ML20149M540
| ML20149M540 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 12/05/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20149M532 | List: |
| References | |
| 50-424-96-11, 50-425-96-11, NUDOCS 9612170288 | |
| Download: ML20149M540 (34) | |
See also: IR 05000424/1996011
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, U. S. NUCLEAR REGULATORY COMMISSION (NRC)
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! REGION II
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Docket Nos. 50-424 and 50-425 ?
License Nos. NPF-68 and NPF-81
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Report No: 50-424/96-11, 50-425/96-11 ;
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Licensee: Georgia Power Company (GPC) !
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Facility: Vogtle Electric Generating Plant (VEGP). Units 1 & 2 !
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Location: 7821 River Road
Waynesboro. GA 30830
Dates: September 29 - November 9. 1996
Inspectors: C. Ogle. Senior Resident Inspector i
M. Widmann. Senior Resident Inspector (Acting)
K. O'Donohue. Resident Inspector (in training) >
J. Bartley. Resident Inspector. Farley (Section 01.4. M1.4.
M1.5)
R. Carrion. Project Engineer (Sections 08.1. 08.2 M8.1. :
R1.1. R1.2. S8.1) '
J. Coley Reactor Inspector (Section M2.1) -
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Approved by: P. Skinner. Chief. Projects Branch 2
Division of. Reactor Projects
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Enclosure 2
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9612170288 961205 " '
PDR ADOCK 05000424
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j EXECUTIVE SUMMARY
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Vogtle Electric Generating Plant Units 1 and 2 ;
NRC Inspection Report 50-424/96-11, 50-425/96-11
, This integrated inspection included aspects of licensee operations.
, engineering, maintenance, and plant support. The report covers a six-week
i period of resident inspection. It includes the results of an announced
- inspection by a regional reactor inspector that examined the ultrasonic
testing methods of control rod guide tube support pins during the Unit 2 fifth
! refueling outage (2R5).
Ooerations
j e Performance of startup activities from the Unit 2 refueling outage were -
l well coordinated and performed per written procedures (section 01.2).
i e Mid-loop activities were performed in accordance with written plans and
- appropriate contingency plans were available. ' Mid-loop activities were
j performed in a controlled manner (section 01.3).
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e A Unit 2 manual reactor trip occurred as a result of a steam generator
(SG) failed main feedwater regulating valve positioner mechanism
. (section 01.5).
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l e A Unit 2 automatic turbine / reactor trip occurred as a result of a blown
3 rupture disc on the main feedwater pump turbine B (section 01.6).
e A notification of unusual event (NOVE) was declared for Unit 2 due to a
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loss of function of 17 main control annunciator panels. Grounding of an
i annunciator light socket caused a blown fuse in a power supply cabinet
i that resulted in the loss of the control room alarm function
- (section 01.7).
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e A violation was identified as a result of two examples of improperly
i installed and maintained clearance points. The control room handswitch
for valve 2-HV-8220, reactor coolant system hot leg post accident
sampling system (PASS) isolation, and 2-HS-7791, reactor cavity sump
pump, were positioned contrary to their respective clearance
j designations (sections 02.1 and 02.2).
e A violation was identified as a result of an inadequately performed
j Unit 2 containment exit inspection. Loose debris were identified inside
a containment that had the potential to block the emergency sump screens
- during accident conditions (section 03.2).
- Maintenance
e Routine maintenance and surveillance activities observed and reviewed by
the inspectors were generally completed satisfactorily (sections M1.1
and M1.3). However, specific examples of unsatisfactory performance of
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maintenance activities were identified.
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e As part of the licensee's routine monitoring program, debris was l
identified in a nuclear service cooling water (NSCW) line to the '
centrifugal charging pump (CCP) 2A motor cooler, containment spray 2A
and 2B motor coolers, and safety injection (SI) pump 1B lube oil cooler i
(section M1.2). '
e Inattention to detail by maintenance personnel during reconnection of I
cabling resulted in a digital rod position indication problem with one !
control rod drive mechanism on Unit 2 (section M1.4). '
e Diesel generator train A and engineered safety features actuation system
(ESFAS) testing were performed in accordance with written procedures and
were well controlled (section M1.5).
e The inspector's review of the procedure fer tt.c ultrasonic testing (UT)
examination of the Un't 2 control rod guide tube support pins and
observation of static calibrations performed on five support ains with
electric discharge machining (EDM) notches located in applica)le defect
areas and at various depths revealed Westinghouse's examinations
techniques to be acceptable methods for determining if discrepancies are
present in the designated areas of the support pins. Review of examiner
certifications revealed that the examiners were well qualified. The
inspector's independent evaluation of UT data for forty support pins
further supported Asea Brown Boveria (ABB's) conclusion that none of the
Unit 2 control rod guide tube support pins are experiencing cracking
problems at this time (section M2.1).
e An apparent violation was identified based on the results of a
licensee's engineering evaluation that determined the Unit 1 safety
injection pump train B could have been unable to perform its intended
safety function. During a design basis accident, medium break loss of
coolant accident (LOCA). the safety injection pump motor bearings could
have failed during operation (section M3.1)
Encineerina
e A non-cited violation was identified as a result of inadequate guidance
provided in a reactor engineering procedure to calculate an estimated
critical condition (ECC). In addition, the procedure did not provide
adequate criteria for reference point selection (section E3.1).
Plant Suop_qrl I
e The residents participated in a table top emergency drill with licensee
personnel and representatives from local and state agencies. The
inspectors concluded that this exercise was useful in that it ,
established and developed better communications between the NRC resident l
staff and licensee, state, and local officials. j
Enclosure 2 l
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Reoort Details
Summary of Plant Status .
Unit 1 operated at full power throughout the entire inspection period.
Unit 2 began the ins)ection report period in mode 6 with fuel reload l
commencing on Septem)er 27, 1996. Core reload was completed on October 1.
Mode 5 was entered on October 5. mode 4 was entered on October 8. and mode 3
entry occurred on October 9. Control rods were pulled and the unit went
critical on October 11, with mode 1 entry occurring on October 12. Following
low power physics testing and )ower escalation, the unit output breakers were
closed on October 13. ending t1e 2RS.
On October 14. at approximately 78% reactor power. SG #3 level started to
fluctuate due to control problems with the loop #3 main feedwater regulating
valve (MFRV). 2-FV-0530. To ensure plant conditions remained stable,
activities were initiated to reduce power to approximately 50%. Due to
continued problems with MFRV 2-FV-0530. the operating crew made the
determination to manually trip the unit from approximately 53% power. All
rods fully inserted and the unit was safely shutdown to Mode 3. On October
15. following the replacement of a failed positioner on MFRV 2-FV-0530, plant
startup was conducted. However, due to a problem with the ECC calculation,
control rods were again fully inserted and mode 3 was reentered (see
section E3.1). After recalculation of the ECC a normal reactor startup was
achieved. Modes 2 and 1 were entered on October 15.
On October 18, the unit reached 100% power and remained there until October 21
when power was reduced to approximately 65% due to high vibration of the
train B main feedwater pump turbine (MFPT). On October 23 while trying to
place the MFPT in service. the pump casing was inadvertently overpressurized
resulting in the rupture disc being blown out causing a low condenser vacuum
condition (see section 01.6). Due to the low condenser vacuum, an automatic !
turbine / reactor trip signal was received. All safety systems operated as l
designed. The unit was stabilized in mode 3. Plant startup commenced on i
October 24. Full )ower operation was attained on October 25.-and remained
there throughout tie remainder of the inspection period.
I. Doerations
01 Conduct of Operations
01.1 Core Reload (71711)
The inspectors observed portions of the Unit 2 fuel reloading
activities. The inspectors reviewed Procedures 93300-C. Conduct of
Refueling Operations, and 93100-C. Refueling Tools and Equipment
Preservice Inspection / Checkout. In addition, the inspectors reviewed !
portions of the site reactor engineering core verification tape. No !
assemblies were identified differently than their designated planned l
position.
Enclosure 2
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Overall, based on this review the inspectors concluded that the licensee
reloaded the core in accordance with their reshuffle plan. Refuel
. activities were performed in a controlled manner and in accordance with
specified procedures. No issues were identified by the inspectors
during the reload process.
01.2 Unit 2 Startuo Observations (71707) (71711)
The inspectors witnessed selected portions of the Unit 2 startup
following 2RS. Activities witnessed by the inspectors included plant
heatup, transition into mode 2, low power physics testing, and power
escalation in preparation for turbine loading.
The performance of these evolutions was good. During the reactor
startup, the inspectors observed that reactivity additions were well
coordinated and involved appropriate oversight on the part of the
licensed operators.
01.3 Review of RCS Midlooo/ Reduced Inventory Activity (71707)
Prior to the shutdown on September 7.1996, the inspectors reviewed the
outage schedule to identify periods of midloop and reduced inventory
operation.
A six-hour midloo) period, after fuel reload, was provided in the
initial outage scledule. The inspectors reviewed planned licensee
controls during this interval in the areas of reactivity, core cooling.
RCS inventory, power availability, and containment integrity controls.
Generic Letter 88-17. the corresponding licensee response, and an
assessment of outage risk performed by independent safety engineering
group (ISEG) were also reviewed.
Based on this review, the inspectors concluded that planned controls and
equipment availability during this period of reduced inventory were '
good.
On October 3-4, an approximately 33-hour fueled midloop condition
existed. The scheduled mid-loop was lengthened due to problems torquing l
the SG~#1 cold leg and #4 hotleg manways. The licensee successfully l
accomplished the removal of a hot leg nozzle dam prior to a cold leg >
injection path being established. The inspectors verified that the i
licensee's plan was consistent with regulatory guidance. All activities !
were performed in a controlled manner. '
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01.4 Control Room Observations
a. Insoection Scooe (71707)
The inspectors observed shift turnovers on Unit 2 and performed a
limited amount of observation of the Unit 1 main control room (MCR)
activities.
b. Observations and Findinos
The inspectors observed that overall control of the MCR was adequate.
