Channel 3"
Plant Surveillance Procedure 1 PSP 05-AF-7523, Revision 2, " Aux Feedwater
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Flow Loop 3 Channel C Calibration (F-7523)"
Plant Surveillance Procedure OPSP03-FC-0002, Revision 5, " Spent Fuel Pool
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Cooling Pump 1 A inservice Test"
Unit 2:
Plant Surveillance Procedure OPSP03-DG-0001, Revision 7, " Standby
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Diesel 21 Operability Test"
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b.
Observations and Findinas
The inspectors found that the observed surveillance activities were performed in
accordance with approved procedures. The inspectors noted some minor
deficiencies in the procedures. They included inconsistent equipment nomenclature,
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inconsistent notes, and steps that were designated as containing acceptance criteria
that did not. Nevertheless, Technical Specification surveillance requirements were
correctly implemented. The inspectors verified that the test equipment calibrations
were current. Good communications between the control room operators and
personnel performing the tests were noted. Prejob briefings were thorough and
comprehensive.
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Conclusions
The surveillance activities observed were performed in accordance with the
applicable Technical Specifications.
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M3
Maintenance Procedures and Documentation (92902)
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M3.1 (Closed) Violation 498/94010-01: Failure of Ooerators to Follow Plant Surveillance
Procedures
This violat;on documented several examples of the failure to follow surveillance
procedures. The problems were partly attributable to procedural inadequacies. The
specific corrective actions in response to the violation were reviewed and
documented as being adequate in NRC Inspection Report 50-498/95-23;
50-499/95 23. However, the violation remained open to track the status of the
surveihnce procedure enhancement program. The NRC's Diagnostic Evaluation
Team Report, dated June 10,1993, documented the licensee's original commitment
to establish a surveillance procedure enhancement program. Subsequently, as
documented in NRC Inspection Report 50-498/95-15;50-499/95-15, the inspectors
performed a programmatic review of the results from the enhancement program.
The inspectors determined that the enhancement program had resulted in a stronger
surveillance program. However,'the licensee had not completed the program at the
time of that inspection.
The inspectors reviewed the surveillance procedure enhancement program including:
Observations of maintenance personnel performing Technical Specification
required surveillance tests in accordance with enhanced procedures.
Discussions regarding and reviews of the status of the enhancement program
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with appropriate licensee management personnel.
The specific observations of testing were documented in Section M1.2 of this
inspection report. The inspectors noted some minor procedure deficiencies that
included: inconsistent equipment nomenclature, inconsistent precautionary notes,
and misleading information in steps designated as containing test acceptance
criteria. None of the deficiencies affected either the validity of the test nor
equipment operability. All deficiencies were discussed with the appropriate licensee
contact for evaluation and correction.
As of the date of this inspection, the licensee had completed upgrading all of the
operations, mechanical maintenance, and electrical maintenance procedures and
approximately 60 percent of the instrumentation and controls procedures. The
schedule was prioritized based on the risk associated with procedure performance.
Those that impacted high risk systems as defined by the probabilistic sr.cty
assessment were upgraded first.
Licensing organization personnel stated that the surveillance procedure
enhancement program was closed out on December 20,1995. This was based on
the assessment of low risk for the remaining procedures. Although the completion
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status of the remaining procedures was not tracked, enhancements continued to be
made using the guidelines developed for the enhancement program.
A large number of surveillance procedures were scheduled to be upgraded in
accordance with the improved Technical Specifications following their approval and
issuance. Approximately one third of the operations and instrumentation and
controls procedures williequire revision as part of the improved Technical
Specifications implementation process.
The inspectors noted that nine LERs were issued in 1994 and two in 1995 related
to surveillance procedure technical adequacy. There were no reports issued in
1996 related to procedure adequacy. This indicated that the surveillance procedure
enhancement program had been effective in addressing procedure problems.
The inspectors concluded that the licensee's corrective actions to address problems
with surveillance procedure technical adequacy were thorough. Current revisions of
surveillance procedures reviewed, properly implemented Technical Specifications
surveillance requirements. Therefore, no additional tracking or review of the
surveillance procedure enhancement program was deemed necessary.
