ML20134H160
| ML20134H160 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 01/17/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20134H127 | List: |
| References | |
| 50-424-96-12, 50-425-96-12, NUDOCS 9702110180 | |
| Download: ML20134H160 (30) | |
See also: IR 05000424/1996012
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U. S. NUCLEAR REGULATORY COMMISSION (NRC) l
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REGION II
Docket Nos. 50-424 and 50-425
License Nos. NPF-68 and NPF-81
Report No: 50-424/96-12. 50-425/96-12
Licensee: Georgia Power Company (GPC)
Facility: Vogtle Electric Generating Plant (VEGP) Units 1 & 2
-Location: 7821 River Road
Waynesboro. GA 30830
Dates: November 10 - December 21, 1996
Inspectors: M. Widmann. Senior Resident Inspector (Acting)
K. O'Donohue. Resident Inspector (In Training)
B. Bearden. Reactor Inspector (Sections M8.1 thru M8.3)
R. Carrion. Project Engineer (Section R8.1)
W. Kleinsorge. Reactor Inspector (Sections M1.2. M1.4 thru
M1.7)
Approved by: P. Skinner. Chief
Reactor Projects Branch 2
Division of Reactor Projects
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- 9702110100 970117
4 PDR ADOCK 05000424
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EXECUTIVE SUMMARY
Vogtle Electric Generating Plant Units 1 and 2
NRC Inspection Report 50-424/96-12. 50-425/96-12
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a six-week
period of resident ins)ection: in addition, it includes the results of
announced inspections ]y two reactor inspectors and one regional project
engineer.
Doerations
e In general, the conduct of operations was professional and
safety-conscious (Section 01.1).
e A notification of unusual event was declared on Unit 2 due to a loss of
function of 17 main control annunciator panels. Grounding of an
annunciator light socket caused a blown fuse in a power supply cabinet
that resulted in loss of the control room alarm function. This was a
duplicate event due to similar maintenance work performed on the
annunciator light boxes. (Section 01.2).
e A Unit 1 automatic turbine / reactor trip occurred as a result of a loss
of stator cooling to the turbine generator due to maintenance work on a
pressure switch (Section 01.3).
e A weakness was identified in the implementation of the maintenance
3rogram for the heat trace / freeze protection system. A review of the
lest trace / freeze protection systems were performed with numerous
deficiencies noted. The licensee stated that they were cognizant of most
of the issues and developed a plan to address the status of open
preventive maintenance and maintenance work orders (Section 02.1).
Maintenance l
e Maintenance and surveillance activities were generally completed l
thoroughly and professionally, with satisfactory results (Sections M1.1
and M1.2). ,
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e A non-cited violation was documented concerning missed surveillances on
containment electrical penetration circuit breakers for the personnel
and escape air locks (Section M1.3).
e A violation was identified for inadequate corrective actions to address
improperly secured safety-related motor control center door latches.
The issue was initially documented in Inspection Report (IR)
50-424.47' '96-09 dated September 16. 1996. The inspectors performed a
walkdowr an effort to verify stated corrective actions of IR 96-09
were com, 1ed. (Section M1.6).
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Enclosure 2
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e A review of the Remote Shutdown Panels and associated equipment was
performed. The licensee's program for maintenance and testing for this
equipment was adequate. However, a weakness in the area of housekeeping
inside of the inspected panels was identified (Section M8.1).
Enaineerina
e The inspectors concluded that engineering personnel did an effective job
in determining the underlying root cause for a loss of annunciator
function after the occurrence of two similar events. Engineering
personnel effectively supported operations. maintenance. and
Instrumentation and Control troubleshooting efforts. (Section E7.1).
Plant Sucoort
e A non-cited violation was identified concerning a missed performance of
a technical specification required surveillance for a specific activity
prior to entry into mode 4 and subsequent power ascension activities.
(Section R8.1).
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Enclosure 2
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Report Details
Summary of Plant Status
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Unit 1
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The unit began the period operating at full power, however, on November 27. '
1996, the unit automatically tripped due to a maintenance activity in the main
generator stator cooling / hydrogen seal oil panel. A loss of control power to .
the stator cooling panel actuated a tri) relay giving the turbine / reactor trip !
signal. All rods fully inserted and tie unit was safely shutdown into mode
3. Following-troubleshooting and corrective action criticality was achieved
on November 28. 1996, with nominal full power attained on November 29. The
unit operated at full power the remainder of the inspection period.
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L Unit 2
The unit operated at full power throughout the inspection period. ,
I. Ooerations i
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01 Conduct of Operations
01.1 General Comments (71707) l
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Using Inspection Procedure (IP) 71707. the inspectors conducted frequent :
reviews of ongoing plant operations. Operations activities were ;
generally conducted in a controlled, professional, and safety-conscious '
manner. Minor issues identified were forwarded to operations management l
for resolution. i
01.2 Annunciator Function Lost in Unit 2 Control Room (93702) !
At 8:12 a.m. on November 15. 1996. personnel were authorized to aerform
maintenance on Unit 2 main control room annunciator ALB06-E01. C9MT VENT .
ISO ACTUATION [ Containment Ventilation Isolation Actuation), due to a t
light socket having fallen behind the alarm panel. During the work :
activity, maintenance personnel inadvertently grounded the light socket
to the annunciator i
to numerous panels. panel which caused various alarms and a loss of power ,
At 8:42 a.m. the licensee declared a Notification of Unusual Event
(NOUE) on Unit 2 due a loss of function for most of the safety system
main control annunciator Janels. The NRC. state, and local officials '
were promptly notified. Juring the event, compensating non-alarming ;
indicators were available. Due to the loss of safety related l
annunciator functions the licensee initiated compensatory measures that ;
included additional monitoring of key plant aarameters. The increased
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monitoring activities were~ continued until tie Event was terminated at !
j 11:15 a.m. ;
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On October 25. a similar event occurred as a result of maintenance.
From the October event, the licensee developed and implemented several *
corrective actions including removing the associated annunciator alarm :
cards to de-energize the affected light socket. The licensee at that -!
time, also initiated a recuest for engineering assistance (REA) 4. ) :
review system electrical crawings and investigate other potential l
contributors to the event. As part of their original troubleshooting j
, efforts, the licensee did not determine that a hard ground was present
i in the system. The ground detection system design at Vogtle is an l
ungrounded system. This design allows the system to handle one fault ;
l without losing power and permits the licensee time to troubleshoot <
j ground problems. However, the introduction of a second fault may !
complete a short to ground. resulting in a loss of power to the
annunciators. l
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As a result of troubleshooting efforts stemming from the second event
the licensee determined that a logic card had field contacts wired i
i incorrectly that did not allow the ground detection alarm system to l
recognize a fault. Consecuently, the control room operators were .
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unaware of a system grounc . When maintenance personnel commenced their '
work activity on the annunciator light box, the moment they touched the
control panel, a fuse blew in the power supply cabinet that fed the main
- control annunciator panels. This was the same fuse that was replaced in ;
the October 25 incident. The licensee later determined that a common !
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ground wire existed from one annunciator light box to the next. Even !
though the light socket was de-energized, the light box itself remained
part of the ground detection system. Therefore, with the ground fault
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already present, maintenance inadvertently established a short to ground
that caused the loss of the 17 main control room annunciators panels.
- The licensee concluded after the second event that if-the drawing review
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requested by the REA had been conducted at the time of the initial
event, then the common ground would have been identified and potentially
i avoided the second event. However, the license recognized during their
onsite review that the REA effort would be manpower intensive due to the
complexity of the electrical system and chose to take corrective action ;
on the annunciator panel light socket prior to completion of that
review. '
Upon replacement of the fuse, rewiring of the ground detection system ,
logic card contacts, and resolving the hard ground fault, all ,
annunciator functions were restored. j
At the time of the declaration. Unit 2 reactor power was approximately ;
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100 percent. No transient or challenges to safe operation occurred i
during the time of the NOUE. !