However, the inspector did observe that on a couple of occasions during
the Unit 2 outage the "At the Controls" area was entered by personnel
other than the on-shift reactor operators (R0s) without obtaining prior
permission. This was very evident during shift turnover when the crew
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(including the additional plant operators for the outage) gathered in
the Unit 2 MCR for the Unit Shift Supervisor (USS) shift brief. These
o)erators were in the MCR for approximately 20 minutes while waiting for
t1e USS. During this time the plant operators were talking and joking,
creating a distracting environment for the R0s. These observations were
limited to the Unit 2 outage shift turnovers only. These observations
were identified to licensee management.
c. Conclusions
Overall. the inspectors concluded that improvement was needed in
controlling access to the "At the Controls" area, control of
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distractions, and conducting the shift briefs during outages. '
01.5 Unit 2 Manual Reactor Trio (93702) l
At 7:28 p.m. on October 14. 1996, a manual reactor trip of Unit 2 was .
initiated in response to SG #3 low level. SG #3 level decrease was due '
to erratic control of MFRV 2-FV-0530. Control room operators placed the
valve controller in manual: however, the valve re-positioned from full
open to approximately 25 percent open. The operators were unsuccessful l
in attempts to open the MFRV further. As SG level decreased, the unit !
was manually tripped with SG level at approximately 43 percent and -
reactor power at approximately 53 percent. Post-trip plant response was I
normal with no significant complications identified. Subsequent ;
troubleshooting revealed a failed MFRV positioner mechanism. Following '
positioner replacement and additional troubleshooting to determine the
cause of the positioner failure, the reactor was restarted. Criticality
was achieved at 3:52 a.m., on October 15, 1996, with nominal full power
being achieved on October 18. 1996.
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On October 15, the ins)ectors reviewed the sequence of events report and
noted no significant a) normalities. The inspectors witnessed a portion
of the event review team's efforts and concluded that these activities '
were appropriately performed. The licensee determined that the.MFRV
Enclosure 2
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i stem inside the positioner's pilot valve was slightly worn and
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misshapen. The licensee is continuing its efforts to determine if other
anomalies contributed to the erratic valve response.
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The licensee issued licensee event report (LER) 50-425/96-006. Reactor
Trip Due To Main Feedwater Regulating Valve Closure, on November 8,
1996. No additional items were revealed by this LER. )
! The inspectors noted that operators initiated a manual reactor trip
l prior to the automatic protective function. The rapid identification
and response to the event indicated good performance of the operating
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01.6 Unit 2 Automatic Turbine / Reactor Trio (93702)
At 5:07 p.m., on October 23, 1996, an automatic turbine / reactor. trip was i
received in the Unit 2 control room during operations and maintenance !
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activities to return the Main Feedwater Pump Turbine B (MFPTB) to
service. The automatic trip signal was received with the unit at
approximately 64 percent reactor power. Post-trip plant response was
normal with no complications identified.
i- The licensee determined that during performance of Procedure 13615-2,
! Condensate and Feedwater Systems, operations personnel lined-up main
! steam to the MFPTB arior to opening the exhaust line to the condenser.
- A delay to adjust tie main shaft proximity probes at the MFPTB resulted
4 in the incoming steam overpressurizing the pump casing and blowing out
the rupture disc. Subsequently, operations actions isolated the steam
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, supply. This resulted in outside air being introduced causing a low !
condenser vacuum condition that led to the turbine / reactor trip. l
On October 23. the inspectors responded to the site and observed plant !
conditions as stable. A review of the sequence of events report noted
no significant abnormalities.. The inspectors witnessed a portion of the
event review team's efforts and various maintenance activities, and .
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concluded that these activities were appropriately performed. The
licensee determined that the blown rupture disc was caused by a
procedural deficiency that did not address the proper sequence for
opening steam line valves to return the main feedwater pump turbine to 4
service while at power. Based on this review, the inspectors concluded
that in addition to the above item, the licensee did not establish
clear concise, communication between operation and maintenance
personnel prior to commencing the MFPTB return to service procedure
13615-2. The lack of communication contributed to the decision that
resulted in the exhaust valve to the condenser remaining closed longer
than usual during valve realignment. This delay contributed to the
event.
Following rupture disc replacement, the reactor was restarted.
Criticality was achieved at 4:39 a.m. on October 24. 1996, with nominal
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full power being achieved on October 25. 1996. The licensee issued LER
50-425/96-008. Turbine / Reactor Trip While Restoring Main Feed Pump
Turbine To Service, on November 14. 1996, to document this event. The
inspectors reviewed the LER's corrective actions. The inspectors
concluded that the licensee's actions appropriately addressed the cause
of the event. The inspectors have no additional concerns with respect
to this event. :
01.7 Annunciator Function Lost in Unit 2 Control Room (93702)
At 11:10 p.m. on October 24, 1996. maintenance being performed on
annunciator ALB04-C02 ACCW RX COOLANT DRN TK HX L0 FLOW. (Auxiliary
Component Cooling Water Reactor Coolant Drain Tank Heat Exchanger Low
Flow). due to a light socket having fallen behind the alarm panel,
caused a loss of power to alarm functions on 17 annunciator panels.
During the work activity, maintenance personnel had inadvertently
grounded the light socket to the annunciator panel that caused various
alarms in the main control room.
At 1:06 a.m., on October 25, 1996, the licensee declared a NOUE on
Unit 2. The NRC. state, and local officials were promptly notified.
Due to the loss of safety related annunciator function the licensee
initiated compensatory measures that included additional monitoring of
key plant parameters. The increased monitoring activities were
continued until the event was terminated.
Subsequent troubleshooting efforts determined that a blown fuse in a
power supply cabinet caused the failure. Upon replacement of the
one-amp fuse and restoration of the alarm functions, the licensee
terminated the NOUE at 4:20 a.m. and recommenced power escalation. At
the time of the declaration reactor power had been ap3roximately 79
percent with power ascension activities in progress. Jpon declaration
of the NOUE the licensee terminated the power ascension and
appropriately stabilized the plant.
The inspectors concluded that the licensee's conservative response was
appropriate. The classification of the event was timely and all
required notifications completed. Operations shift personnel reviewed
all annunciator response procedures and took compensatory actions for
alarms affected during the event. No concerns were identified during
the inspectors' review of this event.
02 Operational Status of Facilities and Equipment
02.1 Miscositioned Unit 2 Samole Isolation Valve Handswitch
a. Insoection Scooe (71707)
The inspectors reviewed the control room boards and indications during
the Unit 2 refueling outage. This review included clearance hold tags
Enclosure 2
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and system alignments. The inspectors specifically reviewed clearance
29600288. Gross Failed Fuel Detector: PASS drawings; and Procedures
00304-C, Equipment Clearance and Tagging: and 10000-C, Conduct of
Operations. The inspectors also interviewed operations management
concerning their investigation of this issue.
b. Observations and Findinas
On October 5, while performing a walk down of the Unit 2 control room !
boards, the inspectors identified a control room handswitch for valve 2- l
HV-8220, reactor coolant system hot leg PASS sample isolation, '
Jositioned contrary to clearance 29600288 requirements. Although the
1old tag required valve 2-HV-8220 to be in the open position, the
handswitch lights indicated that the valve was closeri. The inspectors
notified the USS of the discrepancy. After verification of the
inspectors' observation, the Su) port Shift Supervisor authorized the
release of the clearance with t1e valve remaining in the closed .
position. l
The inspectors' review determined that clearance 29600288 was installed
to support removal of the Unit 2 gross failed fuel detector. Solenoid
valve 2-HV-8220 was used as a clearance point to establish a vent path
to ensure the RCS remained drained during the maintenance work activity.
Procedure 00304-C prohibits the use of a solenoid valve as a clearance
point unless the valve is mechanically blocked in the desired position. )
The licensee did not block the valve open. With the valve in the as '
found closed position the potential existed that during the performance
of work on the gross failed fuel detector the system would not be
maintained properly vented. However, work was completed on October 4,
1996, with no record of an inadvertent water spill during the period the
work activity was in progress. The licensee was unable to definitively
determine the cause of the inadvertent
re-positioning of 2-HV-8220. However, the licensee informed the
inspectors that they believed a loss of power to the solenoid occurred
sometime after the clearance was installed on September 24, 1996. An
interruption of the valve's power source would cause the valve to
reposition to its fail safe (closed) position. Due to outage work, the
licensee believed that the bus that powered this valve was inadvertently
de-energized, although the licensee was unable to verify this action.
c. Conclusions
The inspectors concluded that plant equipment was not properly
positioned in that handswitch 2-HV-8220 was not properly maintained in
its required Josition in accordance with clearance 29600288. This is
contrary to tie requirements of Procedure 00304-C which requires the
licensee to maintain plant equipment in accordance with the clearance
hold tag instructions. This was identified as an example of Violation
(VIO) 50-425/96-11-01. Imaroperly Positioned Clearance Hold Points on
Unit 2 Main Control Room 30ards - Two Examples.
Enclosure 2
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02.2 Misoositioned Reactor Cavity Sumo Pumo Handswitch
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a '. Insoection Scooe (71707)
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l The inspectors reviewed the control room boards and indications during
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the Unit 2 refueling outage. This included the clearance hold tags and
system alignments. The inspectors specifically reviewed clearance
29616044 Reactor Cavity Sump Pump 018. electrical and system drawings,
and Procedures 00304-C. Equipment Clearance and Tagging. and 10000-C.
! Conduct of Operations.
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b. Observations and Findinas
On October 8, while performing a walk down of the Unit 2 control room i
boards, the inspectors identified that handswitch 2-HS-7791. Reactor 1
Cavity Sum) Pump, was not positioned as required by clearance 29616044.
Although t7e hold tag recuired 2-HS-7'791 to be in the stop position, the
handswitch was identifiec in the automatic position. Additionally, the
inspectors noted that the reactor cavity sump pump was deenergized. The
inspectors notified the USS of the tagging discrepancy. After review,
the USS placed the handswitch in the "stop" position without incident
and in accordance with the clearance point.