M8
Miscellaneous Maintenance issues (92902)
M 8.1 (Closed) LER 50-498/94-007: Reactor trip bypass breaker testing had not been
performed in accordance with Technical Specifications.
On February 22,1994, licensee engineers discovered that the station procedure for
testing the reactor trip bypass breakers did not properly satisfy Technical
Specification 4.3-1, Surveillance Requirement 22. This required a test of the
bypass breaker local manual shunt trip pp>r to placing the bypa.es breaker in
service. The surveillance procedure had specified testing the bypass breaker after it
had been racked in and closed. Three other station procedures were identified with
th7 same problem. The root cause of this event was determined to be inadequate
procedure preparation and review. The Technical Specification requirement had not
been properly incorporated into the procedure when it was written and reviewed.
Tne following corrective actions were performed:
The surveillance procedure enhancement program was conducted as
documented in Section M3.1 of this inspection report.
A team consisting of a procedure writer, an engineer, and a representative of
the procedure users' organization was established for each surveillance
procedure to ensure that assigned procedures were administratively and
technically correct and able to be performed as written.
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The associated procedures were appropriately revised.
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The inspector determined that these corrective actions were satisfactory to prevent
recurrence. The failure to test the bypass breaker local manual shunt trip prior to
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placing the bypass breaker in service was a violation of Technical
Specification 4.3-1, item 22. This licensee-identified and corrected violation is
being treated as a noncited violation, consistent with Section Vll.B.1 of the NRC
Enforcement Policy (498 499/97002-03).
M8.2 (Closed) LER 50-498/95-004: Failure to meet the requirements of the Technical
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Specifications by not testing a contact of a load sequencer relay.
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On March 28,1995, while performing a review of procedures as part of the
surveillance procedure enhancement program, engineers determined that
Contact 51-52 on Load Sequencer Relay K243 had not been tested during the
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performance of the Train A loss-of-offsite-power surveillance test. This condition
failed to meet the requirements of Technical Specification 4.8.1.1.2.e 4.b, that
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required the diesel generator to energize the auto-connected shutdown loads
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through the load sequencer when a simulated loss-of-offsite-power signal was
initiated. Contact 51-52 initiated the start of several fan loads after the shedding of
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bus loads. Therefore, the failure to test this contact resulted in the failure to ensure
energization of these auto-connected loads. The root cause for this failure was
determined to be less than adequate preparation, review, and revision of the
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surveillance test procedure.
The following corrective actions were performed:
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The operability of the specific loads in question was verified by review of
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completed surveillance test data for all trains in both units.
The associated surveillance procedures were revised appropriately.
The inspector determined that these corrective actions were satisfactory to prevent
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recurrence. However, the f ailure to ensure that the diesel generator energized the
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auto-connected shutdown loads through the load sequencer following shedding of
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bus loads when a simulated loss-of-offsite-power signal was initiated, was in
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violation of Technical Specification 4.8.1.1.2.e.4. This licensee-identified and
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corrected violation is being treated as a noncited violation, consistent with
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Section Vll.B.1 of the NRC Enforcement Policy (498;499/97002-04).
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M8.3 (Closed) LER 50-498/94-020: Failure to fully meet the surveillance requirements of
the Technical Specifications because previous testing of the adjustable molded-case
circuit breakers had been inadequate.
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On December 8,1994, an NRC inspector determined that the licensee had
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misapplied the surveillance test tolerance for the 480 VAC adjustable magnetic
molded-case circuit breakers used for containment penetration protection required
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by Technical Specification 4.8.4.1.a.2. A combined total of 66 breakers from the
two units were determined to be potentially out-of-tolerance. This event was
caused by misinterpretation of the acceptance criteria.
The following corrective actions were preformed:
The surveillance test packages for potentially impacted breakers were
reviewed.
A formal procedure revision was developed incorporating use of the
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appropriate acceptance criteria.
The 66 breakers identified as inoperable during the review were tested
utilizing the appropriate acceptance criteria band.
