ML17264A186
| ML17264A186 | |
| Person / Time | |
|---|---|
| Site: | Ginna  |
| Issue date: | 09/29/1995 |
| From: | Lazarus W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML17264A185 | List: |
| References | |
| 50-244-95-15, NUDOCS 9510110047 | |
| Download: ML17264A186 (28) | |
See also: IR 05000244/1995015
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION I
Inspection Report 50-244/95-15
License:
Facility:
Inspection:
Inspectors:
R.
E. Ginna Nuclear
Power Plant
Rochester
Gas
and Electric Corporation
(RG&E)
July 30,
1995 through September
9,
1995
P.
D. Drysdale,
Senior Resident
Inspector,
Ginna
E.
C. Knutson,
Resident
Inspector,
Ginna
E.
H. Gray, Chief, Non-Destructive Engineering Section,
Region I
A. R. Johnson,
Ginna Project Manager,
Approved by:
az~rus
ie
,
eac or
roJects
ection
P8~
~s
Kaae
INSPECTION SCOPE
Plant operations,
maintenance,
engineering,
plant support,
and safety
assessment/quality
verification.
95iOii0047 95i003
ADQCK 05000244
6
INSPECTION EXECUTIVE SUNMARY
Operations
The plant operated
at full power (approximately
97 percent) for the majority
of the inspection period.
During this period,
a lightning strike caused
a
momentary loss of two of the four class
1E electrical
buses.
Corrective
maintenance
had
been performed
on the associated
emergency diesel
generator
(EDG) earlier that day; although administratively inoperable at the time of
the event,
licensee
management
had earlier made the decision to defer
acceptance
testing
and to place the
EDG in automatic
standby
due to impending
storm conditions.
As a result,
the
EDG was available during the event.
The
EDG started
and loaded normally,
and all other engineered
safety features
equipment functioned
as required.
The event
had
no effect on reactor
power.
The operators
responded
well to the event.
management's
decision to make the
EDG available prior to performance of acceptance
testing
was prudent.
Later in this period, the shift supervisor directed that the reactor
be
manually tripped from approximately
70 percent reactor
power due to a
secondary
plant transient that was caused
by the loss of power to
a main
circulating water
(CW) pump.
All engineered
safety features
equipment
functioned
as required
and operators
promptly stabilized the plant in hot
shutdown.
The shift supervisor's
decision to manually trip the reactor
was
appropriate.
Operator response
to the transient
and reactor trip was good.
management effectively integrated resolution of
CW pump motor failure and
other secondary plant technical
issues with plans for plant restart.
The
licensee's
decision to also inspect the unaffected
CW pump was prudent
and led
to identification of a malfunction that would otherwise
have gone undetected.
Naintenance
As a result of maintenance activities to correct low fuel oil pressure
on the
B-emergency diesel
generator,
the licensee
determined that the replacement
fuel
pump model that was specified in the vendor manual
required modification
to produce the desired
discharge
pressure.
Although the required value of
fuel oil pump discharge
pressure
is engine-spe 'fic, the licensee
issued
an
interim notice to the
NRC of the problem in accordance
with 10 CFR Part 21.
RG&E had obtained
spare
replacement
pumps through
a commercial
procurement
process
and later dedicated
them for nuclear service.
All of the
pumps that
had
shown reduced
performance
when installed
on the
EDG had
been successfully
tested
by RG&E prior to being released
to the spare parts
system,
raising
questions
regarding the adequacy of commercial
grade dedication testing.
The
licensee
indicated that
a review of the procurement
and dedication
processes
will be conducted
as part of the root cause evaluation.
During routine surveillance testing of the undervoltage
(UV) protection
system,
the practice of testing
a malfunctioning indicating light by using
a
nearby "working" indicating light bulb produced
an alarm indication of a
possible loss of undervoltage protection for safeguards
bus
17.
The
B
EDG was
started
and connected
to bus
17 to assure
the continued availability of
protection during troubleshooting.
The cause
was subsequently
determined to be that the indicating light in question
had
been tested with an
(EXECUTIVE SUNNRY CONTINUED)
incompatible light bulb, which caused
a fuse in the indicating light circuitry
to blow.