The inspectors' review determined that the clearance was installed to
allow for the trouble shooting and repair of 'he reactor cavity sump
pump 018. With the handswitch in the incorrect position, potential for
an inadvertent pump start existed when the system would have been
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returned to service or if the pump had been energized for a functional
test. Review of electric drawing 2X3D-BD-P01D indicated that the
handswitch was not a spring-return to auto, rather it is a maintained
handswitch. Therefore, the switch should have been manually placed in
the stop position as indicated on the hold tag. The licensee determined
that the clearance discrepancy was a result of personnel error.
c. Conclusions
The inspectors concluded that clearance 29616044 was not installed
correctly in that handswitch 2-HS-7791 was not placed in its designated
clearance position. The incorrect handswitch position could have
resulted in an inadvertent pump start presenting a challenge to
personnel safety. This is contrary to the requirements of Procedure
00304-C in that the licensee failed to correctly Josition the equipment
in accordance with the clearance instructions. T1is was identified as
an example of VIO 50-425/96-11-01. Improperly Positioned Clearance Hold
Points on Unit 2 Main Control Room Boards - Two Examples.
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03 Operations Procedures and Documentation
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.03.1 Walkdown of Clearances (71707) l
During the inspection period, the inspectors walked down the following
clearances. ;
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19600601 Nuclear service cooling water (NSCW) pump 2 l
remove / replace pump and motor t
29600343 Component cooling water pump 5 electrical tagout ,
29600347 Containment spray pump train A mechanical tagout !
l 29615601 Turbine driven auxillary feedwater pump train C i
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mechanical tagout i
The inspectors did not identify any problems or concerns during these
walkdowns.
03.2 Unit 2 Containment Closeout Sumo Discreoancies
a. Insoection Scooe (61715)
On October 9 and 11. 1996, the ins)ectors conducted a walkdown of the
Unit 2 containment per Inspection 3rocedure 61715. Verification of
Containment Integrity. The inspectors reviewed surveillance procedure
14900-C. Containment Exit Ins)ection. deficiency cards (DCs) generated,
engineering evaluations, and ER 50-425/96-007. Inadequately Performed
Surveillance Results in Inoperable Residual Heat Removal (RHR) Pump.
The inspectors also interviewed licensee management as to their
investigation of identified discrepancies,
b. Observation and Findinas
On October 9.1996, the inspectors conducted walkdown inspections of the
containment to assess material condition prior to startup. On
October 8.1996, the licensee completed its containment exit inspection
and containment integrity had been established. During the walkdown,
the inspectors identified numerous materials within readily accessible
areas. The items included: insulation, small tools, signs paper
plastic, metal clips, screws. nuts, washers, tie wraps, and other '
miscellaneous debris. These observations were discussed with licensee
management and the material was removed from containment at the time of
the inspection. On October 9. the licensee completed an evaluation that
determined the materials identified did not represent a substantial
challenge to containment sump performance. The licensee estimated the
total surface area of the items. that could be potentially transported i
to the sumps, to be approximately six square feet.
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On October 10, while the unit was in Mode 3. the licensee conducted a l
walkdown of containment. Additional items were identified that had the
potential to be transported to the containment sump screens. Items
identified were similar in description to those items listed above. On
October 11. the inspectors conducted a second walkdown to verify that i
health protection department signs, chains, and lights, allowed to !
remain inside containment prior to Mode 2 entry, had been properly ;
removed. During that walkdown the inspectors again identified several i
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-additional items. This was identified to licensee management. j
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On October 15, 1996, the licensee determined that surveillance 14900-C :
was not adequately performed to remove loose debris from within !
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containment whereby the debris could be trans)orted to the containment !
emergency sump and cause restriction of.the RiR pump suction. The !
results of a completed engineering e/aluation indicated that this debris i
would result in a decreased flow rate of recirculating water reaching ;
the RHR pump train B suction line, and prevent the pump from having ;
l .- sufficient net positive suction head to pro)erly operate during a large I
break LOCA. The total quantity of loose de)ris identified was measured
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by the licensee at approximately 10.7 square feet. At the time the !
evaluation was completed, all loose debris had been removed from' l
containment. Based on the licensee's evaluation. RHR train A remained j
operable. ;
The licensee issued LER 50-425/96-007, on November 14. 1996. Licensee
actions included a commitment to review the inspection technique
currently being used to close out containment. The ins '
the licensee's corrective actions as part of this LER. pectors reviewed
c. Conclusions
The inspectors concluded that the containment exit inspection 14900-C
performed by the licensee on October 8, 1996, did not adequately
l identify loose debris that had the potential to block the emergency sump
- screens inside containment. Technical Specification (TS) surveillance
l requirement 4.5.2. Emergency Core Cooling System (ECCS) Subsystems,
requires the licensee to verify that no loose debris remained inside
containment 3rior to containment integrity being established. Based on
the loose de)ris identified and the results of the licensee's evaluation
that determined this condition represented a substantial challenge to
, containment sump performance, this was identified as VIO
l 50-425/96-11-02. Inadequately Performed Surveillance to Closeout Unit 2
l Containment.
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08 Miscellaneous Operations Issues (92700) !
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08.1 Personnel Outaae Work Time r
a. Insoection Scooe (71707)
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The inspectors reviewed a random sample of time sheets and overtime ;
i records of plant staff and contractors during the 2R5. The inspection !
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was conducted for plant ~ staff in performance of safety-related functions i
to verify compliance with TS 6.2.2.e.. Plant Staff, and to review the ;
overtime authorization process. The inspectors reviewed licensee ;
l documentation, including personnel payroll time sheets, personnel l
l on-site time as determined by security computerized personnel tracking ,
l logs preliminary safety audit and engineering review (SAER) audit i
, resuits of overtime usage during the 2RS and Procedure 00005-C. !
Overtime Authorization. '
!
!
! b. Observations and Findinas j
The inspectors reviewed timesheets for personnel in health physics 1
(HP)/ chemistry, instrumentation and control (I&C), and the electrical ;
l and mechanical maintenance departments. The inspectors reviewed payroll
, time sheets of randomly selected contract HP personnel and compared them !
I
to the computerized personnel tracking logs provided by the plant
security department. These records indicated that the HP personnel were !
generally on site for twelve and a half to thirteen hours at a time and i
L were compensated for twelve hours of work. The licensee allowed for a ;
l thirty-minute non-compensated lunch period each day. None of the !
individuals selected were found to have worked in excess of the TS l
L allowed maximum 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per any seven-day period even though they were !
l onsite for longer periods of time. The inspectors also reviewed the ;
preliminary findings of SAER for overtime usage in the maintenance and 4
radiation protection departments. The inspectors discussed the findings :
- with the SAER auditors. SAER auditors determined that plant management
l
'
closely followed the referenced TS and the required written
authorization procedure. The SAER audit report determined that no :
overtime was in excess of TS requirements and most overtime was properly l
authorized. i
'
j
l c. Conclusions
Overall, the inspectors concluded that the licensee was in compliance
I with TS requirements for plant staff hours. In addition, the inspectors l
noted that deviations from TS 6.2.2.e guidelines were approved in l
accordance with procedure 00005-C. Based on the inspectors * review no
systematic abuse of overtime was identified. No items of concern were :
identified during this review.
l Enclosure 2 i
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l 08.2 (Closed) LER 50-425/96-001: Offsite Power Sources Not Verified in l
l Technical Specification-Prescribed Time Frame
This issue was addressed in Paragraph 3.c of Inspection Report 50-424,
425/95-31, resulting in Non-Cited Violation (NCV) 50-425/95-31-03. The
inspectors reviewed the corrective actions listed in the LER to assure
adequacy to prevent recurrence and to verify their completion. The l
corrective actions included counseling the USS involved and i
incorporating the lessons learned from the event into licensed operator
recualification training. Documentation provided by the licensee
incicated that the USS was counseled regarding human performance errors
on January 30. 1996, and that the issue was addressed during the
licensed operator requalification training of July 1996. The inspectors
determined that these corrective actions were adequate and closed LER
50-425/96-001.
08.3 (Closed) LER 50-425/96-006: Reactor Trip Due to Main Feedwater
Regulating Valve Closure. !
l
This issue was discussed in this report, as ) art of Section 01.5. No
new issues were revealed by the LER. This LER is closed.
08.4 (Closed) LER 50-425/96-008: Turbine / Reactor Trip While Restoring Main
Feed Pump Turbine to Service.
This issue was discussed in this report, as aart of Section 01.6. No
new issues were revealed by the LER. This LER is closed.
08.5 (Closed) LER 50-425/96-007: Inadequately Performed Surveillance Results
in Inoperable RHR Pump.
This issue was discussed in this report, as ) art of Section 03.2. No
new issues were revealed by the LER. This LER is closed.
II. Maintenance .
!
M1 Conduct of Maintenance i
M1.1 Maintenance Work Order Observations
a. Insoection Scooe (62707)
The inspectors observed portions of maintenance activities involving the
following work orders:
1
29401727 Troubleshoot control bank A. rod K8 failure during hot I
rod drop testing: replace card A216 )
29502375 Repair auxiliary feedwater check valves 21302U4113 and 1
21302U4116
Enclosure 2
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, 29600663 Inspection of SG feedwater nozzles flow elements
2FE510, 520, 530 and 540 per SCLO2465
29601105 Implement design change package (DCP) 95-V2M057; 7300 ,
process control reliability in pressurizer pressure
protection channels i
29602119 SG loop 1 wide range level. transmitter 2-LT-0501: leak
in a five-way manifold
29602157 Replace control room handswitch hydrogen pressure
control valve to volume control tank 2-PCV-8156
29602231 Boric acid storage tank transfer pump 007 discharge
1 pressure low
' '
29602621 Investigate and repair 2-FV-0530 SG #3 main feedwater
regulating valve
b. Observations and Findinas
i
The observed maintenance activities were performed satisfactorily.