As in the first event, the inspectors concluded that the licensee's I
conservative response was appropriate. The classification of the event
was timely and all required notifications completed. Operations shift
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i personnel reviewed all annunciator response procedures and took
compensatory actions for alarms affected during the event (reference
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section E7.1 for additional licensee corrective actions and an
assessment of engineering root cause determination).
j 01.3 Unit 1 Automatic Turbine / Reactor Trio (93702) !
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At 8:46 a.m. on November 27. 1996, a Unit 1 automatic turbine / reactor l
trip signal was received in the control room as a result of maintenance
! activity in the main generator stator cooling / hydrogen seal oil panel.
The automatic trip signal was received witu the unit at 100 percent
l reactor power. Although main steam line code safety valves did not
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lift. the atmospheric reliefs valves (secondary pressure operated relief
valves) were actuated. Based on a review of the sequence of event !
j report and walkdown of the main control room boards, the inspectors !
concluded that the post-trip plant response was normal. The unit was
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i stabilized in mode 3. with no significant complications identified.
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On November 27. maintenance personnel were authorized to isolate a
hydrogen pressure switch inside the stator cooling /nydrogen seal oil
panel when the technician inadvertently moved a metal identification tag -
4 and touched an exposed terminal strip on the stator cooling system that )
i shorted out the control panel 120 VAC power. As a result, a high
l temperature relay logic was actuated (failed high on loss of )ower)
- which led to the loss of stator cooling and thereby causing tle )
- turbine / reactor trip signal.
Shortly after the occurrence of the event the inspectors responded to
the control room and observed plant conditions. The inspectors observed
a portion of-the post-trip maintenance activities including replacement
of the stator cooling 120 VAC power fuse and removal of all metal tags
inside the control panel. In addition, the inspectors witnessed a
portion of licensee management's investigation into the event and
concluded that this activity was appropriately performed. The licensee
determined that the trip occurred as a result of the metal
identification tag coming in contact with an exposed terminal strip.
The contact was a direct result of the technician's movement of the tag
while closing the hydrogen system isolation valve. A review of the
circumstances revealed that the tag was inconspicuously placed in front
of the terminal strip. The inspectors' discussions with the technician
indicated that he was unaware of the terminal strip behind the tag.
Following troubleshooting efforts the reactor was restarted.
Criticality was achieved at 1:27 a.m. on November 28. with nominal full
power achieved on November 29. The licensee issued Licensee Event
Report (LER) 50-424/96-12. Main Generator Turbine / Reactor Trip While
Performing Maintenance In The Stator Cooling / Hydrogen Control Panel.
Enclosure 2
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The inspectors' noted that the licensee management's decision to defer I
the restart of the unit until after. troubleshooting and maintenance '
efforts were completed on the backup power supply that feeds the Unit 1 t
annunciator panels was conservative. A restart could have occurred late
afternoon the day of the trip, however, management made a conscious I
choice to defer the startup until this other problem was addressed.
02 Operational Status of Facilities and Equipment j
02.1 Heat-Tracino and Freeze Protection Panel Status
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a. Insoection Scooe-(71714)
The inspectors walked down the heat tracing and freeze protection system
to determine the effectiveness of the licensee's program to protect )
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against cold weather conditions. This review included examination of j
the Updated Final Safety Analysis Report (UFSAR) system description: the '
licensee's design basis document; the system's physical condition:
preventive maintenance (PM) checklists SCL01749 Freeze Protection:.and
SCL00424. Heat Tracing: outstanding Maintenance Work Orders (MWO)s and
corrective work orders: and Procedure 13901-1/2, Heat Tracing System.
The inspectors' also interviewed the system engineer and maintenance
manager as to the status of the system work. I
b. Observations and Findinas
On December 12 and 13, 1996, the inspectors performed a walk down of the
Unit 1 and 2 heat tracing and freeze protection panels. Based on this
effort, the inspectors identified that the heat trace and freeze
)rotection system had not been maintained in a condition whereby it can
3e relied upon to perform its intended function. However the
inspectors recognized that the system does not provide a safe shutdown
function and is not classified as safety-related.
On December 12 the inspectors performed the walkdown with the system.
engineer. Of the panels inspected, more than half were not working
properly. Numerous maintenance work orders were written, but additional
deficient conditions were identified by the inspectors. Deficiencies
varied from central alarms being illuminated: ground faults being
evident: undertemperature, overtemperture, and undervoltage alarms
visible: and freeze protection systems automatically being energized
when weather conditions did not warrant it. Inside three freeze
protection panels. located in the fire pump house, the inspectors
identified evidence of rodent intrusion. Although there was an j
intrusion of rodents into the panels, there was no obvious damage to i
cables or circuit connections. The system engineer was aware of some of !
the problems listed above, but captured the additional deficiencies
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identified during the walkdown.
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t- The inspectors' review of the PMs on the system indicated that four of l
the fifteen freeze protection panels had not had a routine PM performed
- in a number of years. The last time the circulating water heat trace '
3 panel PM was performed was in November 1993. The Nuclear Service ,
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Cooling Water (NSCW) A and B train freeze protection panel PMs were last
! performed December 1994, and April 1995, respectively. The high voltage ;
switchyard heat trace PM was last performed in August 1995. The i
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maintenance manager stated that a plan had been developed prior to this
- review that would address the known deficient conditions, in addition to .
- subsequent issues identified. The maintenance manager also indicated !
- that the past policy of approving PM due date extensions, was not ;
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occurring as of November 1996. -As of this review, there were 34 open :
maintenance and corrective work orders against the heat trace / freeze i
- protection systems with the oldest one written in 1992, two written in j
! 1993, and 3 written in 1994. Ten MW0s were written against the system !
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in 1995 that also remain open. ;
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The licensee presented their basis as to why portions of the heat trace / I
freeze protection systems were out of service and did not have the !
- scheduled PMs performed. REA 94-VAA628. Review of Heat Tracing Panels. l
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dated September 1. 1995, was initiated to eliminate heat tracing on '
)iping larger than four inches. The licensee' developed Design Change i
l Jackage (DCP) 95-VAN 0067. Elimination of Heat Tracing / Freeze Protection -
- & Setpoint Lowering. to implement the recommendations of the REA. Since l
j the due dates for the portion of systems affected by this REA were i
j extended, maintenance personnel postponed the work. However, the !
licensee presented a cancellation notice dated December 12, 1996,
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indicating that the DCP 95-VAN 0067 would not be implemented. The ;
! licensee also presented a revised PM schedule that incorporated all heat ;
trace / freeze protection panels including a scheduled commitment date of
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December 29, 1996 to perform outstanding PMs. ;
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- c. Conclusions
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i The inspectors concluded that although portions of the heat trace / freeze
3 protection systems are not in a condition to perform their function, the
licensee has developed an adequate plan to address the issues. The
i cancellation of the DCP to eliminate heat tracing has removed the
- affected portions of the system from a state of non-repair and has !
prompted the licensee to take action on open items. As a result, the i
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4: inspectors concluded that system problems should be adequately addressed
l if the licensee follows their current maintenance plan.
- 02.2 Safety-Related Walkdowns i
i. a. Insoection Scooe (71707)
} The inspectors walked down the following engineered safety feature (ESF)
l systems as part of the routine inspection effort to verify availability
and overall condition of the safety-related systems:
Enclosure 2
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Unit 1 Safety Injection System ;
Unit 2 Fuel Handling Building Post-Accident Exhaust System F
The inspectors also performed a review of UFSAR commitments and !
technical specifications (TS) requirements for the above listed systems.