The undervoltage protection function of the cabinet
had not been
affected,
and therefore,
operability of the
UV cabinet
had not been lost as
a
result of this event.
Corrective action included listing all the various indicating lamps of all 480
VAC UV relay and control cabinets
under the applicable
equipment
identification numbers
(EINs).
The licensee
also conducted training on this
incident for all Results
and Test Department
personnel
to review its causes
and corrective actions.
The inspector considered
that the potential for a
problem similar to this incident existed in other electrical
maintenance
and
test areas.
The licensee
subsequently
agreed to review the standard
practices
for troubleshooting
indicator light faults
and to expand training on the event
to include
I&C technicians
and electrical
maintenance
personnel.
The licensee
has experienced
water leakage into the residual
heat
removal
system
pump room for several
years.
The inleakage is currently too small to
represent
any operational
safety concern for the plant.
All potential
sources
of the leakage
have not yet been positively identified by the licensee.
Ground water appears
to be entering the room; however,
RG&E's analyses
also
indicate the presence
of boric acid and radionuclides that are also present
in
the spent fuel pool.
The licensee is removing the scale buildup from the area
of inleakage to facilitate better collection.
The inspector will continue to
monitor licensee efforts to quantify the water inleakage rate
and to
positively identify all sources.
The licensee is planning to replace
both steam generators
(SGs) during the
next refueling outage,
currently scheduled
to begin in Harch
1996.
The
inspectors
are monitoring the licensee's'reparations
for SG replacement
and
are reviewing the effectiveness
of RG&E's project management
controls, the
safety evaluations
prepared for the project,
and the engineering
specifications
associated
with the
new SGs.
During this period, the
NRR and
Region I-based Project Managers visited the site to obtain
an overview of the
SG replacement
project
(SGRP)
and to coordinate
inspection plans.
No areas of
concern
were identified during review of the
SGRP.
The licensee
was well
prepared
to address
questions
posed during the discussions.
Engineering
During a routine start of the D-service water
(SW) pump, the motor began to
emit smoke
and flames.
The licensee
determined that the likely cause of
failure was
a phase-to-ground
short circuit that developed
due to vibration-
induced degradation of the winding insulation.
A similar failure had occurred
with this motor several
years earlier,
and the motor had
been refurbished
by a
vendor
and returned to service.
On this occurrence,
the licensee
decided to
replace
the motor with a commercial-grade
motor that had
been
intended for
installation
and dedication during the next refueling outage.
The licensee
initiated
an internal engineering
action to review all of the
known new motor
characteristics,
to determine
the extent of dedication testing necessary,
and
'(EXECUTIVE SUMMARY CONTINUED)
to perform
10 CFR 50.59 safety evaluations of any necessary
plant
modifications necessary
to perform dedication testing during plant operations.
The inspector considered that the licensee
made
a sound decision to replace
the
D-SW pump motor and restore
the
pump to operability in a timely manner
through installed dedication testing.
" The new motor's performance
was
thoroughly modeled
and reviewed, with conservative
engineering
assumptions
and
ample consideration
for the existing plant design
and safety evaluations.
Plant Support
During recent months,
several
incidents
have occurred
where personnel
entering
a radiologically controlled area
(RCA) in the plant did not log into the
licensee's
radiation work permit
(RWP) access
control system,
and/or did not
have the secondary
alarming dosimetry required for entry.
None of the
incidents involved entry without the primary personnel
exposure monitoring
devices
(thermoluminescent
dosimeters);
however, all represented
a failure of
qualified radiation workers to adhere to the procedure
requirements
pertaining
to
RCA access,
RWP work controls,
and possession
of alarming dosimetry.
Although of minor radiological
consequence,
these
incidents represent
a
relatively high occurrence
over
a seven
month period of a lack of adherence
to
procedure
requirements
for radiological
work controls
and access
to radiation
and high radiation areas.
This item is unresolved
pending
NRC review of the
licensee's
human performance evaluation report
and the licensee's
implementation of permanent corrective actions.
TABLE OF CONTENTS
EXECUTIVE SUMMARY .