M1.2 Unit 2 NSCW Flushina Activities
a. Insoection Scooe (62707)
The inspectors reviewed recent licensee activities to remove and
evaluate debris from the NSCW system. This included a review of the !
following maintenance work orders (MW0s) and DCs: l
19602248 Disassemble and flush safety injection pump 1B l
4
lube oil cooler !
, 29600022 Disassemble and flush centrifugal charging pump
- 2A motor cooler
>
29602416 Disassemble and flush containment spray pump 2B .
- motor cooler l
29602700 Disassemble and flush containment spray pump 2A
motor cooler
'
DC 1-96-460 Degraded NSCW flow to safety injection pump 18
lube oil cooler
DC 2-96-133 Debris found during flush of centrifugal
charging pump 2A motor cooler
DC 2-96-208 Degraded NSCW flow to containment spray 28 motor
-
cooler
DC 2-96-225 Debris found during flush of containment spray
2B motor cooler
DC 2-96-279 Degraded NSCW flow to containment spray 2A motor
cooler
b. Observations and Findinas
On September 10. 1996, while performing MWO 29600022. the centrifugal
charging pump 2A motor cooler was flushed. Debris removed included two
Enclosure 2
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l stainless steel pieces of wire, one seven inches long and the second two
l inches long. Post-flush NSCW flow were reported as normal.
1
On September 30. 1996. while performing the routine surveillance. NSCW
system flow to the containment spray pump 2B motor cooler was measured
at 15.3 gallons per minute (gpm). Although this flow rate was above
minimum NSCW flow for operability. it was below the surveillance
I
acceptance criteria. Per MWO 29602416. the pump was removed from
service and the cooler orifice flushed. Miscellaneous debris was
removed from the system's lines.
On October 23, 1996, during a surveillance on the containment s] ray
pump 2A motor cooler, flow was measured at 9.5 gpm. Although t11s flow
rate was above minimum NSCW flow for operability, it was below the
surveillance acceptance criteria. Per MWO 29602700, the pump was l
,
i removed from service and the cooler orifice flushed. Debris removed
included some concrete and a piece of "Y" shaped expanding metal mesh.
The pump was returned to service and post-flush NSCW flows were reported
as normal.
'
On November 1, 1996. during a routine surveillance, the licensee
measured NSCW system flow to the safety injection pump 1B lube oil
cooler at 4.5 gpm. which was below the surveillance acceptance criteria.
However, given that this flow remained above a previously calculated
minimum of 3 gpm. the pum) was not declared inoperable. Per MWO
19602248. the pump was suasequently removed from service and the motor
cooler flow orifice flushed. A piece of metal approximately 0.375 x 3.8
inches was removed during the flush. Post-flush flow was verified to
have returned to normal.
! c. Conclusions
The ins)ector concluded that the licensee's efforts to clean up the NSCW
system las not, to date, captured all debris within the system. The '
licensee's four additional instances of debris in the NSCW lines to
safety-related components is evidence that problems continue.
M1.3 Surveillance Observation
a. Inspection Scooe (61726)
The inspectors observed the performance or reviewed the following
l
surveillances and plant procedures:
14005-2 Shutdown margin calculations
14406-2 Boron injection flow path verification - shutdown
14546-2 Turbine driven auxiliary feedwater pump operability test
14666-2 Train A diesel generator and ESFAS test
14748-2 Auxiliary feedwater system pump and check valve cold
4
shutdown inservice test
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Enclosure 2
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14721-2 ECCS subsystem flow balance and check valve refueling
inservice test *
! 14786-2 Turbine driven auxiliary feedwater pump overspeed test !
14804-2 Safety injection pump inservice test !
.14807-2 Motor driven auxiliary feedwater pump inservice test- t
14810-2 Turbine driven auxiliary feedwater pump and check valve i
inservice test !
14850-2 Cold shutdown valve inservice test
14980-2 DG operability test
24478-2 SG #3 level control 2-FV-0530 and 2-FV-0532 channel i
calibration i
88006-C Rod drop time measurement with rod drop test cart l
93660-C VEGP special nuclear material control and accountability j
manual physical inventories of special nuclear material i
93663-C VEGP special nuclear material control and accountability
manual verification of core loading pattern
In general, the observed surveillance activities were performed
satisfactorily with the following concern reviewed in further detail
,
below.
,
b. Observations and Findinas
During the performance of surveillance 14721-2, ECCS Subsystem Flow
Balance and Check Valve Refueling Inservice Test. Unit 2 centrifugal
charging pump (CCP) B's total flow was measured at 636.6 gpm for two
minutes. Procedure 14721-2, Precaution and Limitation section 3.4
delineates that total flow for a CCP shall be kept below 555 gpm to
prevent possible pum) run-out. The reactor operator lowered CCP 28 flow ,
to below 555 gpm wit 11n two minutes. Site engineering requested that l
corporate engineering perform an evaluation for possible pump damage due
to the high flow condition. The evaluation determined that, in view of
the short duration of the high flow condition and that the CCP 28
subsequently performed satisfactorily during the test. CCP 2B was
operable and not damaged.
Additionally, while performing section 5.2, Safety Injection Pump (SIP)
Cold Leg Injection Lines, of surveillance 14721-2. the measured total i
pump head for SIP 2B was 1579.7 feet at 649.3 gpm. This was below the ,
minimum required pump curve. An engineering evaluation determined that I
the values were within allowable tolerances based on additional margin
available in the pump's performance curve.
c. Conclusions
Based on direct observation and interviews the inspectors concluded that l
l surveillance 14721 2 was performed adequately. After review of final
l safety analysis report (FSAR) Chapter 6. Engineering Safety Features,
i and discussions with site engineering personnel, the inspectors also
l concluded that the engineering evaluations adequately address pump
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l operability issues identified during the performance of 14721-2. The !
inspectors have no operability concerns related to CCP 2B or SIP 2B.
i
M1.4 Cold Rod Droo Testina Eauioment Failures !
a. Insoection Scooe (61726)
On October 8. several equipment failures occurred during cold rod drop ,
testing. As a result, on October 8, 1996, the inspectors observed
limited portions of Cold Rod Crop Testing conducted per 88006-C, Rod ,
Drop Time Measurement With Rod Drop Test Cart. The inspectors also i
reviewed procedure 93240-C, Reactor Vessel Assembly / Disassembly !
'
Instructions. Revision 27. to determine the controls of the cables
during assembly. I
b. Observations and Findinas
The rod drop testing commenced on October 8. 1996, at about 4:00 PM. It !
was interrupted several times by equipment failures. Rod K8 did not
move during the first attempt to pull control bank (CB) A due to a blown -
fuse. The fuse was replaced. but a pulse-to-analog (P/A) converter card
failed during the second pull. The operators were successful in fully ,
withdrawing CB A but had to re-insert the bank when the troubleshooting
efforts on the P/A converter unplugged the 110 V power cord to the test '
cart. These equipment problems delayed the rod drop testing by several
hours.
The operator commenced testing of CB C after completing CB A. The
operator was quick to observe that rod H14 did not appear to be moving
out with the bank. The operator also observed that rod K14 (CB B)
appeared to be moving out with CB C. The operator stopped pulling CB C
prior to receiving any annunciators. The crew promptly reinserted the
rods and opened the reactor trip breakers to troubleshoot. The licensee
determined that rod K14 did not actually move but that the train A
digital rod position indication (DRPI) cables for rods H14 and K14 were
reversed during installation. .The licensee connected the cables
correctly under MWO 29600200. The licensee also verified the B train
DRPI cables and the control rod drive motor (CRDM) cables for rods H14
and K14 were correctly installed.
The ins)ector found that the reconnection of the cables to the reactor
vessel lead was directed in steps 4.33.10 and 4.33.11 of procedure
93240-C. These steps directed the technician to document the
reconnection on Data Sheets 3 and 4. Data Sheet 4. Power and Signal
Cable Removal / Replacement, provided a table to document removal and
L reconnection of each cable. The inspector noted that neither the DRPI
nor the CRDM cables required independent verification of proper
reconnection. The inspector determined that, while in this case there
was no safety impact, the technician could have just as easily reversed
l
,
the CRDM cables. The CRDM cables and DRPI cables are labelled alike.
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Enclosure 2
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are in the same location, and, in this case, were reconnected by the ;
same technician. The inspector looked at the labeling at the connector i
'
! plates and on the cables to determine if it was a contributing factor to
l the error. The inspector found that the labeling was clear and legible.
!
The inspector determined the error was caused by inattention to detail
on the part of the installing technician. [
c. Conclusions ;
The inspector concluded that, while the cold rod drop testing ~was
delayed by equipment problems, the operators were quick to observe t
problems prior to receiving alarms and the evolutions were well- ,
controlled. The inspector also concluded that the DRPI rolled cables '
were caused by inattention to detail while reinstalling the cables.
M1.5 Diesel Generator and ESFAS Testina '
a. Insoection Scooe (61726) j
The inspector observed erformance of DG and ESFAS testing as part of
the safety-related comp ex surveillance TS requirements. This
surveillance is conducted once every 18 months.
b. Observations and Findinas
On October 1. 1996, the inspector observed performance of procedure i
14666-2, Train A Diesel Generator and ESFAS Test. Section 5.2. Loss-Of- '
Offsite-Power (LOSP) In Conjunction With An Engineered Safety Feature ;
(ESF) Actuation Test Signal Followed By Safety Injection Actuation With j
The Diesel Generator In A Test Mode: Section 5.3. DG Start on LOSP: and
Section 5.4. DG Start on Safety Injection (SI) Signal. The inspector i
reviewed results documented in the completed procedure and verified that t
test results met the acceptance criteria of each respective section. .