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b. Observations and Findinas
The ins)ectors verified proper system configurations both electrically
and meclanically for the above ESF systems through accessible portions ,
in the plant, walkdowns of main control room boards, and reviews of !
system drawings. The inspectors also observed overall material !
condition of system components during the walk downs. Any minor issues l
identified were forwarded to the licensee for resolution.
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c. Conclusions
The inspectors concluded that the systems reviewed were available to ,
perform their intended designed function: systems were properly aligned. .
and UFSAR commitments and TS requirements were met. No items or ,
discrepancies were noted during these inspections.
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03 Operations Procedures and Documentation (71707) l
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. 03.1 During the inspection period, the inspectors walked down the following i
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l 19600306 accumulator 1. 2. 3. and 4 isolation per unit i
operating procedure 12006-1
l 19600666 centrifugal charging pump (CCP) A auxiliary lube oil
i pump clearance to troubleshoot pump cycling while CCP
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running :
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The inspectors did not identify any problems or concerns during these !
walkdowns. l
07 Quality Assurance in Operations
07.1 Evaluation of Licensee Self-Assessment Caoability (40500)
During this inspection period the inspector attended two Plant Review
Board (PRB) meetings. The PRB meeting of December 11 was primarily
concerned with a review of the Technical Review Manual for
implementation of the improved technical specifications scheduled to
! commence January 22. 1997. Other subject matters discussed were the
review and ap3roval of deficiency card (DC) dispositions and procedure
revisions. 11e second PRB meeting on December 18 reviewed responses to
, earlier documented NRC violations. The inspectors recognized the
i. licensee's effort in ensuring that the corrective actions developed
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Enclosure 2
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addressed the issues cited. Meetings attended were conducted critically- l
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i attendees were knowledgeable of the materials discussed. PRB attendees l
met TS requirements.
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j No issues were identified as a result of this review.
II. Maintenance
! M1 Conduct of Maintenance l
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M1.1 Maintenance Work Order Observations
a. InsDection Scooe (62707) (92902) ,
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,! The inspectors observed portions of maintenance activities involving the !
- following work orders.
- 19502616 Diesel Generator (DG) 1A day tank low level alarm
L ALB035-D07 troubleshoot i
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- 19601067 Replace valve 1-1405-U4-011 l
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19601177 NSCW pump 5 discharge isolation motor operated valve l
per DCP 95-V1N0035-1
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j - 19601931 Calibration 1-T0126; verify.UQ1118 below 3562.9 MWt
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j 19601961 DG 1B jacket water leak in coupling under left bank
turbo charge
19602213 Match marking motor coolers for A train pumps
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19602612 Computer point does not show correct indication on
reactor coolant drain tank vent valve 1-HV-7150
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19602831 Repair 1-HV-4486 control loop valve miniflow through
steam jet air ejector to condenser: change out~
. tracking driver card and light indication fuses
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29602921 Troubleshoot and repair train "B" hydrogen recombiner
29602951 Control room emergency filtration system A train
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breaker change out
29603039 Safety injection pump A train motor cooler low flow
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- condition;' reverse plenum orientations
29603080 DG train 2A starting air: uncontrolled bleed down l
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i b. Observations and Findinas !
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The observed maintenance activities were performed satisfactorily except l
as noted below:
During the inspection-period two events occurred as a result of :
maintenance activities. The declaration of a Notification of Unusual i
Event (Section 01.2) when work on a light socket resulted in the loss of '
power to Unit 2 main control room annunciator panels, and the Unit 1
automatic trip due to loss of stator cooling (Section 01.3). These -
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events were a direct result of maintenance personnel errors.
In both cases, the precursors to the events were difficult to identify.
However, the licensee took appropriate corrective actions for both
events in an effort to preclude repetition.
c. Conclusions
The inspectors concluded that although maintenance personnel caused the
two above events, the work activities did not reflect poor control of
maintenance. The events were a result of unforeseeable circumstances.
No trends or indicators of adverse maintenance performance were
identi fied.
M1.2 Surveillance Observation
a. Insoection Scoce (61726)
The inspectors observed the performance or reviewed the following
surveillances and plant procedures:
14546-2 Turbine driven auxiliary feedwater (TDAFW) pump operability
test
14810-2 TDAFW pum) 1 check valve IST and manual initiating i
handswitc1 trip actuation device operability test j
14970-2 Semiannual, train "B" hydrogen recombiner !
(2-1513-H7-002-000) functional test ]
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14980-1 DG 1A' operability test !
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24568-2 Reactor coolant pump 1 train A. reactor trip underfrequency )
(281-A) and undervoltage (227-A) relays trip actuating i
device operational test and channel calibration
83308-2 Monthly NSCW flow test of 2-1203-P4-002-M01 component ,
cooling water (CCW) train B motor cooler per section 8.2. i
data sheet 1 of 83308-C l
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83308-2 Monthly NSCW flow test of 2-1203-P4-004-M01 CCW (train B) l
motor cooler per section 8.2. data sheet 1 of 83308-C
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83308-2 Monthly NSCW flow test of 2-1203-P4-006-M01 CCW (train B) I
q motor cooler per section 8.2. data sheet 1 of 83308-C
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b. Observations and Findinas
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! The observed surveillance activities were performed satisfactorily l
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except as noted below: 1
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i Review of GPC Procedure 83308-C. Revision 10. Flow Testing of Safety l
'Related NSCW System Coolers, does not address the following when using -
i the polysonics instrument: the maximum variation that is considered -
- stable: what value to report when a range of flow values is encountered.
- ' or how to evaluate ranges that bridge the required flow range. The i
- licensee indicated that they currently are in the ;
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this procedure and will make appropriate changes. process of revising !
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Following the observation of flow testing of the upstream flow orifice i
.. for Unit 2 B Train Component. Cooling Water (CCW) Motor Nos. 2-1203-P4- !
l 002-M01, 2-1203-P4-004-M01, and 2-1203-P4-006-M01, the inspectors noted ;
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that the prerequisite steps verifying: instrument calibration: Nuclear :
Service Cooling Water (NSCW) normal alignment; and authorization to !
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install Maintenance and Test Equipment (M&TE): were signed off after the :
completion of the testing. The licensee's procedural compliance- l
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guidance is to: " Follow steps in sequence...". which is documented in i
- Procedure 00054-C. Revision 9. Rules for Performing Procedures,
i paragraph 1.1. The inspectors noted that the technicians had in fact l
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completed the prerequisite ste)s prior to conducting the test but )
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- completed the sign off for eac1 prerequisite step after completing the '
test. In addition the inspectors noted that the completed data sheets
did not contain required dates for each of the initialed sign offs. The
! preceding indicates a lack of attention to detail on the part of the
Instrumentation and Controls (I&C) technician performing the tests.
This was discussed with licensee management.
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l c. Conclusions
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The observed surveillance activities were performed satisfactorily.
I Some discrepancies were noted in documentation and procedural
compliance.
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M1.3 Missed TS Surveillance on Containment Penetrations
a. Scope of Insoection (92903)
The inspectors reviewed a licensee identified issue concerning the
design of Unit 1 and 2 containment electrical penetrations for the
personnel and escape air locks. The review included system drawings.
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surveillance requirements, and Licensee Event Report (LER) 50-424/96-11,
Inadequate Containment Electrical Penetration and Missed Surveillance.
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b. Observations and Findinas
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On October 23. 1996, during a review of the airlock lighting
requirements, the licensee identified that several personnel and escape
airlocks essential and normal lighting circuits for both Unit 1 and 2 ;
had not been tested per TS requirements. In addition, the circuits did ;
not meet design requirements to provide dual overcurrent protection. !