The inspector determined that these corrective actions were satisfactory to prevent
recurrence. The failure to properly test these circuit breakers was cited as a
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violation in NRC inspection Report 50-498/94-35; 50-499/95-35. This violation
was closed as documented in Section M8.4 of this inspection report.
M8.4 (Closed) Violation 498/94035-01: Failure to perform functional testing of the
instantaneous trip element of molded-case circuit breakers by injecting a test
current within a certain tolerance of the element pickup value.
The licensee had acknowledged this violation in a letter dated February 22,1995.
As discussed in Section M8.3 of this inspection report, the corrective actions
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included a review of the surveillance test packages for potentially impacted breakers
and additional testing of a total of 66 breakers identified as being inoperable. These
corrective actions were reviewed and found to be acceptable.
M8,5 (Closed) Insoection Followun item 498:499/94025-02: Inspect the licensee's
programs for and performance of infrequently performed evolutions, surveillance
test procedures and licensee upgrade efforts, equipment clearance implementation,
and the effectiveness of the licensee's corrective actions.
The inspector reviewed selected NRC inspection reports concerning the increased
focus on the above issues. The subject areas had been reviewed during core,
regional-initiative, and reactive inspections in accordance with the master inspection
plan. Therefore, continued tracking of these areas are no longer necessary and this
IFl is administratively closed.
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111. Enaineerina
E1
Conduct of Engineering
E1.1
Evaluation of the Replacement of a Standbv Diesel Generator K1 Relav (Unit 1)
a.
Insoection Scope (37551)
On March 12,1997, Standby Diesel Generator 13 failed to develop an output
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voltage during routine surveillance testing. On March 11, maintenance technicians
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replaced the K1 relay in the generator start circuitry with a new design as part of a
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program to phase out obsolete equipment. The K1 relay was designed to flash the
generator field when the diesel started. Licensee engineers determined that the
relay had failed resulting in the valid failure of the diesel generator. The inspectors
reviewed the following design documents related to this event:
Design Change Package 96-4039-8, Revisions O and 1
Replacement item Equivalency Evaluation 95-10944-1
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b.
Observations and Findinas
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Following the initial relay replacement, the standby diesel generator successfully
passed the postmaintenance and surveillance operability tests. However, on
March 12, licensed operators started the diesel a third time for the Technical
Specification required monthly surveillance test. During the test, the generator
failed to develop an output voltage,
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Licensee engineers determined that the new K1 field flash relay had failed.
Technicians reinstalled a relay of the original design and sent the failed relay to a
laboratory for failure analysis. The standby diesel generator then passed the
montMy surveillance operability test.
The inspectors did not identify any deficiencies in the design change packages or
item equivalency evaluation. The eqaivalency evaluation was thorough. The
condition report work order contained the appropriate installation information. An
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- unreviewed safety question evaluatior' had been performed in accordance with
10 CFR 50.59. This evaluation was c.omplete and properly conducted.
c.
Conclusions
The engineers developed the design change packages and item equivalency
evaluation associated with a standby diesel generator relay replacement in a
thorough manner,
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E1.2 Review of Electro-hydraulic Control System Modification (Unit 2)
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a.
Inspection Scoce (37551)
As documented in Section 01.2 of this inspection report, a perturbation in the
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electrohydraulic control system resulted in a reactor trip. Following that trip, the
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inspectors reviewed a modification that had been implemented in the system during
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Refueling and Equipment Outage 2REOS. The inspectors reviewed the following
associated documents:
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Design Change Package 95-5755-17
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Updated Final Safety Analysis Report Section 10.2.1
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Change Notice 2117
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10 CFR 50.59 Evaluation Screening Form
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Westinghouse Operation and Maintenance Memo 085
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Unreviewed Safety Question Evaluation 96-0060
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Plant Operating Procedure OPOP07-TM-0003, Revisions 3 and 4
b.