The inspectors also verified that the test results met surveillance i
requirements of TS 4. 8.1.1.2. The inspector also reviewed the failed ;
component / test exception logs for both the A and B train ESFAS tests and !
verified that test exceptions were retested or dispositioned properly, i
c. Conclusions i
The inspectors concluded that DG and ESFAS tests were performed in ,
accordance with written procedures. The inspectors identified several !
minor administrative -issues that were forwarded to the licensee and l
appropriately dispositioned. Overall, all test activities observed were :
well controlled.
l
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Enclosure 2 i
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H2 Maintenance and Material Condition of Facilities and Equipment !
j M2.1 UT Examination of Control Rod Guide Tube Suooort Pins
,
a. Insoection Scooe (57080)
As a result of having experienced a control rod guide tube su port pin
. failure prior to the: spring 1996 Unit 1 outage, the licensee decided to
-
- . ultrasonically examine all of the control rod guide tube support pins on
i Unit 2 during outage 2RS. Westinghouse was the vendor selected by the
- licensee to perform the UT examinations. However. Westinghouse
subcontracted ABB/ Combustion Engineering Nuclear Services to actually
conduct the UT examinations to Westinghouse's Quality Assurance Program
and procedures.
4
l b. Observation and Findinas
ABB performed the UT examinations of the support pins utilizing its
,
~
automatic ultrasonic manipulator while the upper internals were in the
refueling support stand. The UT inspection of each guide pin consisted
'
of two techniques. Two longitudinal wave transducers statically
examined each leaf of the pin and two shear wave transducers statically
i
examined the collet-to-shank area from the slot in the pins. The areas !
-
in the pins where stress corrosion cracking has historically been i
observed is in the leaf adjacent to the bottom of the slot and at the
i
'
change-in-section between the collet and the shank. ABB was able to
examine each leaf of all 122 support ains. However, only 93 of the
support pins could be examined with tie shear wave transducers because
of apparent slot size irregularities. No defects were observed by ABB
i
with either of the UT techniques utilized. In addition, visual ,
examinations performed with the cameras mounted on the UT manipulator !
during the in-process UT examinations did not reveal any discrepancies. l
Although the UT examinations had been completed prior to the inspectors'
arrival on-site. Westinghouse's UT Examination Procedure Number l
STD-FP-1996-7842. Revision 1. UT Inspection of Guide Tube Support Pins !
At Alvin Vogtle - Unit 2, was reviewed to determine the adequacy of the
examination techniques. Certification and qualification records for two
Level III and four Level II examiners were reviewed to determine the
level of experience of the examiners. System calibrations and UT
examination results for 40 support pins out of a total population of 122
were evaluated by the inspector reviewing a video tape of the UT
instrument screen presentations for each of the static calibrations and
examinations.
c. Conclusion
The inspector's review of the examination procedure and observation of
static calibrations performed on five support pins with EDM notches
located in applicable defect areas and at various depths revealed both
Enclosure 2
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18
examination techniques to be acceptable methods for determining if
discrepancies were present in the designated areas of the support pins.
Review of examiner certifications also revealed that the examiners were
well qualified. The only weakness observed in the process was the lack
of sufficient electrical interference filtering use when conducting the
shear wave examinations. This interference made evaluation difficult
for many of the support pins when viewing the video tapes of the
examinations and could result in impro)er evaluation of the examination
results if allowed to deteriorate furtier. However, the inspector
concluded that the equipment used and the inspection techniques
developed for examination of the support ains were adequate to determine
whether the support pins were cracked. T1e inspector's independent
evaluation of forty support pins further supported ABB's conclusion that
none of the Unit 2 control rod guide tube support pins are experiencing
cracking problems at this time.
M3 Maintenance Procedures and Documentation
M3.1 Unit 1B SIP Inability to Perform Its Safety Function
a. Insoection Scooe (62707)
The licensee determined on November 12. 1996 that the Unit 1 SIP train B
could have been unable to perform its intended safety function during a
design basis accident due to insufficient motor cooling resulting in
failure of the motor bearings at elevated temperatures. In addition.
discussions with site personnel indicated that the plant may not have
been able to respond to a medium break LOCA. due to periods of time
since September 1991 whereby both trains of safety injection would have
been simultaneously unavailable.
The inspectors reviewed the circumstances surrounding the Unit 1 SIP
train B motor cooler configuration and subsequent ability to perform its
intended designed safety function. The inspectors' review of this issue
included: interviews with licensee management, engineering, and
maintenance personnel; review of associated MW0s, resulting DCs, and
engineering analysis: and observation of the fiber scope activity.
b. Observations and Findinas
On October 15, 1996, a concern was identified by a plant equipment
operator (PEO) during the performance of plant equipment rounds that
Unit 1 SIP train 8 did not have sufficient motor cooler cooling water
flow. System engineering measured the cooling water pipe temperatures
and verified that pipe temperatures indicated low cooling water flow
conditions. An inspection of the inboard motor cooler with a fiber
scope revealed that the inboard motor cooler plenum gaskets were
installed backwards. This installation blocked the cooling water
flowpath through the motor cooler tubes.
Enclosure 2
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Site system engineering requested the licensee's corporate engineers to
evaluate the operability of SIP 1B with only one motor cooler available.
The resulting engineering evaluation, dated October 15, 1996, stated
that SIP 1B was operable with a minimum cooling flow of eight gpm per
motor cooler. However, based on a previously measured total flowrate of
34 gpm the engineering evaluation determined that this also would be
adequate flow with just one motor cooler.
As a result of the blocked motor cooler system engineering personnel
requested that the gaskets be re-installed. During the replacement of
the gaskets, the motor cooler plenums were removed to the maintenance
work shop to allow more accurate gasket measurements. While observing
the maintenance activity a site engineer questioned the installation of
the motor cooler plenum and orientation of the internal baffle. It was
determined that it would be possible to install the plenum backwards and
not detect the erroneous installation. Additionally it was determined
that if the plenum was installed backwards the cooling water flowpath
would be reduced from a three-pass, cross-counterflow, flowpath to a
single-pass flowpath. This would decrease the available area for heat
transfer by two-thirds per motor cooler.
Based on this possibility, engineering personnel examined motor coolers
of similar type to determine if plenums were installed backwards.
SIP 18 and Unit 2 containment spray pump (CSP) train A motor coolers !
were identified as each having one plenum installed backwards. '
Immediate corrective actions were initiated to re-install the plenums in
the correct orientation.
With one plenum reversed, the 2A CSP motor cooler cooling water flow
path was reduced to four-sixths of its total design flow which based on
a licensee engineering review, was determined to be adequate to ensure
operability of the pump. However, due to both SIP 1B motor coolers
flowpaths being affected (one completely blocked and the other with
reduced heat transfer capability), a second engineering evaluation was
performed. The evaluation reviewed the operability of SIP 1B due to the
inboard motor cooler's reversed gasket installation concurrent with the
outboard motor cooler's backwards plenum. This condition resulted in a
total available heat transfer surface being one-sixth of the design
surface. The second engineering evaluation was completed November 1,
1996. At that time, the evaluation results did not determine if the
SIP 1B would have been capable of performing its intended safety
function. This engineering evaluation included a statement that
operating the SIP in the reduced cooling flowpath condition could result
in a reduced cualified life of the motor: the extent of reduction was
not quantifiec.
Additional review of these conditions resulted in a third licensee
evaluation undertaken to determine the safety consequence on the )lant. ,
The licensee's engineering evaluation assumed that the SIP would )e l
required to operate for 24-hours into a design basis accident. Based on l
l
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l
the results of the engineering determination the licensee concluded that
the motor bearing would be operated at elevated temperatures that could
result in bearing failure within two hours. Therefore, the pump could
have been unable to perform its intended safety function for that design
basis accident. Additionally, a review of out service times of the last
18 months for the other ECCS pumps indicated that SIP train A was remove
l from service three separate times. The length of times varied from
approximately one hour and nine minutes to at least two hours. The <
, times that SIP train A and train B were simultaneously unavailable
!
resulted in the potential that the plant would not have had the required
safety injection function to fully mitigate conditions of a medium break
LOCA.
l
l Upon identification of this discrepant condition, the licensee commenced
l immediate corrective action to re-install the reversed plenum gaskets.
The licensee declared SIP 18 operable on October 23, 1996. On
October 25. the licensee successfully completed corrective maintenance
work on the motor cooler to re-install the plenum in its designed
orientation. A review of previously completed MW0s indicated that the
SIP was in this degraded condition from September 30. 1991, when it was
last inspected until October 23, 1996, when one of the two motor coolers
,
was made available as a cooling medium.
The licensee's additional preliminary corrective actions include
,
revising the 3reventive maintenance (PM) checklist SCL02238. NSCW Heat
! Exchangers Jeriodic Inspection, and Procedure 29402-C. Maintenance
Work Request Processing, to include precautions regarding orientation of
motor cooler gaskets and plenums: revise the PM checklist SCLO2238 to
include taking temperature readings of the plenums, and measuring
individual motor cooler flows. rather than total flow per pump motor:
and match marking coolers to prevent incorrect orientation. In
addition, the licensee plans to perform engineering evaluations with
respect to past operability of ECCS pumps and present qualified life of
the motors due to incorrectly installed gaskets and/or improperly
orientated plenums.
l
c. Conclusions
l The inspectors concluded that the motor cooler plenums and gaskets were
installed incorrectly due to inadequate procedural guidance and
insufficient cooler component configuration knowledge. The PM checklist
SCLO2238 provided with work orders to inspect the motor coolers did not
contain adequate guidance to enable maintenance personnel to assemble
I and disassemble similar type ECCS motor coolers. Due to the work
! performed on SIP 1B motor coolers on September 30. 1991. Unit 1 SIP
! train B was rendered in a condition whereby it could not have been able
l to perform its intended safety function due to insufficient motor
I
cooling.
Enclosure 2
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l
TS 6.7 Procedures and Programs, requires written procedures to be
established, implemented, and maintained. Contrary to the above, the
licensee failed to properly establish maintenance procedures on
i September 30, 1991, in that adequate guidance was not provided by
maintenance checklist SLC02238 as part of work order 19102059, to
correctly install the motor cooler gaskets and plenums. The procedure
lacked specific instructions for maintenance personnel to properly
assemble the SIP 18 and CSP 28 motor cooler plenums in their proper
orientation. This was identified as an apparent violation EEI
50-424/96-11-03, Unit 1 SIP Train B Loss Of Function.