The licensee subsequently install two fuses in series to the affected
circuits to address potential containment integrity issues and comply !
with design requirements. The airlock lighting circuits were returned ,
to service on November 14, 1996.
The licensee determined based on a engineering review that Updated Final !
Safety Analysis Report (UFSAR) Table 16.3-5. Ccntainment Penetration
Conductor Overcurrent Protection Devices and Isolation Devices for Class ;
IE to Non-Class 1E Feeds, did not list all reqeired lighting circuit l
breakers for surveillance testing. Since the original design was ,
instalied, the surveillance testing for the penet. ration circuit breakers ;
had not been performed. The licensee determined that the cause of the
event was a failure to adequately document all airlock lighting circuits
as containment electrical penetration circuits requiring surveillance :
testing. In addition, the licensee determined that engineering failed
to properly design and install circuits with dual overcurrent protection i
during the original )lant construction. The subsequent installation of l
the fuses in the lig1 ting circuit addressed the dual overcurrent !
3rotection issues and alleviated the need to incorporate circuit !
3reakers into the existing surveillance testing since fuses are not j
required to be tested. l
The licensee issued LER 50-424/96-011. on November 22, 1996. Licensee
actions included a commitment to revise the UFSAR Table 16.3-5 to
reflect fuses being used as primary and backup circuit protection and to
review other airlock containment penetration power circuits for similar
design issues. The inspectors verified the licensee's corrective
actions as part of this LER. Actions were taken as stated.
c. Conclusions
The inspectors concluded that the licensee failed to perform required
testing of circuit breakers per TS requirement 4.8.4.1. Electrical
Equipment Protection Devices, at least once per 18 months since initial
startup. However consistent with Section VII of the NRC Enforcement
l Policy this was identified as Non-Cited Violation (NCV) 50-424,
425/96-12-01. Failure to Perform Containment Penetration Circuit Breaker
l Surveillances.
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The inspectors noted that the licensee's electrical engineer did a good
job during the systems design review in identifying circuits not tested
as part of the required surveillance program. This was a good example
of attention to detail. ,
M1.4 Foreion Material Exclusion (FME)
a. Insoection Scooe (62707)
Generic Letter 89-13. Service Water System Problems Affecting Safety-
Related Equipment, was first implemented for the 1990. Unit 2 fall
outage. Heat exchangers and motor / lube oil coolers were tested or
inspected during refueling outages for any adverse fouling, corrosion,
structural damage, and debris. A deficiency card (DC) was written in
September 1994 due to elevated lube oil temperatures for a Unit 2
Centrifugal Charging Pump (CCP) train B lube oil cooler. The
investigation indicated that the flow orifice was blocked by a small
particle of concrete with a piece of aggregate attached. On December
27, 1994, a DC was written to document a piece of aluminum lagging
material (approximately 1 ftz) that had fallen into the Unit 1 NSCW
tower basin. In January 1995, on Unit 2. two other instances occurred
that indicated debris was possibly blocking flow orifices in some of the
motor coolers. During the fourth Unit 2 refueling outage in March 1995,
considerably more debris was discovered during scheduled inspections of
the containment coolers. On August 18. 1995, during the performance of
o)erator rounds, an operator noted that the temperature was 4 F higher
tlan normal on the Unit 1 Train B CCP, On August 26, 1995, maintenance
and engineering personnel measured a low flow condition through the CCP
lube oil cooler. NRC Inspection Report (IR) 50-424.425/95-21. dated
October 13, 1995, identified this issue as an Unresolved Item. NRC IR
50-424.425/95-27 dated December 1. 1995, closed the Unresolved Item for
NSCW debris and opened a Severity Level IV violation. This issue is
further discussed in NRC irs 50-424.425/96-02: 50-424.425/96-09: 50-424,
425/96-10: and 50-424.425/96-11.
To evaluate the FME program at Vogtle in general and the debris in the
NSCW system in particular, the inspectors reviewed procedures, observed
flow testing in progress, interviewed licensee personnel and examined
selected records
b. Observations and Findinas
The licensee established a NSCW debris data base compiled from records
starting September 1992. This data base is composed of 63 records
representing 63 occurrences when debris was identified in the NSCW
l system. The items found in the system include but are not limited to:
l- concrete, sand and aggregate: assorted metal items including expanded
metal, various fasteners, assorted wire, a tapered drift pin: plastic,
including pieces of a beeper, a pipe cap, ball point pen silicon plug.
,
and tie wraps: an AA battery: pieces of Colmonoy wear surfaces of the
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Enclosure 2
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! NSCW pumps: and other assorted trash. The licensee attributes the
I
debris intrusion into the NSCW system to the following: construction
debris not removed by pre-operational flushes: spalling concrete debris ,
from NSCW cooling tower and basin: debris that was improperly or
inadvertently washed, swept, blown or dropped into unprotected NSCW
cooling tower basins and pump wells; and degrading Colmonoy coating on
sleeves and wear ring surfaces of the NSCW pumps.
To address the existing debris and new debris ingress into the NSCW
system, the licensee has taken the following actions: steel plates have
been installed over the Unit 1 and 2 pump well openings to prevent
l foreign material from entering the basins and pump shaft wells: kick
i plates were installed and screens were installed / repaired on the basins
in both units pump rooms; a diving service was contracted to inspect a
,
representative sam)le of the Unit 1 and 2 tower basin walls to inspect i
the integrity of tie suction screens, and inspect and vacuum debris:
!
flow testing on all Unit 1 and 2 safety-related NSCW small diameter
, motor / lube oil coolers is ongoing and is expected to continue on a
'
monthly basis: the scope was expanded for Generic Letter 89-13 testing
and inspection during the Unit 1 sixth refueling outage; the removal of ,
orifices and flushing of lines and/or visual inspection of lines serving l
l critical components: the Colmonoy coating on NSCW pump sleeves and wear l
- rings have been repaired on the Unit 1 Jumps and is expected to be
completed by September 1,1997 for the Jnit 2 pumps: and a design change i
has been proposed but not yet approved to provide strainers for all Unit i
1 and 2 safety-related NSCW small diameter motor / lube oil coolers. !
c. Conclusions )
l
The licensee's arogram continues to identify and remove debris from the i
NSCW system. T1e licensee's plant modifications and the FME program
l should prevent new ingress of debris into the NSCW system (with the
exception of spalling concrete from the NSCW cooling towers and basins).
At present, the monthly flow testing is identifying debris already in
the NSCW system, when it migrates to the small diameter flow orifices.
Appro)riately sized strainers have the potential of reducing the need
for t1e current level of flow testing.
M1.5 Reolacement of Valve 1-1405-U4-011
a. Insoection Scooe (62703) i
( The inspectors observed work and work activities associated with the
replacement of valve 1-1405-U4-011. These activities included
implementation of a freeze seal, removal of valve 1-1405-U4-011. pipe ,
fitting, welding, and termination of the freeze seal. i
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b. Observations and Findinas
As reported in NRC.IR 50-424.425/96-09, several examples were noted l;
where procedural personnel safety precautions were not followed during
the a> plication of a freeze seal associated with the repair to valve 2- i
1901- J4-144. In addition, a number of unsu) ported divergences were ;
noted, between NRC Technical Guidance and t1e implementation of the i
freeze seals. The licensee has revised the freeze seal procedure to !
appropriately. address the previously identified unsupported divergences ;
from NRC Technical Guidance for freeze seals. The freeze seal was :
implemented in compliance with all personnel safety and technical ;
requirements of the freeze seal procedure consistent with NRC Guidance. :
Welding was accomplished by a properly qualified welder using properly
certified welding filler material in accordance with a properly
qualified welding procedure specification.
.
c. Conclusien.ji
!