Observations and Findinas
The modification reviewed was performed to remove the low hydraulic system
pressure trip function from the main turbine protective system. The associated trip
relays were removed, and the turbine trip first-out annunciator in the main control
room was disabled and the panel removed. This was performed to improve system
health by reducing spurious channel trips and improve the ability to latch the main
turbine. The vendor provided operational information indicating that the removal of
the trip was optional and recommending the method of removal. The inspectors
determined that the vendor's recommendations had been followed.
The unreviewed safety question determination was properly performed and
documented. Proper safety conclusions were drawn. The inspectors determined
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that a change to the Updated Final Safety Analysis Report was being processed to
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revise the appropriate drawings and words. In addition, the inspectors determined
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that no evidence existed that the modification had resulted in the March 19 reactor
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trip.
c.
Conclusions
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The documentation associated with a modification to the electro-hydraulic control
system was thorough and complete. The unreviewed safety question determination
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met the requirements of 10 CFR 50.59.
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E8
Miscellaneous Engineering issues (92903)
E8.1
(Closed) 1.ER 50-498/94-013: Failure to fully meet the requirements of the station
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blackout rule.
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On August 4,1994, the licensee conducted a reportability review that determined
that they were not fully meeting the requirements of NUMARC 87-00, which
implemented 10 CFR 50.63, " Loss of All Alternating Current Power." A self-
assessment of the station blackout commitments had identified two cases where
the criteria of 10 CFR 50.63 were not being satisfied.
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The cases related to the physical protection and electrical vulnerabilities of alternate
AC power sources used for station blackout. Although the South Texas Project
design utilized a standby diesel generator for providing electric power, the
transformers used to transfer the power to the companion train instrumentation
were not protected from likely weather-related events and were a single point of
vulnerability for preferred and station blackout power. In addition,
10 CFR 50.63(c)(2) required a demonstration test of the time required to providc
power from the alternate AC source and associated equipment. The required test
had not been performed. The root cause of this event was determined to be a lack
of familiarity by engineering personnel with the history of the station blackout
initiative.
The following corrective actions were performed:
The severe weather guidelines were changed to provide for plant shutdown
prior to any predicted hurricane landfall, rather than prior to hurricane winds
in excess of 120 mph.
The staffing of the design engineering-electrical group was doubled to one
supervisor and ten engineers.
A self-assessment of the station blackout program was conducted and
corrective actions taken.
A revised station blackout position was submitted to the NRC staff for
review.
The inspector determined that these corrective actions fully met the requirements of
the station blackout rule. In addition, the NRC staff had concurred with the revised
position and formally issued a safety evaluation report on July 24,1995. However,
the failure to initially ensure that alternate AC power met the station blackout rule
criteria was a violation of 10 CFR 50.63. This licensee-identified and
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corrected violation is being treated as a noncited violation, consistent with
Section Vll.B.1 of the NRC Enforcement Policy (498:499/97002-05).
E8.2 (Closed) IFl 498:499/94025-04: Inspect the licensee's programs for performing:
10 CFR 50.59 evaluations; inservice testing; station blackout rule implementation;
engineering backlog reduction; corrective actions associated with inappropriate use
of plant change forms, and the new modification process.
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The inspector reviewed selected NRC inspection reports concerning the increased
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inspection on the above issues. The subject areas had been reviewed during core,
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regional-initiative, and reactive inspection in accordance with the master inspection
plan. Therefore, continued tracking of these areas are no longer necessary and this
IFl is administratively closed.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1 Tours of Radioloaical Controlled Areas
a.
inspection Scone (71750)
The inspectors routinely toured the mechanical auxiliary and fuel handling buildings
in Units 1 and 2. These tours included observation of work, verification of proper
radiological work permits, sampling of locked doors, and observations of personnel
entrance and egress from the radiological controlled areas.
b.
Observations and Controls
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Radiological housekeeping in the areas toured was very good. Doors required to be
locked in accordance with Technical Specification 6.12.2 and the licensee's
radiological program were properly secured. No entrance / egress discrepancies were
identified.
c.
Conclusions
Routine radiological controls observed were considered in place and effective.