M8 Miscellaneous Maintenance Issues (92902)
M8,1 (Closed) VIO 50-424. 425/96-02-02: Failure to Properly Implement Wire
Lift Procedure
This item was addressed in Paragra)h 3.3 of Inspection Report
50-424,425/96-02. The licensee su)mitted its re)1y to the NRC Notice of
Violation (NOV) by letter dated June 3, 1996. T1e inspectors reviewed
the root cause determination and corrective actions completed by the
licensee to avoid recurrence. The inspectors verified completion of the
corrective actions, which included the counseling of the individuals
directly involved in the event, briefings of maintenance personnel
shortly after the event happened. and including the event in the
maintenance department's continuing training subjects. The inspectors
also reviewed the training lesson plan, training handouts, and personnel
attendance sheets for the training and briefings. All were determined
to be adequate. This VIO is closed.
III. Enaineerina
E3 Engineering Procedures and Documentation
E3.1 ECC/ Estimated Critical Position (ECP) Miscalculation
a. Insoection SCoDe (37551) l
The inspectors reviewed the activities associated with the October 15,
1996. Unit 2 startup activity when a miscalculation of the ECP occurred. 4
Involved operations and reactor engineering personnel were interviewed. I
Review of related procedures included the computer code " APEX" User
'
Manual: 00410-C Control of Computer Software: 88010-C Computer
Calculations of Estimated Critical Conditions; and 12003-C Reactor
Startup (Mode 3 to Mode 2).
b. Observations and Findinas
l On October 14, 1996, during post refueling power ascension, the Unit 2
'
reactor had been manually tripped from approximately 53 percent power
j Enclosure 2
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22
due to a failed feedwater regulating valve. The valve repair was
completed and reactor startup commenced at 3:52 a.m.. October, 15, 1996.
To support the reactor startup, the ECC and ECP were calculated per
l procedure 88010-C. The ECC is calculated using the APEX computer '
program. Inputs to APEX include boron concentration, power. rod height,
and a ten day power history at a chosen reference point. The reference
point to be selected for input into APEX must be within a 72-hour time
period of the trip and the reactor conditions stable and known. Based -
on that criteria, the reactor conditions at the completion of the
moderator tem)erature coefficient test, within the 72-hour period, was
I
selected as tie reference point by site reactor engineering.
The APEX calculation results determined criticality to be at 180 steps
on CB D. Control rods were withdrawn until CB D was at 200 steps. Site
reactor engineering plotted the Inverse Count Rate Ratio Graph (ICRR)
per procedure 12003-C and monitored doubling of the count rate during
the evolution. Normally, criticality is obtained within approximately
l five doublings of the count rate. At 200 steps on CB D the ICRR
indicated that the reactor would not go critical at 228 steps on CB D.
The counts had only doubled three times, therefore the startup was
aborted, and control rods (CB D) were inserted to zero steps.
Site reactor engineering could not determine why the original ECC was
inaccurate. However, after conferring with cor) orate personnel, a
different reference point (still within the 72-lour period) was used in
the APEX computer program and a second ECC was completed. This reactor
l
'
startup commenced at 2:20 p.m.. October 15. 1996. Criticality was
achieved at 3:41 ).m. and mode 1 entered at 8:09 p.m. No problems were
observed during t1e startup.
i The inspectors noted that the cause for the inaccurate ECC and ECP was
l not specifically identified. Although the reference point selected for I
i
use in the first ECC calculation appeared to meet the criteria i
appropriately, a different reference point was selected by corporate
,
personnel for the second ECC. Apparently, startup conditions which are
! close to initial criticality and do not have a 10 day power history are
l
'
not adequately profiled in the APEX program. This being the case. the ,
criteria for reference point selection appears to be more stringent than l
for more typical startups with at least 10 days power history. Based on '
l discussions with the site reactor and corporate engineers, it appears
! that corporate personnel had sufficient knowledge to "get the code to
work" in the post refueling non-equilibrium condition where as the site
reactor engineering personnel did not.
L
c. Conclusions
l
Theinsbectorsconcludedthat88010-Cdidnotprovideadequateguidance
to calc late an accurate ECC after a reactor trip, within ten days of an j
<
1
Enclosure 2 l
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. - - _ - - - - - . . . . - - - - - - - . - . ~ . - - .. .
.
.
7
.
23
l
l initial criticality, nor did it provide adequate criteria for reference
point selection.
rocedure
l Asaresultofthisproblem,thelicenseeplanstoenhance$owing:
88010-C and the APEX users manual to better address the fol APEX
,
calculations for low burnup cores: determining average rod and average
power over periods of zero power: directions for determining proper time '
periods and burnup for core depletion history, reference point, and ;
shutdown time: identifying numerical significance required for each
'
field in the arogram. The licensee requested corporate staff to
re-evaluate t1e current Unit 2 cycle 6 core modeling data used by APEX
to determine acceptability of modeling and expected accuracy of
calculations. The licensee recommended that training on the use of the
APEX code be 3rovided that addresses these issues and the expected
accuracy of tie calculations. Additionally, site reactor engineering
personnel are re-evaluating the methods used to determine estimated
critical rod heights.
The inspectors concluded that although the startup did not commence as
planned on October 14, 1996, the startup activities were controlled by
reactor engineering and the on-duty' reactor operator at all times. The
inaccurate determination of the ECC and confusion of on-site engineering
personnel is indicative of weak reactivity management process.
TS 6.7 Procedures and Programs, requires written procedures to be
!
established, implemented, and maintained. Contrary to TS 6.7 the
licensee failed to properly establish procedure 88010-C in that adequate
guidance was not provided to accurately determine the ECC. However,
consistent with Section VII of the NRC Enforcement Policy this was
identified as NCV 50-425/96-11-04, Inaccurate Calculation of Estimated
Critical Condition.
E8 Hiscellaneous Engineering Issues (92903)
E8.1 Enoineerina Followun
'
(Closed) LER 50-424/96-007: Main Steam Isolated When Steam Dump Valve
Failed Open
This LEF documented an unplanned ESF actuation due to steam dump
valve 1-PV-507B failing full open. The steam dump valve failure was
attributed to a loosened cam in the positioner that resulted in the
camshaft's inability to close the steam dump valve on demand. This
issue was documented in Inspection Report 50-424,425/96-05.
Corrective Action 1 of the LER. which required the repair and return to
service of 1-PV-507B. was completed. Corrective Action 2 recuired the
,
examination of all other steam dump valves, both Unit 1 and lnit 2 for
. similar failures. The examination of all steam dump valves was
i completed, however, due to the results of the examinations and an
~
Enclosure 2
. ~ . _._ _ _-._ _ . ~ .. . _ _ ___ __ >_
o '
.
A
24
)
associated engineering review, the licensee determined additional
corrective actions were necessary. These actions are scheduled for
completion in the fall of 1997.
l This LER is closed.
'
l IV. Plant Sucoort
i
L P1 Conduct of EP Activities (71750) I
1
On October 23, 1996, the licensee conducted a table top exercise at the i
Emergency Operating Facility. Participants in the drill included key
. licensee representatives, state and county representatives from Georgia
1
and South Carolina, and the resident inspectors. The exercise consisted !
of a practice drill scenario with each participant describing their
!
respective actions. It also gave the resident inspectors an opportunity
to describe their actions onsite and NRC actions in both the regional
and headquarters response centers during an actual emergency.
Significant areas covered during the exercise included: actions that
would be taken at different Emergency Action Levels by local and state
, officials; the importance of accurate and timely information to
emergency agencies: important information on the Emergency Notification
l form; and communications that would take place during an event. ,
'
i
The residents concluded, based on observations and participation in the j
emergency drill, that the table top exercise was useful in that the i
exercise helps the licensee develop good communications with the NRC J
i
resident inspectors and state and local agencies.
! R1 Radiological Protection and Chemistry (RP&C) Controls (92904) l
1
R1.1 (Closed) VIO 50-424/96-02-07: Posting Removed For Radiation Area
l Without HPs Authorization
<
! The licensee submitted its reply to the NRC Notice of Violation (NOV) by
letter dated June 24, 1996. The inspector reviewed the licensee's root
i cause determination and Radiological Incident Report (RIR)96-012
associated in this problem, which determined the root cause'to be
inexperienced, untrained personnel who were directed by the HP staff to
l remove a radiological barrier that was located such that it hampered the
- work effort of laborers carrying cement blocks into a work area. The i
! incident was' discussed with the HPs staff on April 14, 1996. )er HP
- Shift Briefing 96-02 via a "Ta11 board" meeting to emphasize t1e
L importance of only HP personnel moving radiation protection barriers and
warning signs to avoid confusion and to maintain personnel exposures As .
Low As Reasonably Achievable (ALARA). On May 3.1996 HP Shift Briefing
96-03 was held via a "Tailboard" meeting to discuss unposted radiation '
areas and associated potential problems. The inspector reviewed the :
, briefing information and personnel attendance sign off sheets of both *
l meetings. The material in the licensee's Badge Training Handbook and
j Enclosure 2 l
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l
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, - , . _ _ . _.
__ .
_ _ _ _ _ _ .
.
. .
,
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25
l Badge Retraining Handbook had been modified in May 1996, to emphasize
l the fact that "only HPs personnel may move, remove, or reposition
radiation signs, ropes, or barriers."
'
,
The inspector concluded that the corrective actions taken by the
licensee were adequate to prevent recurrence. This VIO is closed.
R1.2 (Closed) VIO 50-424. 425/96-02-08: Failure of Procedure 46017-C. !
l Control. Monitoring, and Removal of Materials in Radiation Controlled '
Areas (RCA), to be Prepared Consistent With 10 CFR Part 20.