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ii
TABLE OF
CONTENTS
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v
1.0
OPERATIONS
1.1
Operations
Over view...
1.2
Operational
Experiences
.
1.2. 1 Loss of One Offsite
1.2.2 Manual Reactor Trip
Water
Pump
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Power Supply
due to Loss of a Main
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Circul ating
1
1
1
1
2
2.0
MAINTENANCE .
2. 1
Maintenance Activities
2. 1. 1 Routine Observations
2.2
Surveillance
and Testing Activities
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2.2. 1 Routine Observations
2.2.2 B-Emergency Diesel Generator
Low Fuel Oil Pressure
and
10 CFR 21 Report
2.2.3
Bus
17 Undervoltage
Cabinet Indicating Light Failure
2.3
Water Leakage Into the Residual
Heat
Removal
System
Pump
oom
R
4
5
5
5
6
7
3.0 ENGINEERING............................
8
3.1
Service
Water
Pump Motor Failure
and Subsequent
Upgrade
.
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8
3.2
Replacement
Project
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4.0
5.0
6.0
PLANT SUPPORT
.
4. 1
Radiological
Work Controls
and External
in Radiologically Controlled Areas
SAFETY ASSESSMENT/OUALITY VERIFICATION
5. 1
Periodic Reports
5.2
Licensee
Event Reports
ADMINISTRATIVE
6. 1
Senior
NRC Management
Site Visits
.
6.2
Exit Meetings
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11
Exposure Monitoring
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14
14
DETAILS
1.0
OPERATIONS (71707)
1.1
Operations
Overview
At the beginning of the inspection period, the plant was operating at full
power (approximately
97 percent).
On August 3,
1995,
one of the two offsite
electrical
power supplies
deenergized
due to
a lightning strike.
This
resulted in a momentary loss of two of the four class
lE electrical
buses
until the associated
emergency diesel
generator
started
and
assumed electrical
loads.
All engineered
safety features
equipment functioned
as required
and
the event
had
no effect on reactor
power.
On August 25,
1995, the shift supervisor directed that the reactor
be manually
tripped from approximately
70 percent reactor
power due to a secondary
plant
transient that was caused
by the loss of a main circulating water pump.
All
engineered
safety features
equipment functioned
as required
and operators
promptly stabilized the plant in hot shutdown.
Following resolution of
several
balance-of-plant
issues,
a plant startup
was performed
on August 26,
1995.
Plant power was escalated
to 48 percent
and held pending repair of the
failed main circulating water pump.
Before this was completed,
a through-wall
pipe leak was discovered
in a moisture separator
drain line to the main
condenser.
A controlled steam plant shutdown
was conducted
on August 28,
1995, to support replacement
of the affected piping.
During this shutdown,
repairs
were also completed to the main circulating water pump.
A steam plant
star tup was conducted later the
same
day and the plant returned to full power
operation
on August 30,
1995.
There were
no other significant operational
events or challenges
during the inspection period.
1.2
Operational
Experiences
1.2.1 Loss of One Offsite Power Supply
On August 3,
1995,
the B-emergency diesel
generator
(EDG) was declared
inoperable to investigate
a decreasing
trend in fuel oil pressure;
the
maintenance activity is discussed
in detail in section 2.2.2 of this report.
By that afternoon,
maintenance
was complete
and the
B-EDG was prepared for
operation to conduct acceptance
testing.
However, licensee
management
decided
to defer testing
and to align the
B-EDG for normal operation
due to lightning
storm activity.
At 3:26 p.m.
on August 3,
1995,
a lightning strike occurred offsite on one of
the plant's
two offsite electrical
power circuits (circuit 751).
As a result
of the transient, circuit 751
was deenergized
by protective relays at offsite
station
204.
This resulted in a loss of power to the two class
1E 480-volt
electrical
busses
that were being supplied
by circuit 751
(busses
16 and 17).
In response
to the power loss,
the
B-EDG automatically started
and reenergized
the two busses.
Operators
responded
in accordance
with abnormal
procedure
AP-
ELEC. 1, "Loss of 12A and/or
12B Busses,"
to stabilize affected
systems.