Maintenance activities were completed thoroughly and professionally, in !
accordance with procedures. ,
til.6 Motor Control Center (MCC) Door Latches
a. Insoection Scooe (62707)
i
As identified in NRC IR 50-424.425/96-09, a significant number of MCC
panel door closure " dogs" or latches were not secured. The licensee >
stated that a REA 96-VAA639 had been opened to address this issue.
Completed.REA 96-VAA639. dated August 7. 1996, indicated that no data :
had been found to support the position that impact loads from unlatched
or partially latched doors would not adversely affect devices that would i
chatter. Further, the seismic report indicated that the MCCs were :
tested with all latches secured, therefore the cabinets, with some l'
latches not fully secure are not within the envelope of the seismic
qualification. !
>
REA 96-VAA639 indicated that duct tape was an acceptable temporary l
closure mechanism for broken latches as it was used at the testing i
facility during test to secure wiring, flexible conduits, air lines, and !
'
other components.
i
After determining that unsecured MCC panel doors were outside of-the i
envelope of the seismic qualification for MCCs. the licensee's .
corrective action, concerning the findings of. REA 96-VAA639. consisted ;
of a walkdown inspection of all MCCs to assure that all doors on all
MCCs were properly secured. The licensee stated that this walkdown
inspection was performed but undocumented. j
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b. Observations and Findinos
To determine the efficacy of the licensee's corrective actions related !
to MCC latches, the inspectors on December 5. 1996, started to conduct a
walkdown inspection of a re)resentative number of MCCs. examining the
security of the latches. T1e inspectors, accompanied by a licensee
!
representative, examined safety related 1E 480 volt MCCs 2-1805-S3-2BBA i
and 2-1805-S3-2ABA. The inspectors identified seven latches not secured >
on MCC 2-1805-S3-2ABA and 34 latches not secured on MCC 2-1805-S3-2BBA. .
One unsecured latch was identified with a work order tag indicating that
I
the latch was broken. but the door was not secured with duct tape as
recommended by REA 96-VAA639. Both latches on a number of doors were
,
not secured. In view of the number of unsecured latches found on the
l first two MCCs examined, the inspectors discontinued their inspection
and the licensee documented the discrepancies in DC 2-96-310.
t
c. Conclusions
l
The licensee's corrective action to assure that MCC Janel doors were
properly secured, was ineffective. as evidenced by .le unsecured latches
identified by the inspectors on MCC Nos. 2-1805-S3-2BBA and
2-1805-S3-2ABA after the completion of the licensee's walkdown. Failure
to establish effective measures to assure that nonconformances are 1
3romptly identified and corrected is a violation of Title Ten Code of '
ederal Regulations Part 50. Appendix B. Criterion XVI. This is
identified as Violation (VIO) 50-424.425/96-12-02. Failure To Take
Effective Corrective Actions To Assure MCC Door Latches Are Properly
Secured. i
1
M1.7 Maintenance Audits j
a. Insoection Scooe (62707) l
The inspectors reviewed 1996 audits in the maintenance area. The scope
of these audits included: NSCW pump refurbishment procedure control,
maintenance program. Performance Team activities, and maintenance.
b. Observations and Findinas
Audit findings included weaknesses related to: safety related work 3
performed by a contractor not on the safety related approved vendors l
list, bolts over torqued. lockwire not installed, receipt ins)ection not
performed. American Society of Mechanical Engineering (ASME) 3 oiler and
Pressure Vessel Code Section XI repair not implemented, improperly
written purchase order, color coding of grinding wheels for specific
material application, awareness of hold points, training and
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s. qualification of maintenance planners, excessive overtime
- authorizations, procedure revision process, lifting rigging color
coding, improper / lack of restraint of materials and equipment to prevent
i
damage to operable safety related equipment. Appropriate corrective
, actions were taken or planned.
1
- c. Conclusions
!
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The area of maintenance was subjected to independent audits, with
- appropriate action taken for identified weaknesses.
s <
M7 Quality Assurance in Maintenance Activities
j M7.1 Hydroaen Recombiner Failed Surveillance
'
a. Insoection Scooe (61726) (40500)
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The inspectors reviewed the licensee's investigation and troubleshooting l
efforts regarding a failed surveillance on the Unit 2 train B hydrogen '
4 recombiner The inspectors reviewed the MWO associated with the ,
,
corrective work order, the DC generated, and Procedure 14970-2, Hydrogen l
l Recombiner Functional Test. The inspectors also discussed the root
4
cause determination effort with the system maintenance team leader and
a maintenance manager. 1
i
b, Observations and Findinas
)
j j
i On November 28. 1996, the Unit 2 hydrogen recombiner train B failed to
i successfully pass the surveillance criteria of procedure 14970-2.
-
Maintenance determined that the failure was a result of a transducer
! filter that prevented the recombiner from reaching the required kilowatt
- output specified in the surveillance. Maintenance was able to identify
- and replace the failed component through effective root cause and
troubleshooting technicues. Maintenance activities observed were
properly documented anc well controlled.
.
After completion of corrective maintenance activities operations
'
performed the surveillance again with satisfactory results.
.
c. Conclusions
,
The inspectors concluded that, for this example of surveillance / ,
maintenance root cause and troubleshooting effort, the licensee
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o effectively identified and resolved issues affecting plant operations.
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M8 Hiscellaneous Maintenance Issues (62700) (61726) (92902)
M8.1 Remote Shutdown Panel
a. Insoection Scooe (62700) (61726)
l
The inspectors reviewed the licensee's maintenance and testing program
for the Remote Shutdown Panels (RSPs) to evaluate the adequacy of the
licensee's program for maintenance and routine testing of this
equipment. Additionally, the inspectors reviewed post-modification
testing following implementation of design changes to components
controlled from the RSPs to determine adequacy of testing.
b. Observation and Findinas
Instrumentation and controls to achieve and maintain hot / cold shutdown
as required by 10 CFR 50 Ap)endix R are provided by separate RSPs for
each unit and supplemented )y manual actions at local component control
stations. The inspectors determined that the RSPs for both units were
installed and functionally tested prior to initial plant o)eration.
Systems and components required to satisfy the alternate slutdown 1
capability are described in the licensee's UFSAR Section 7.4.3. Safe
Shutdown From Outside the Control Room. TS recuirements are described
in Sections 3.3.3.5.1, 3.3.3.5.2. 4.3.3.5.1 anc 4.3.3.5.2.
The inspectors reviewed a listing of plant modifications issued by the i
licensee for systems controlled from the RSPs. Five completed
'
modifications which could have potentially affected operability of RSP
instrumentation or the ability to control components from the RSPs were ,
selected for review. DCP records for those completed modifications were i
reviewed by the inspectors to determine actual scope of modification
activities and adequacy of required post modification testing. The
inspectors determined that for four of the five selected DCPs. post
modification testing of RSP controls was not required since the scope of
modification activities could not have affected the ability to control
components from the RSPs. The remaining DCP appeared to potentially l
affect RSP controls. This modification was DCP 88-V1N0076, which .
deleted the automatic closure interlock associated with Residual Heat !
Removal (RHR) Hot Leg Isolation Valves 1HV-8701A 1HV-87018, 1HV-8702A.
and 1HV-8702B. The inspectors verified that post modification testing
for this DCP had included functional testing of those RHR valves from
the Unit 1 RSPs. No problems were identified during this review.
The inspectors reviewed GPC Procedures, 14445-1. Rev. 4. Remote Shutdown
Monitoring Instrumentation Channel Check. Unit 1. and 14445-2. Rev. 2.