R1.2 Secondary Chemistrv Controls
The inspectors routinely reviewed secondary water chemistry reports and radiation
monitor alarm status. Secondary chemical analysis, the calculated primary to
secondary leak rate, and indication from the Nitrogen-16 radiation monitors all
confirmed steam generator tube integrity. The chemical analysis results provided
evidence of management attention and commitment to maintaining chemistry
parameters within appropriate limits.
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R4
Staff Knowledge and Performance in Radiological Protection and Chemistry Controls
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R4.1 Review of the Circumstances Surroundina items inadvertentiv Left inside the
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Reactor Containment Buildina (Unit 2)
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a.
Insoection Scoce
On February 24,1997 with Unit 2 in Mode 3, a radiological protection technician
found three bags containing protective clothing inside the reactor containment
building on the 34-foot elevation near the auxiliary airlock. Subsequently, .on
March 27, during a posttrip walkdown of the Unit 2 reactor containment building,
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an operator found piping insulation on the floor of the regenerative heat exchanger
room. Both of these events occurred after containment integrity had been
established and a Technical Specification required performance of Plant Surveillance
Procedure OPSP03-XC-0002, " Containment inspection," had been completed.
The inspectors reviewed the licensee's response and corrective actions to these
events in relation to the corrective actions of a previous similar event. This
inspection included a review of the following documents:
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Condition reports, licensee investigation reports, and corrective actions
associated with the two events.
LERs 50-498/96-003 and 50-499/97-003 and the supplement to
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LER 50-499/97-003.
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Notice of Violation 498/96004-01 and the licensee's response.
Revisions to Procedure OPSP03-XC-0002 in effect during these events.
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The inspectors discussed these reviews with the appropriate operations, engineering
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and management personnel. In addition, the inspectors performed a detailed
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walkdown of several areas in containment.
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b.
Event Description
On February 23, a licensed operator completed a Unit 2 containment inspection in
accordance with Procedure OPSP03-XC-0002, Revision 11, prior to Mode 4 entry.
Several maintenance jobs were performed inside containment during and after the
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performance of this surveillance procedure. It was management's stated
expectation that the maintenance craftsmen working inside containment would
perform and complete Form 1, " Partial Containment inspection For Loose Debris."
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This form required personnel to inspect the work area and remove allloose debris
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following work completion.
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On the morning of February 24, a radiological protection technician found three
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partially open bags containing three sets of protective clothing, a radiological control
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sign, and some plastic booties inside the reactor containment building. The material
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was immediately removed from containment. Condition Report 97-3989 was issued
to document and address this event.
On March 27, during a posttrip Unit 2 containment walkdown, two pieces of
insulation and other smallitems were found on the floor of the regenerative heat
exchanger room. The material was removed from containment and Condition
Report 97-6147 was written to document and address this issue.
c.
Historv
On May 16,1996, while Unit 1 was at 100 percent power, a health physics
technician had found plastic bags containing prestaged equipment inside the reactor
containment building during a containment inspection. As documented in NRC
Inspection Report 50-498/96-04; 50-499/96-04, the equipment had been placed in
containment in preparation for a rerueling outage. Licensee engineers had
performed an evaluation for the placement of the equipment inside containment but
had not taken into account the potential impact of plastic bags on the emergency
sump. Technical Specification 4.5.2.c.2 states that the emergency core cooling
system be verified to be operable by a:
Visualinspection of the affected areas within containment at the
completion of each containment entry when containment integrity is
' established to verify no loose debris is present which could be
transported to the containment sump and cause restriction of pump
suctions during LOCA conditions.
The inspectors had determined that Procedure OPSP03-XC-0002, Revision 9, that
had been intended to implement Technical Specification 4.5.2.c.2, had been
inadequate to ensure that the surveillanco requirements were properly performed.
The inadequate containment inspection had been cited as a violation of Technical
Specification S.8.1 and documented as Violation 498/94004-01.
d.
Observations and Fir.dinas
The inspectors reviewed the condition reports and subsequent investigation reports
for the February 24 and March 27 events. In each event, licensee personnel
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removed the loose material from containment. Engineering evaluations were
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performed to determine safety significance of the events.