The licensee submitted its reply to the NOV by letter dated June 24,
1996. Licensee corrective actions included a shift briefing for HP
l personnel involved with the procedure revision process to stress the
, importance of ensuring that applicable regulatory requirements are
- properly interpreted and revision to the referenced procedure to reflect
the proper interpretation of 10 CFR 20.1904. The inspector reviewed the
revision (Revision 18) to the referenced procedure to verify that the i
j issue was adequately addressed. This VIO is closed. l
58 Hiscellaneous Security and Safeguards Issues (71750)
1
S8.1 (Closed) VIO 50-424. 425/96-03-05: Inadequate Vehicle Search l
l
The licensee submitted its reply to the NOV by letter dated July 17. l
1996. Licensee corrective actions included counseling the officer i
involved in the event regarding the performance of assigned tasks as I
well as giving him remedial training regarding vehicle searches. In I
addition, a " Lessons Learned" was issued to security personnel
concerning the performance of vehicle searches. The inspector discussed
the remedial actions with cognizant licensee personnel to verify that I
the issue was adequately addressed. The inspector determined that the J
- remedial actions were adequate. This VIO is closed.
! V. Manaaement Meetinas and Other Areas
l X1 Review of Final Safety Analysis Report
l A recent discovery of a licensee operating its facility in a manner
! contrary to the Updated Final Safety Analysis Report (UFSAR) description
I
highlighted the need for a special focused review that compares plant
l practices, procedures and/or parameters to the UFSAR descriptions.
While performing the inspections discussed in this report, the
inspectors reviewed the applicable portions of the UFSAR that related to
the areas inspected. The inspectors verified that the UFSAR wording was
consistent with the observed plant practices, procedures and/or
parameters.
i
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Enclosure 2
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..
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26
X2 Exit Meeting Summary [
i
The inspectors ) resented the inspection results to members of licensee *
l management at t1e conclusion of the inspection on November 12, 1996. ,
l .The licensee acknowledged the findings presented. -
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary. No proprietary
'
information was identified.
l
i
PARTIAL LIST OF PERSONS CONTACTED
'
Licensee
J. Beasley, Nuclear Plant General Manager
P. Rushton, Plant Support Assistant General Manager
J. Gasser, Plant Operations Assistant General Manager
W. Burmeister, Manager Engineering Support
K. Holmes, Manager Maintenance
I. Kochery, Health Protection Superintendent
D. Carter, SAER Supervisor
M. Sheibani, Nuclear Safety and Compliance Supervisor
C. Tippins Jr. Nuclear Specialist I
INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 57080: Non-Destructive Examination Procedure: Ultrasonic Examination
Procedure: Review / Work Observation / Record Review
IP 61715: Verification Of Containment Integrity l
IP 61725: Surveillance Testing and Calibration Control Program '
IP 61726: Surveillance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71711: Plant Startup from Refueling i
IP 71750: Plant Support Activities !
IP 92700: Onsite Notification Of Written Reports Of Non-routine Events At :
Power Reactor Facilities i
IP 92901: Followup - Operations '
IP 92902: Followup - Maintenance *
IP 92903: Followup - Engineering :
IP 92904: Followup - Plant Support i
IP 93702: Prompt Onsite Response To Events At Operating Power Reactors
!
l !
i Enclosure 2 ,
,
_ - __ _ . _1
_. .._ . . _ _ _ _ . _ . . _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ . . _ _ . _ . . _ . _ _ . . . . _ . -
.
. .
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27 !
ITEMS OPENED, CLOSED, AND DISCUSSED
Ooened
,
l 50-425/96-11-01 VIO Improperly Positioned Clearance Hold Points on i
l
Unit 2 Main Control Room Boards. Two Examples
l (Section 02.1 and Section 02.2)
i ,
!
50-425/96-11-02 VIO Inadequately Performed Surveillance to Closeout
Unit 2 Containment (Section 03.2)
50-424/96-11-03 EEI Unit 1 Safety Injection Pump Train B Loss of
Function (Section M3.1)
Closed
l 50-424. 425/96-02-02 VIO Failure to Properly Implement Wire Lift
Procedure (Section M8.1)
50-424/96-02-07 VIO Posting Removed for Radiation Area Without
Health Physics Authorization (Section R1.1)
!
50-424. 425/96-02-08 VIO Failure of Procedure 46017-C. Control. !
l
'
Monitoring. and Removal of Materials in l
Radiation Controlled Areas, to be Prepared ;
Consistent With 10 CFR Part 20 (Section R1.2) l
l 50-424, 425/96-03-05 VIO Inadequate Vehicle Search (Section S8.1)
'
I-
50-425/96-11-04 NCV Inaccurate Calculation of Estimated Critical
Condition (Section E3.1)
!
50-425/96-001 LER Offsite Power Sources Not Verified in Technical
l- Specification-Prescribed Time Frame (Section !
l 08.2)
50-425/96-006 LER Reactor Trip Due to Main Feedwater Regulating i
Valve Closure (Section 08.3) J
50-425/96-008 LER Turbine / Reactor Trip While Restoring Main Feed
- Pump Turbine to Service (Section 08.4) i
i
50-425/96-007 LER Inadequately Performed Surveillance Results in
Inoperable RHR Pump (Section 08.5)
50-424/96-007 LER Main Steam Isolated When Steam Dump Valve Failed ;
- Open (Section E8.1)
.
.
Enclosure 2 1
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__. -
4
.
i
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28
LIST OF ACRONYMS USED i
ABB - Asea Brown Boveria !
ACCW - Auxiliary Component Cooling Water :
- As low As Reasonably Achievable
'
CB- - Control Bank
, CCP - Centrifugal Charging Pump i
l CFR - Code of Federal Regulations l
! CRDM - Control. Rod Drive Motor
! CSP - Containment Spray Pump
l DC - Deficiency Card !
l DCP - Design Change Package
DRPI - Digital Rod Position Indication
EA - Enforcement Action
ECC - Estimated Critical Conditions
ECCS - Emergency Core Cooling System
ECP - Estimated Critical Position
EEI - Escalated Enforcement Item
EDM - Electric Discharge Machining !
ESF - Engineered Safety Feature
ESFAS - Engineered Safety Features Actuation System
FSAR - Final-Safety Analysis Report
GET - General Employee Training
GPC - Georgia Power Company
g am - Gallons Per Minute
H) - Health Physics
I&C - Instrumentation and Controls
ICRR - Inverse Count rate Ratio Graph ;
ISEG - Independent Safety Engineering Group !
LER - Licensee Event Report
LOCA - Loss of Coolant Accident
LOSP - Loss of Offsite Power
MCR - Main Control Room
MFPTB - Main Feedwater Pump Turbine B l
MFPT - Main Feedwater Pump Turbine
MFRV - Main Feedwater Regulating Valve
MSIV - Main Steam Isolation Valve
MWO - Maintenance Work Order
NCV - Non-Cited Violation
NOUE - Notification of Unusual Event
NOV - Notice of Violation
NPF - Nuclear Power Facility i
NRC - Nuclear Regulatory Commission
NSCW - Nuclear Service Cooling Water
NUREG - Nuclear Regulations .
P/A - Pulse-2-Analog
Enclosure 2
l
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- -
. ;
!.
I
29 !
PASS - Post Accident Sampling System *
PDR - Public Document Room
PE0 - Plant Equipment Operator
PM - Preventive Maintenance
RCA - Radiologically Controlled Area
RHR - Residual Heat Removal System
RIR - Radiological Incident Report
R0 - Reactor Operator
RP&C - Radiological Protection and Chemistry
RPS - Reactor Protection System
SAER - Safety Audit And Engineering Review
SI - Safety Injection
SIP - Safety Injection Pump
TS - Technical Specifications
UFSAR - Updated Final Safety Analysis Report
USS - Unit Shift Supervisor
UT - Ultrasonic Testing
VEGP - Vogtle Electric Generating Plant
VIO - Violation
2RS - Unit 2 Fifth Refueling Outage
l
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Enclosure 2
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_ _ . _ . _ _ _ _ _ _ _ _ . _ _ _. _ .. _ . _ _ _ _ ___ _ .__ _ _ _ . _ _ _ . _ _ . _
_- .
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_
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1
36388 Federal Register / Vol. So, No.126 / Friday, June 30. 1995 / Notices
j fetors in arriving at the a te is not held,b lloonses will normally is a matter of public record, such as an
- nonrity level will be t on the be requested to provide a written adjudiatory dacialan by the
- circumstances of the vi tion. response to an inspection report,if Department of Labor. in addition, with
However,if a licensee refuses to correct issued,as to b liansee's views on the the approval of the Executive Disector
a minor violation within a reasonable apparent violations and their root for Operations, conferences will not be
-
time such that it willfully continues, the causes and a description of planned or open to the public where good cause has
, violation should be categorised at least implemented corrective action. been shown aAer balancingthe beneSt
at a Severity LevelIV. During the predecisional enforcement of the public observation ogninst the
- D. Violations of Jieposting flequirements conference, the licensee, vendor, or potentlalimpact on the egnacy"'s
- other persons will be given an enforcement action in a case.
- j The NRC expects licensees to provide opportunity to provide information As soon as it is deterniined that a
cornplete, accurate, and timely
consistent with the purpose of the conference willbe._opan to
j information and reports. Accordingly, conference, including an explanation to observation, the NRC will
,
unless otherwise categorised in b the
the NRC of the immediate corrective limnaes that the conference be
Supplements,the severity level of a actions (if any) that were taken
,
violation involving the failure to make oPen to public observation as part of the
,
following identincetion of the potential agency's trial program. f%==4=e==* with
j a mquimd report to the NRC will be
based upon the significance of and b violation ornonconformance and the the agency's policy on open seestings,
j
long-term comprehensive actions that " Staff Meetings Open to Public,"
j circumstances surrounding the matter Published September 20,1994 (59 FR
were taken or will be taken to psevent
- that should have been mported recurrence. Licensees, vendors, or other 48340), the NRC latends to announce
- However, the severity level of an
t
persons will be told when a meeting is OPen conferences normally at least to
untimely report, in contrast to no report, a Predecisional enforcement conference, working days in advance of conferences
- may be reduced depending on the A predecisional enformment through (1) notices posted in the Public
- circumstances surrounding the matter. conference is a meeting between the Document Room,(2) a toll-free
l A licensee will not normaDy be citad for NRC and the licensee. Conferences are telephone recording at 800-452-9674,
- a failure to report a condition or event normally held in b regionaloffices
unless the licensee was actually aware
and (3) a toll-free electronic bulletin
j board at 800-452-9678. In addition, the
and are not normally open to puulic
- of the condition or event that it failed observation. However, a trial program is NRC will also issue a press please and
j to report. A licensee will, on tne other
.
hand, normally be cited for a failure to being conducted to open approximately notify appropriate State 11=Iman ofBoers
report a condition or event if the
25 percent of all eligible conferenas for that a predecisional enforcement
! public observation, i.e., every fourth conference has been scheduled and that
- licensee knew of the information to be eligible conference involving one of it is open to public observation.