Remote Shutdown Monitoring Instrumentation Channel Check, Unit 2, which
are performed by the licensee on a monthly basis. The inspectors also
reviewed GPC Procedures. 14710-1 Rev.18. Remote Shutdown Panel
Transfer Switch and Control Circuit 18 Month Surveillance Test. Unit 1.
and 14710-2 Rev. 17. Remote Shutdown Panel Transfer Switch and Control
Enclosure 2
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-Circuit 18 Month Surveillance Test. Unit 2. which are used by the
licensee to periodically verify operability of the transfer switches and
functional controls located on the RSPs and at local control stations.
These two test procedures are performed every refueling outage. The
inspectors reviewed each of these surveillance procedures and verified
that all instrumentation and controls surveillance requirements from
TS 4.3.3.5.1 and 4.3.3.5.2 were satisfied. The inspectors also reviewed
the data package associated with the most recent performance of each
procedure. Additionally. the inspectors verified that instrumentation
located on the RSP was included in the licensee's instrumentation
calibration program. During this review the inspectors determined that
all necessary instrumentation located on the RSP or locally is routinely
checked and all required functional controls are adequately tested.
During this review, the inspectors noted that the licensee had
previously identified various control switches located on the.RSPs or
locally that had not been included under the scope of GPC Procedures
14710-1 and 14710-2. The inspectors reviewed DC 1-95-129 which
documented the licensee's disposition of this 3roblem. DC 1-95-129 '
'
included a list of s)ecific control switches w11ch should have been
routinely tested. T1e licensee evaluated this problem as not affecting
the operability of required safe shutdown equipment. This determination
was based on the fact that none of the listed control switches were ,
associated with equipment required by TS 3.3.3.5.2. The inspectors
noted that the licensee subsequently revised both procedures to require
functional testing of those control switches as the result of this -
issue. The inspectors review of the licensee's resolution of this issue
identified no concerns.
The inspectors performed a walkdown on the Unit 1 Train A and Train B
RSPs. Unit 1 TDAFW Control Panel. Unit 2 Train A and Train B RSPs, along
with selected local controls for the diesel generators and other
components located on the safety related electrical switchgear. The
RSPs are located in separate locked rooms with access restricted. No
loose wires, damaged components, or evidence of corrosion were observed
' during this walkdown. Material condition inside and outside of the
panels was acceptable. However, several housekeeping deficiencies were
identified during the walkdown. A section of loose metal deck ) late,
sound powered phone headset and cable, a used 100 VAC light bul) with
bulb cage, and several spare 110 VAC light bulbs were noted inside the
RSPs. The section of deck plate was approximately 8 inches by 15 inches
in size and had all four bolts missing. The inspectors identified these ;
deficiencies to licensee management and the deficiencies were !
immediately corrected. The licensee also requested that corporate !
engineering evaluate any seismic effects of the loose material on l
operability of the RSPs. The licensee's evaluation was documented under l
REA VE-3100. The inspectors reviewed the licensee's evaluation and i
determined that the operability of the RSPs was not effected by the ;
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Enclosure 2 ;
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presence of the loose material. However, better housekeeping practices I
following maintenance could have prevented these deficiencies. The
presence of this material within infrequently inspected panels ;
represents a weakness. j
c. Conclusions
The inspectors concluded that the licensee has maintained the alternate :
safe shutdown equipment in a satisfactory manner, and that the
licensee's program for routine testing of RSP instrumentation and
controls is adequate. The inspectors did not identify any examples of
inadequate post modification testing following licensee modification
activities that could have had a negative impact on any control
functions of equipment operated from the RSP. A weakness was identified i
associated with poor housekeeping practices following maintenance within l
infrequently inspected panels.
M8.2 Balance of Plant '(BOP) Eauioment Reliability I
a. Insoection Scone (62700)
l
The inspectors reviewed a listing of unplanned capability loss data for !
both units along with other plant operating history provided by the
licensee to identify potential equipment reliability problems that might
exist. This listing was evaluated to identify unplanned )ower ;
reductions and trips associated with equipment failures tlat might be
associated with maintenance activities for Balance of Plant (BOP)
equipment that was not being conducted in a manner that results in the
reliable and safe operation of the plant. The purpose for this review
was to identify equipment that has a history of recurring problems or
whose failure resulted in a safety system actuation or plant shutdown or
resulted in reduced system capability and determine if the problem might
have been caused by inadequate maintenance.
i
b. Observation and Findinas
The inspectors reviewed plant operating history for 1994. 1995. and 1996
and noted that the licensee had experienced some plant trias and
unplanned )ower reductions due to degraded performance of 30P equi) ment.
However.. t1e ins)ectors did not identify any trends associated wit 1
these failures w11ch might indicate that tha equipment reliability
problems resulted from inadequate maintena ce.
c. Conclusions
The licensee has experienced some trips or unplanned power reductions
due to degraded performance of B0P equipment. The ins)ectors did not
identify any adverse trends that might indicate that t1e equipment
reliability problems resulted from inadequate maintenance.
Enclosure 2
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M8.3 Reactor Trio Breakers
a. Insoection Scooe (62700) {
f
The inspectors reviewed the status of licensee action to address NRC l
Information Notice (IN) 96-44. IN 96-44 was issued to alert licensees !
to the possible failure of reactor trip breakers (RTBs) to properly !
function because of cracking or breakage of the secondary disconnecting i
contact assemblies. During RTB testing at another nuclear facility. a !
licensee found that one of the bypass breakers failed to open l
electrically when the local shunt trip push button was depressed. !'
During subsequent inspection of the breaker, a small piece of the
assembly was found lodged in the secondary disconnecting contact
assembly which may have prevented reliable electrical continuity for
the local shunt trip push button circuitry for the manual trip function. j
i
The disconnect assemblies provide circuit connections between the i
control and monitoring devices on the breaker and external control !
circuits. The housing of the electrical contacts in the disconnect !
assemblies consists of a phenolic material. The assemblies are made of l'
a molded, cellulose-filled, phenolic material which has low impact
strength and may be highly susceptible to chipping or cracking.
Breakage or partial cracking of these assemblies may prevent the breaker
from performing its design function or other secondary functions l
provided by the status of the breaker position,
b. Observation and Findinas
i
The inspectors reviewed Operating Experience Program Evaluation. OER-ID: ;
IN 96-44, which documented the licensee's disposition of this issue, !
The RTBs installed are Westinghouse DS-416 type breakers which are the !
same type which were in use at the other nuclear facility which had been j
the subject of IN 96-44. As the result of the licensee's review of this !
issue the licensee determined that the PM procedure used for routine RTB l
inspection and maintenance required revision. The licensee determined !
that maximum torque values specified in the vendor manual might prevent i
overtorquing and resultant cracking of the disconnect assemblies. ;
Required procedure changes included specific ins)ection of the secondary j
disconnecting contact assembly for cracking of t1e phenolic material and j
incorporation of the torque values specified in the vendor manual into ;
the licensee's procedure. l
The inspectors reviewed PM Procedure. 27765-C Westinghouse Type DS-416
Circuit Breaker Maintenance, and verified that Step 4.9 includes a i
requirement to verify that the secondary contact assembly is free of l
cracks during this periodic inspection. Additionally, Step 4.9 requires ,
that whenever those assemblies are replaced torquing requirements from i
Westinghouse Vendor Manual AX6AT01-10005 would be followed. The !
'
inspectors were informed that the breaker insSection under the new
revised procedure had been performed during tie recent Unit 2 refueling
Enclosure 2
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outage and that no abnormalities were identified during those j
inspections. The breaker inspections for the Unit 1 breakers are i
scheduled for the upcoming refueling outage during September 1997.
l
c. Conclusions
!
The licensee has adequately addressed IN 96-44.
M8.4 (Closed) EEI 50-424/96-11-03: Unit 1 SIP Train B Loss of Function
An Enforcement Conference (EA 96-479) was held in the Region II office
on December 19, 1996 to discuss the issues identified in Escalated !