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The inspectors reviewed the engineering evaluation for the items found inside the
reactor containment building. Engineers determined that the amount of containment
emergency sump blockage rcpresented by the material found on February 24 was
greater than allowed blockage as determined by the minimum emergency core
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cooling system net positive suction head stated in Table 6.31 of the Updated Final
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Safety Analysis Rept
However, they further determined that it was not likely to
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reach the emergency sumps because of a torturous path between the two locations.
The basis for this assumption was that material on or above the 19-foot elevation
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could not be transported to the containment sumps. This assumption was
contained in Calculation MC-6220, " Safety injection and Containment Spray Pump
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Net Positive Suction Head." Assumption 13 in MC-6220 stated that objects at or
above the 19-foot elevation and outside of the bioshield would not reach the sumps
unless they could fit through the grating spaces. The inspectors noted that this
assumption did not arount for the stair wells or the spaces between the grating
and the containment walls,
in addition to these actions, a containment reinspection was conducted by a team
consisting of two senior reactor operators, two reactor plant operators, and two
radiological protection technicians on February 24. The shift supervisor stated that
approximately 3/4 of a cubic foot of miscellaneous debris was removed from
containment during the inspection. This inspection did not identify the debris found
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on and after March 27.
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After removing the material from containment on March 27, five licensee managers
conducted a detailed inspection of the reactor containment building. One manager
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was assigned to each level of the building. The inspectors reviewed the list of
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items removed from containment during the management inspection and determined
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that it could not have significantly restricted flow to the emergency sumpc. The
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Unit 1 reactor containment building was also inspected, and a small amount of
debris'was removed from the building.
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The inspectors toured selected, accessible portions of the Unit 2 reactor
containment building concurrent with the management inspections. The inspectors
found less than one third of a cubic foot of loose debris during the tour that
included areas inside the bioshield.
Licensee management determined that a failure to communicate management's
expectation for the control of loose debris in the reactor containment building to
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personnel working inside containment had resulted in these events. The inspectors
discussed the events w!;h licensee personnel involved in reviewing these events and
determined that a lack of communication during containment decontamination and
closecut resulted in the bags left in containment. Each crew working in
containment thought that another crew would remove the uags, which
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demonstrated inadequate ownership of a known problem. The inspectors also
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concluded that the March 27 event indicated inadequate corrective action for the
February 24 event.
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The inspectors reviewed the results of the performances of
Procedure OPSP03-XC-0002 conducted on February 23 and 24 to implement
Technical Specification 4.5.2.c.2 prior to these events. The inspectors determined
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that the performances of Procedure OPSP03 XC-0002 were not adequate to ensure
that the surveillance requirements were properly performed. As a result, loose
material was incorrectly left in containment after containment integrity had been
established and operating modes entered. The failure to properly implement this
safety-related procedure was a violation of Technical Specification 6.8.1
(499/97002 01),
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Conclusions
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The inspectors concluded that the failure to remove the loose materials from
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containment was caused by the inadequate implementation of a Technical
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Specification required surveillance procedure. This licensee-identified violation was
not considered for enforcement discretion in accordance with Section Vll.B.1 of the
NRC Enforcement Policy because of the regulatory concerns and potential safety
significance associated with the operability of containment emergency sumps, in
addition, the corrective actions for Violation 498/96004-01 should have prevented
this event, and did not. The inspectors also concluded that corrective actions taken
following the February 24,1997 event had been ineffective in ensuring that the
materialidentified on March 27 was removed from primary containment.
P2
Status of EP Facilities, Equipment, and Resources
P2.1
Emeraencv Response Facilities (71750)
The inspectors observed that the Technical Support Centers and Operations Support
Centers in both units were readily available and maintained for emergency
operation.
P2.2 Meteoroloaical Towers (71750)
The inspectors routinely observed indication of meteorological conditions in the
main control rooms of both units. The data obtained indicated that both the
10-meter and the 60 meter towers remained operable.