- reported, but did not moognise that it The public attending open
thru categories of licensees (reactor,
, was miuired to make a sport. hospital, and other rnatorials licensees) conferences under the trial program may
I
V. Pr=daciala==1 Esforcessent will be open to the public. Conferences observe but not participate in the
} Conferences will not normally be open to the public conference. it is noted that the purpose
ont aedon being *
!% Whenever the NRC has learned of the H b en ,Q,C88,,1 nd
{ existence of a potential violation for Public:,ttendance,but rather to
C*" gg y*7ould tle taken against an .
! which escalated enforcement action determine whether providing the public
ii appears to be warranted, or recurring individual, or H b acdon, bugh not
taken a0dnst an indvidal, turns on with opportunities to be informed of
j nonconformance on the part of a NRC activities is compatible with the
vendor,the NRC may provide an whether an individual has committed
3
NRC's ability to exercise its regulatory
i Opportunity for a predecisional %volv s significant personnel - and safety responsibilities. Therefore,.
- enforcement conference with the members of the public willbe allowed
fdlurn where the NRC has requwted
licenses, vendor, or other person before that the individual (s) involved be access to the NRC regional olRces to
j taking enforcement action. The purpme present at the conference; attend open enforcement conferences in
- of the conference is to obtain (3)is based on the findings of an NRC accordana with the Standard
4 information that will assist the NRC in OfBce ofInvestigations report;or Operating Procedures For Providing
i determining the appropriate (4) Involves safeguards information, Security Support For NRC Hearings And
<
enforcement action, such as:(1) A Privacy Act inforrnation, or information Meetings," published November 1,1991
- ,,
common understanding of facts, root which could be considered proprietary; (56 FR 56251).These precedures
i c! causes and missed opportunities
'
in addition, conferences will not provide that visitors may be sub to
- a associated with the apparent violations, to the publicif
- Personnel screening, that sips,
j$ (2) a common understanding of normally
(5)The con be obronce involves medicalposters, etc., not larger than 18" be
.,
l corrective action taken or planned, and misadministrations or overexposures permitted, and that disruptive persons
a (3) a common understanding of the and the conference cannot be conducted may be removed. . < . , ,
- ! significance ofissues and the need for Members of the public =rtanding open
without disclosing the exposed
j:I
4 N
lasting comprehensive corrective action. Individual's name; or conferences will be retnindad that (1)
If tlie NRC concludes thatit has (6)The conference will be conducted the apparent violations di=====d at
i sufHcient information to make an by telephone or the conference will be predecisional enforcement conferences
- informed enforcement decision, a
2
conducted at a relatively small are subject to further review and may be
'
conference will not normally be held licensee's facillt . subject to change prior to any resulting
1 unless the 1t===== requests it. However, Notwi ng meeting any of these enforcement action and (2)the
)l' h
i
"
an opportunity for a conference will criteria, a conference may still be open statements of views or expressions of
}- normally be provided before lesuing an if the conference involves issues related opinion made by NRC employees at -
1 order based on a violation of the rule on to an ongoing adjudicatory proceeding predecisional enforcement conferences,
1 ji
'
Deliberate Misconduct or a civil with one or more intervenors or where or the lack thereof, are not intended to
y to an unlicensed poseen.lf a the evidentiary basis for the conference represent final determinations or beliefs.
- e
I
j' NUREG-1600 8
Enclosure 3
- ii
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Federal Register / Vol. 60, No.126 / Friday, Junt 30, 1995 / Notices 34387
~
Persons attendthg~open conferences will to be under oath. Normally, responses ^ management involvement in licensed
be provided an opportunity to submit under oath willbe required only in activities and a decrease in protection of
connection with Severity Levell 11, or the public health and safety.
9 written comments concerning
program anonymously to the regional
offim.These comments will be ., .
the trial
III violations or orders.
The NRC uses the Notice of Violation 1 Base CivilPenalty
subsequently forwarded to the Director as the usual method for formalizin the The NRC im ses different levels of
of the Office of Enforcement for review existence of a violation. Issuance o a penalties for d erent severity level
l and consideration. Notice of Violation is normally the only violations and different classes of
When needed to protect the public enforcement action taken, except in licensees, vendors, and other persons.
health and safety or common defense cases where the criteriefor luuance of Tables 1A and 1B show the base civil
and security, escalated enforcement civil penalties and orders, as set forth in penalties for various reactor, fuel cycle,
action, such as the issuance of an Sections VI.B and VI.C. respectively, are materials, and vendor programs. (Civil
immediately effective order, will be met. However, spedal circumstances penalties issued to individuals are
taken before the conference. In these regarding the violation findings may determined on a case-by-case basis.) The
cases, a conference may be held after the warrant discmtion being exercised such structure of these tables generally takes
l escalated enfomsment action is taken. that the NRC refrains from issuing a into account the gravity of the violation
"' "
VI. Enforcement Actions C',"do of fo Primary consideration and the
r .) 88ghy i Pay as a secondary
This section describes the in addition, licensees are not ordinarily
enforcement sanctions available to the c nsideration. Generally, operations
cited for violations resulting from
NRC and specifies the conditions under matters not within their control, such as inv lying greater nuclear material
which each may be used. The basic """ # **" 8"' I'"N
equipment failures that were not c nsequences to the p lic and licensee
enforcement sanctions are Notices of avoidable by reasonable licensee quality emPl oyees receive higher civil
Violation, civil penalties, and orders of assurance measures or management
various types. As discussed further in Pena ties. Regarding the secondary
controls. Generally, however, licensees
Section VI.D. related administrative are held responsible for the acts of their factor of ability of various classes of ,
actions such as Notices of emplo ees. Accordingly,this policy Heensees to pay the civil penalties, it is
Nonconformance, Notices of Deviation, shoul not be construed to excuse n t the NRC s intention that the
Confirmatory Action Letters, Letters of economic impact of a civil penalty be so
personnel errors.
Reprimand, and Demands for severe that it puts a licensee out of
business (orders, rather than civil
Information are used to supplement the B. CivilPenalty
enforcement program. In selecting the A civil penalty is a monetary penalty Penalties, are used when the intent is to
enforcement sanctions or administrative that may be imposed for violation of (1) suspend or terminate licensed activities)
actions, the NRC will consider certain specified licensing provisions of or adversely affects a licensee's ability
the Atomic Energy Act or to safely conduct licensed activities.
The deterrent effect of civil penalties is
0 enforcement actions taken by other
Federal or State regulatory bodies
having concurrent jurisdiction, such as
supplementary NRC rules.or orders; (2)
any requirement for which a license best served when the amounts of the
in transportation anatters. Usually, may be revoked; or (3) reporting Penalties take into account a licensee's
whenever a violation of NRC requirements under section 206 of the ability to pay,in determining the
requirements of more than a mbor Energy Reorganization Act. Civil amount of civil penalties for licensees
concern is identified, enforcement penalties are desi ned to deter future for whom the tables do not reflect the
action is taken. The nature and extent of violations both b the involved licensee ability to pay or the gravity of the
the enforcement action is intended to as well as by oth r licensees conducting violation, the NRC will consider as
reflect the seriousness of the violation similar activities and to emphasize the necessary an increase or decrease on a
involved. For the vast majority of need for licensees to identify violations case-by-case basis. Normally, if a
violations, a Notice of Violation or a and take prompt comprehensive licensee can demonstrate financial
Notice of Nonconformance is the normal corrective action. hardship, the NRC will consider
action. Civil penalties are considered for Payments over time, including interest.
Severity Level 111 violations. In addition, rather than reducing the amount of the
A. Notice of Violation civil penalties will normally be assessed civil penalty. However, where a licensee
A Notica of Violation is a written for Severity Level I and 11 violations and claims financial hardship, the licensee
notice setting forth one or more knowing and conscious violations of the will normally be required to address
violations of a legally binding reporting requirements of section 206 of why it has sufficient resources to safely
requirement.The Notice of Violation the Energy Reorganization Act. conduct licensed activities and pay
i normally requires the recipient to Civil penalties are used to encourage license and inspection fees.
l provide a written statement describing prompt identification and prompt and 2.CivilPenalty Assessment
l
(1) the reasons for the violation or,if comprehensive correction of violations,
I contested, the basis for disputing the to emphasize compliance in e manner in en effort to (1) emphasize the
l violation; (2) corrective steps that have that deters future violations, and to importance of adherence to
been taken and the resdts achieved; (3) serve to focus licensees' attention on requirements and (2) reinforce prompt
l corrective steps that wth be taken to violations of significant regulatory self-identification of problems and root
prevent recurrence; and (4) the date concern. causes and prompt and comprehensive
when full compliance will be echieved. Although management involvement, correction of violations, the NRC
The NRC may waive all or portions of direct or indirect,in a violation may reviews each proposed civil penalty on
a written response to the extent relevant lead to an increase in the civil penalty, its own merits and, aftor considering all
information has already been provided the lack of management involvement relevant circumstances, may adjust the
[m to the NRC in writing or documented in may not be used to mitigate a civil
an NRC inspection report.The NRC may penalty. Allowing mitigation in the
base civil penalties shown in Table 1 A
and 1B for Severity ImvelI,II, and El
require responses to Notices of Violation latter case could encourage the lack of violations as described below.
!
Enclosure 3
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