Enforcement Item (EEI) 50-424/96-11-03. Unit 1 SIP Train B Loss of ;
Function. (Refer to Section M3.1 of irs 50-424.425/96-11.) As a result !
of the conference, the EEI was closed and two violations were !
identified: VIO 50-424/96-479-01013. Inoperable IB Safety Injection Pump j
(SIP) for Period of at least 09/30/91 through 10/23/96 due to Inadequate ;
Cooling Flow to Its Motor Coolers, and VIO 50-424.425/96-479-01023. *
Inadequate Procedural Guidance to Assure Correct Installation of Motor ,
Cooler Gaskets and Plenums for Safety-Related Equipment. The Notices of !
Violation were issued as Enclosure 1 to the NRC letter of December 31. I
1996 summarizing the proceedings of the meeting.
III. Enaineerina
E7 Quality Assurance in Engineering Activities
t
E7.1 NOUE Problem Identification and Corrective Actions )
!
a, Insoection Scone (37551) l
As a result of a Notification of unusual Event (NOUE) that occurred on
November 15. the inspectors reviewed the licensee's engineering root !
cause/ problem identification and corrective action effort. This review
included assessment of the engineering process into the root cause of
the event and an evaluation of the adequacy of engineering support
personnel activities.
b. Observations and Findinas
As a result of a NOUE declared on October 25. (reference IR 50-424,
425/96-11. section 01.7) engineering personnel were requested to support
annunciator troubleshooting efforts. Engineering. I&C. and maintenance
personnel determined that a blown fuse in a power su) ply cabinet caused
- the loss of annunciator function. However, on Novem)er 15. a second
i similar event took place (reference section 01.2) as a result of the
l
same maintenance activity (i.e. ~ fixing a light socket. but on a
different annunciator pgnel). Investigation into this event also
determined that the same fuse blew. but that an undetected system ground
,
was present. Engineering personnel were able to identify a system
! Enclosure 2
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ground even though the complexity of the annunciator panel electrical !
system made it difficult to troubleshoot. During the process of the l
root cause investigation engineering personnel made manogement aware of !
potential issues and contributors to the event as they were determined. ;
As a result of the second event, the licensee developed additional
I corrective actions that included de-energizing the affected annunciator-
I
light box for future maintenance activities on light sockets. In ;
addition, the licensee plans.to com)lete a review of- system electrical i
drawings for other potential contri)utors to the event. j
c. Conclusions l
1
l The inspectors concluded that engineering personnel did an effective job' l
in determining the underlying root cause as a result of the second (
event. Engineering personnel effectively-supported operations, i
maintenance, and I&C troubleshooting efforts. Engineering )ersonnel :
involved the proper level of management commensurate with tie event. l
The inspectors also concluded that the licensee's planned corrective
actions as a result of the second event, to address future maintenance i
activities on annunciator light boxes was appropriate. ;
1
E8 Miscellaneous Engineering Issues (92903) j
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E8.1 (Closed) VIO 50-424.425/95-27-04: Partially Obstructed NSCW System Flow l
Orifice Corrective Actions inadequate To Preclude Repetition !
r
Violation 50-424, 425/95-27-04 documents the inadequate corrective
actions taken to prevent repetition of NSCW flow reduction events. The
re)ly to the violation itemizes additional corrective actions to be
tacen. The inspectors * review of this issue and the associated
corrective actions is documented in section M1.4 of this report. The
. inspectors determined that the corrective actions identified were
completed. therefore VIO 50-424.425/95-27-04 is closed.
E8.2 (Closed) LER 50-424/96-011: Inadequate Containment. Electrical
Penetration and Missed Surveillance.
This issue was discussed in this re) ort as part of Section M1.3. No new
issues were revealed by the LER. T11s LER is closed.
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Enclosure 2
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IV. Plant Support
R8 Miscellaneous Radiological Protection and Chemistry (RP&C) Issues !
(92700)
R8.1 (Closed) LER 50-424/96-008: Secondary Water Chemistry Tests not
Performed Prior to Power Ascension. .
1
The inspectors reviewed the circumstances associated with not performing
secondary water chemistry tests for dose equivalent iodine-131 prior to ,
power ascension as required by TS 4.7.1.4. as well as the following l
Chemistry procedures: )
,
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30025-C. Rev. 24. Periodic Analysis Scheduling Program
,
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30090-C. Rev.17. Chemistry Technical Specification '
Surveillance Performance Coordination ;
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35110-C. Rev. 22. Chemistry Control of the Reactor Coolant i
System
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35210-C. Rev. 14 Chemistry Control of the Steam Generators
On June 14. 1996, the licensee identified a procedural weakness when it l
discovered that specific chemistry surveillance tasks were not being ,
performed prior to mode 4 entry following a refueling outage. l
Specifically, the licensee identified that TS required surveillances for
specific activities were not done prior to power ascension upon the
completion of the 2R4 refueling outage in March 1995 and the IR6
refueling outage in April 1996. The licensee feels that it is likely
that this condition occurred following outages previous to these two
referenced outages. TS 3.7.1.4 requires the specific activity of the
secondary coolant system to be less than or equal to 0.1 microcurie per i
gram dose equivalent iodine-131 whenever the unit is in modes 1, 2. 3. i
or 4. The failure to complete the TS required surveillances prior to
entry into mode 4 is a violation of TS 3.7.1.4. The cause of the
failure was identified by the licensee as procedural inadequacy in that
the procedures did not specifically state that the surveillances were
required to be performed prior to entry into mode 4.
The required surveillances were made shortly after entering mode 4 in I
both cases and confirmed that the specific activity in the secondary
system was within the required TS limits. Therefore, there was no
adverse effect on plant safety nor on the health and safety of the
public as a result of these events. ;
I
The inspectors verified that the licensee revised the above-referenced
procedures to specify that the required sampling be completed prior to
entry into the applicable mode. l
Enclosure 2
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The inspectors concluded that the failure to complete the secondary
system sampling prior to entry into mode 4 violated the requirements of
TS 3/4.7.1.4. However, consistent with Section VII of the NRC
Enforcement Policy, this is identified as NCV 50-424.425/96-12-03.
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Failure to Complete Required Sampling Prior to Entering Mode 4. Based
upon the inspector's review, this LER is closed.
P1 Conduct of EP Activities
Pl.1 Conduct of 1996 Full Scale Emeroency Preparedness (EP) Exercise (71750)
On November 20. 1996 the licensee conducted a full scale EP exercise.
Participants in the emergency exercise included state and county
representatives from Georgia and South Carolina, and the resident
inspectors. The inspectors observed and Jartici)ated in the exercise
from the Emergency Operating Facility (E02). Tec1nical Su) port Center
(TSC). Operations Support Center (OSC), and simulator. T1e results of
the EP exercise are documented in a separate report. IR
50-424.425/96-13.
The resident inspectors did not identify any specific concerns.
F5 Fire Protection Staff Training and Qualification
F5.1 Announced Fire Drill (71750)
On December 10 and 11. '396, the inspectors observed an announced fire
drill. The scenario was a truck fire located at the A 1 pumps near the
receiving warehouse. This location is outside of the mtected area.
The fire team response was timely. Equipment was readily available and
in adequate condition. The self-contained air breathing ap)aratuses
were suffit.iantly charged and in good working condition. T1e fire team
established good communications with the control room and security.
Minor issues identified by the inspectors were forwarded to the licensee
and adequately addressed.
Overall, the inspectors concluded that the drill was well controlled and
met the performance criteria established by the licensee.
V. Manaaement Meetinas and Other Areas
X1 Exit Meeting Summary
The inspectors ) resented the inspection results to members of licensee
management at t1e conclusion of the inspection on December 23, 1996.