S1
Conduct of Security and Safeguards Activities
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S1.1 Daily Physical Security Activity Observations (71750)
a.
Inspection Scope (717501
The inspectors observed the practices of security force personnel and the condition
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of security equipment on a daily basis. On one occasion, the inspector reviewed
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package search practices at the protected area entrance,
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b.
_ Observations and Findinas
Protected and vital area barriers were in good condition. Personnel access
measures and equipment searches for contraband were observed on a daily basis
and were well performed. One exception was noted.
On February 26, the inspectors observed an officer operating an x-ray search
machine in the East Gate personnel access point. The officer requested to search a
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lunch box that had been processed through the x-ray machine. During the search,
the officer's attention was taken away from the machine. However, the belt was
allowed to continue to move in the forward direction. During this time, the
inspector observed an individual remove a bag that had just finished processing
through the machine, and proceed to take the bag into the protected area. The
inspector noted the weak performance by the officer observing the bag process
through the x-ray machine.
This observation was discussed with the Security Force Supervisor who initiated an
investigation as documented in Condition Report 97-4353. Statements indicated
that neither the officer nor an assisting officer in the area had observed the bag
process through the machine. Security force management informed the inspector
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that a new position identified as Position 7 had been recently implemented. This
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post was established inside the badge issuance area, and was provided with
monitors to observe the X-ray signature of packages processing into the protected
area. Statements by this individual indicated that he did not observe contraband
entering the protected area.
During the inspection period, the inspectors interviewed several officers posted at
Position 7. All officers indicated that the post did not require continuous
observation of the monitors. Additionally, several officers were observed to spend
a considerable period of time performing alternate duties that took their attention
away frorn the monitors. The inspectors concluded that Position 7 was not an
acceptable alternative to the search officer's job performance.
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The collected data and interviews were not conclusive in determining that the
package observed by the inspector was properly searched prior to entering the
protected area. However, management's expectations for the search officers duties
were clearly not met. The Manager of Nuclear Plant Protection stated that the
search officer was expected to stop the x-ray machine belt prior to performing any
hand search. A training bulletin was sent to all officers indicating the
responsibilities of operating the x-ray machine.
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c.
Conclusions
in general, daily security force activities were conducted in an appropriate manner.
However, on one occasion, an officer operating the x-ray machine failed to meet
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management's expectations regarding proper procedure for hand searching articles
entering the protected area.
F8
Miscellaneous Fire Protection issues (92904)
FB.1
1 Closed) IFl 498:499/95001-01: Ineffective training in the fire watch program
identified when fire watch personnel could not describe a Class C fire.
The inspector reviewed the following training documents for certifying fire watch
personnel:
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Lesson Plan Fire Brigade Training 006.01, Revision 5, " Fire Watch"
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Fire Watch Training Handout FBT006, Revision 5
Fire Watch Certification Report, dated March 4,1997
These training documents correctly defined the four classifications of fires. The
fires were classified according to the type of materialinvolved and the proper type
of fire extinguisher to control each classification. The inspector determined through
interviews with three fire watch personnel that they were able to correctly describe
a Class C fire and the correct type of fire extinguisher to be used for each
classification. In addition, the examination for fire watch personnel required
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knowledge of fire classifications and the appropriate fire extinguisher for each type.
The inspector concluded that the fire watch personnel were knowledgeable in the
classification of fires and what type of fire extinguisher to use for each.
F8.2
(Closed) IFl 498:499/95001-03: Inappropriate audit criteria for fire protection
program.
NRC Inspection Report 50-498/95-01;50-499/95-01 documented that the
periodicity requirements for quality assurance audits had been removed from
Technical Specification 6.5.2.8 to the quality assurance program in accordance with
NUREG-1431, " Standard Technical Specifications-Westinghouse Plants," dated
September 1992. However, the inspection report noted that the Quality Assurance
Plan, Chapter 15, Revision 5, " Quality Assurance and Audit," did not specify
definite frequencies for fire protection audits.
The inspector reviewed the licensee's oversight planning and scheduling process
document that defined the audit frequency for quality assurance audits. The audit
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requirement included a nominal frequency of 24 months for fire protection audits.
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The inspector concluded that the audit frequency of 24 months was satisfactory.
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ATTACHMENT
SUPPLEMENTAL INFORMATION
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
T. Cloninger, Vice President, Nuclear Engineering
W. Cottle, Executive Vice President and General Manager Nuclear
B. Dowdy, Manager, Operations, Unit 2
J. Groth, Vice President Nuclear Generation
E. Halpin, Manager, Maintenance, Unit 2
S. Head, Licensing Supervisor
K. House, Supervising Engineer, Design Engineering Department
M. Kanavos, Manager, Mechanical / Civil Design Engineering
D. LeGrand, Performance Assessment Supervisor, Operations Support
B. Logan, Manager, Health Physics
R. Lovell, Manager, Operations, Unit 1
B. Masse, Plant Manager, Unit 2
G. Parkey, Plant Manager, Unit 1
M. Sicard, Acting Assistant to the Manager, Operations, Unit 2
F. Timmons, Manager, Nuclear Plant Protection
T. Waddell, Manager, Maintenance, Unit 1
INSPECTION PROCEDURES USED
IP 37551:
Onsite Engineering
IP 61726:
Surveillance Observations
IP 62707:
Maintenance Observation
IP 71707:
Plant Operations
IP 71750:
Plant Support
IP 92700:
Onsite Followup of Written Reports at Power Reactor Facilities
IP 92901:
Followup - Operations
IP 92902:
Followup - Maintenance
IP 92903:
Followup - Engineering
IP 92904:
Followup - Plant Support
ITEMS OPENED, CLOSED, AND DISCUSSED
Onened
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499/97002-01
Inadequate Containment inspection regarding debris not
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removed.
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498/97002-02
Standby Diesel Generator 11 inoperable for greater than
the Technical Specification allowed outage time
k.
4-
-2-
.
498;499/97002-03 NCV
Failure to test the reactor trip bypass breakers prior to
placing in service -
498;499/97002-04 NCV
Failure to test contact of vital power load shedding relay
498;499/97002-05 NCV
Failure to ensure that alternate power source met station
blackout rule requirements
Closed
50-498/94-012
LER
Valid Failure of Standby Diesel Generator 11 upon K1
Relay Failure
!
'
498/97002-02
Standby Diesel Generator 11 inoperable for greater than
the Technical Specification allowed outage time
498/94010-01
Failure of Operators to Follow Plant Surveillance
Procedures
50-498/94-007
LER
Reactor trip bypass breaker testing had not been
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performed in accordance with Technical Specifications.
498:499/97002-03 NCV
Failure to test the reactor trip bypass breakers prior to
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placing in service
!-
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50-498/95-004
LER
Failure to test a contact of a load sequencer relay.
498:499/97002 04 NCV
Failure to test contact of vital power load shedding relay
50-498/94-020
LER
Testing of the adjustable molded-case circuit breakers had
been inadequate.
498/94035-01
Failure to perform functional testing of the instantaneous
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!
trip element of molded-case circuit breakers
498;499/94025-02 IFl
Inspect the beensee's programs for and performance of
infrequently perlormed evolutions, surveillance test
,
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procedures and licensee upgrade efforts, equipment
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clearance implementation, and the effectiveness of the
licensee's corrective actions.
50-498/94-013
LER
Failure to fully meet the requirements of the station
,
blackout rule.
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498;499/97002-05 NCV
Failure to ensure that alternate power source met station
,
blackout rule requirements
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.
498;499/94025-04 IFl'
Inspect the licensee's programs for performing:
10 CFR 50.59 evaluations; inservice testing; station
blackout rule implementation; engineering backlog
reduction; corrective actions associated with inappropriate
use of plant change forms, and the new modification
process.
498;499/95001-01 IFl
Ineffective training in the fire watch training program
identified when fire watch personnel could not describe a
Class C fire.
498;499/95001-03 IFl
inappropriate audit criteria for fire protection program.
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