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.
Enclosure 2
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After the conclusion of one of the regional reactor inspector's exit
performed on December 6. the licensee was notified by telephone at
approximately 2:30 p.m. December 9.1996, that the issue relating to -i
unsecured MCC door latches, would be the subject of a violation. i
!
X2 Pre Decisional Enforcement Conference Summary l
On December 19. 1996, a pre-decisional enforcement conference was held ;
at the NRC Region II office to discuss potential enforcement issues l
' identified in IR 50-424.425/96-11. Issues discussed primarily focused j
on emergency core cooling system pump motor cooler maintenance :
activities and the operability of the Unit 1 safety injection pump train. i
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B since September 30, 1991.
X3 Review of Final Safety Analysis Report !
A recent discovery of a licensee operating its facility in a manner l
contrary to the Updated Final Safety Analysis Report (UFSAR) description
'
highlighted the need for a special focused review that compares plant l
practices, procedures and/or parameters to the UFSAR descriptions.
While )erforming the inspections discussed in this report, it was noted
'
that tie licensee had determined that the UFSAR Table 16.3-5.
Containment Penetration Conductor Overcurrent Protection Devices and
Isolation Devices for Class 1E to Non-Class 1E Feeds, did not list all
required lighting circuit breakers for surveillance testing. This is
discussed in section M1.3 of this report. The ins)ectors reviewed the ,
applicable portions of the UFSAR that related to t7e areas inspected.
l
X4 Hanagement Meeting Summary
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PARTIAL LIST OF PERSONS CONTACTED j
Licensee
l
J. Beasley. Nuclear Plant General Manager
J. Gasser. Plant Operations Assistant General Manager
S. Chesnut. Manager Operations
P. Rushton. Plant Support Assistant General Manager ;
K. Holmes. Manager Maintenance !
W. Burmeister. Manger Engineering Support
B. Brown. Manager Emergency Preparedness and Training
M. Sheibani. Nuclear Safety and Compliance Supervisor
C. Stinespring. Manager Plant Administration
C. Tippins. Jr.. Nuclear Specialist I l
Enclosure 2 i
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INSPFCTION PROCEDURES USED
l IP 37551: Onsite Engineering
l IP 40500: Effectiveness of Licensee Controls In Identifying. Resolving, and
l Preventing Problems i
IP 61726: Surveillance Observations
- IP 62700: Maintenance Implementation
, IP 62703: Maintenance Observations
IP 62707: Maintenance Observations
IP 71707: Plant Operations
IP 71714: Cold Weather Preparations
l IP 71750: Plant Support Activities '
IP 92700.: Onsite Notification of Written Reports of Non-routine Events At
Power Reactor Facilities
IP 92902: Followup - Maintenance
IP 92903: Followup - Engineering
IP 93702: Prompt Onsite Response To Events At Operating Power Reactors
REFERENCED PROCEDURES AND DRAWINGS
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GPC PM Procedure 27765-C. Westinghouse Type DS-416 Circuit Breaker
Maintenance
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GPC Procedure 14445-1. Rev. 4. Remote Shutdown Monitoring
Instrumentation Channel Check Unit 1
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GPC Procedure 14445-2. Rev. 2. Remote Shutdown Monitoring
Instrumentation Channel Check. Unit 2 l
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GPC Procedure 14710-1 Rev. 19. Remote Shutdown Panel Transfer Switch !
and Control Circuit 18 Month Surveillance Test. Unit 1
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GPC Procedure 14710-2. Rev. 17. Remote Shutdown Panel Transfer Switch !
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and Control Circuit 18 Month Surveillance Test. Unit 2
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DCP 88-V1N0076. Deletion of Automatic Closure Interlock for RHR Hot Leg
Isolation Valves
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DCP 90-V2N0029. AFW to S/G 3 Testing Provision DCP 87-V1E0242. RHR Hot
Leg Isolation Valves RCS Pressure Open Permissive Interlock Setpoint
Change
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DCP 91-V2N0142. Change Handswitch Logic on Power Lockout Handswitch on
Main Control Board
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DCP 92-VIN 0058. NSCW Reliability Upgrade ;
ITEMS OPENED. CLOSED, AND DISCUSSED
Opened l
50-424. 425/96-12-01 NCV Failure to Perform Containment Penetration
Circuit Breaker Surveillances (Section M1.3)
50-424. 425/96-12-02 VIO Failure to Take Effective Corrective Actions to
Assure MCC Door Latches Are Properly Secured
(Section M1.6)
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1 Enclosure 2
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50-424, 425/96-12-03 NCV Failure to Complete Required Sampling Prior to
Entering Mode 4 (Section R8.1)
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50-424/96-479-01013 VIO Inoperable IB Safety Injection Pum) (SIP) for
! Period of at least 09/30/91 througl 10/23/96 due
l to Inadequate Cooling Flow to Its Motor Coolers
l (Section M8.4)
i
50-424,425/96-479-01023 VIO Inadequate Procedural Guidance to Assure Correct
!
Installation of Motor Cooler Gaskets and Plenums j
for Safety-Related Equipment (Section M8.4) l
50-424, 425/96-12-01 NCV Failure to Perform Containment Penetration
Circuit Breaker Surveillances (Section M1.3)
50-424, 425/95-27-04 VIO Partially Obstructed NSCW System Flow Orifice
Corrective Actions Inadequate to Preclude
Repetition (Section E8.1)
50-424/96-011 LER Inadequate Containment Electrical Penetration
and Missed Surveillance (Section E8.2).
50-424/96-008 LER Secondary Water Chemistry Tests Not Performed
Prior to Power Ascension (Section R8.1)
50-424. 425/96-12-03 NCV Failure to Complete Required Sampling Prior to
Entering Mode 4 (Section R8.1)
50-424/96-11-03 EEI Unit 1 Safety Injection Pump Train B Loss of
Function (Sectin M8.4)
LIST OF ACRONYMS USED
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- ASME - American Society of Mechanical Engineering
l BOP - Balance of Plant
CCP - Centrifugal Charging Pump
CCW - Component Cooling Water
CFR - Code of Federal Regulations
DC - Deficiency Card
DCP - Design Change Package
DG - Diesel Generator
EOF - Emergency Operating Facility
FME - Foreign Material Exclusion
ESF - Engineered Safety Feature 4
2
ft - square feet
GPC - Georgia Power Company
I&C - Instrumentation and Controls ,
,
Enclosure 2
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IN - Information Notice
IR - Inspection Report
IP - Inspection Procedure
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LER - Licensee Event Report
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M&TE - Maintenance and Test Equipment
MCC - Motor Control Center
MWO - Maintenance Work Order '
MWt - Megawatt Thermal
NCV - Non-Cited Violation
NOUE - Notification of Unusual Event
NPF - Nuclear Power Facility
NRC - Nuclear Regulatory Commission
NSAC - Nuclear Safety and Compliance
NSCW - Nuclear Service Cooling Water ;
NUREG - Nuclear Regulations
OSC - Operations Support Center
PDR - Public Document Room
PM - Preventive Maintenance
PRB - Plant Review Board
REA - Request for Engineering Assistance
RP&C - Radiological Protection and Chemistry
RSP - Remote Shutdown Panel
RTB - Reactor Trip Breaker
S/G - Steam Generator
TDAFW - Turbine Driven Auxiliary Feedwater
TS - Technical Specifications
TSC - Technical Support Center ,
UFSAR - Updated Final Safety Analysis Report
VAC - Volts Alternating Current
VEGP - Vogtle Electric Generating Plant
VIO - Violation
1R6 - Unit 1 Sixth Refueling Outage
2R4 - Unit 2 Fourth Refueling Outage
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Enclosure 2
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