All
engineered
safeguards
equipment functioned
as required
and plant power was not
affected
by the transient.
At 4:28 p.m., the electrical distribution system
was realigned
such that the
unaffected offsite electrical
power circuit (circuit 767)
was supplying all
four class
lE 480-volt electrical
busses.
The
B-EDG was shut
down and
returned to standby.
Circuit 751 was returned to service at 4:44 p.m.;
however,
the circuit was not placed in service
due to continued
storm
activity.
Based
on control
room observations,
review of logs,
and discussions
with plant
personnel,
the inspector determined that operators
had responded
appropriately
to the loss of circuit 751.
The inspector
observed
good procedural
adherence
during plant restoration.
Operator communications
were formal
and concise.
The Control
Room Foreman provided excellent oversight of the restoration
activities.
Additionally, licensee
management's
decis'ion to defer
acceptance
testing
due to storm activity was prudent.
The technical
specification requirements for one
EDG being inoperable
had
been satisfied
prior to the event,
and loss of one offsite power supply does not alter these
requirements.
A four-hour
non-emergency
report was
made to the
NRC as
required
by 10 CFR 50.72.
1.2.2 Manual Reactor Trip due to Loss of a Main Circulating Water
Pump
The main circulating water system supplies cooling water to the main
condensers
to condense
exhaust
steam
from the two low pressure
turbines.
The
system consists of two headers,
each of which is supplied
by a circulating
water
(CW) pump.
Each header
supplies
The headers
are
cross-connected
upstream of the main condensers
to allow for reduced
power
operations with a single operating
CW pump.
After passing
through the main
condensers,
main circulating water is returned to the lake via a common
discharge
canal.
At 5:41 a.m.
on August 25,
1995, the
B-CW pump tripped.
Control
room
operators
were alerted to the problem by the associated
main control board
Turbine load was rapidly reduced to approximately
50 percent in
accordance
with abnormal
procedure
AP-CW. 1,
"Loss of a Circulating Water
Pump."
Operators
then noted that turbine backpressure
in the condenser
associated
with the failed
CW pump (B-main condenser)
was increasing,
and that
the normally equal levels in the main condenser
hotwells were diverging;
specifically, hotwell level in the B-main condenser
was decreasing,
while
level in the other hotwell (associated
with the operating
CW pump)
was
increasing.
These
abnormal
conditions were developing
because
the
B-CW pump had tripped
rather
than having
been
secured
as part of an orderly transition to single
pump operation.
Although the plant can operate
at up to 50 percent
power on
a
single
CW pump, the. system must first be reconfigured; specifically, the
discharge isolation valve for the
pump to be secured
must be closed before the
CW pump is stopped.
In this case,
the discharge
isolation valve was initially
open
when the
B-CW pump stopped.
The valve is motor operated
and
automatically
began to close
when the
B-CW pump tripped;
however,
closure of
this large valve takes
on the order of minutes.
As
a result,
cross-connected
flow from the
A-CW pump discharged
back to the idle B-CW pump rather than
being forced through the B-main condenser.
The loss of cooling water caused
pressure
in the secondary
side of the B-main condenser
to increase.
The two
connect to a
common suction header for the main condensate
pumps;
consequently,
hotwell level in the B-main condenser
dropped rapidly as
condensate
was either forced into the lower pressure
A-main condenser
hotwell
or supplied to the main condensate
pumps.
As level in the B-main condenser
hotwell approached
empty, the condensate
pumps
began to cavitate
and discharge
pressure
began to drop.
This translated
to low suction pressure
to the main feedwater
pumps.
Given the potential for
damage to secondary
plant equipment
and
a possible loss of main feedwater
flow, the shift supervisor directed that the reactor
be manually tripped.
With reactor
power at approximately
70 percent
and decreasing,
operators
tripped the reactor at 5:43 a.m.,
approximately
two minutes after loss of the
B-CW pump.
Plant response
to the trip was normal.
All safety systems
and
equipment
responded
as required.
Operators
promptly stabilized plant
conditions in hot shutdown.
Investigation revealed that the
B-CW pump breaker
had tripped due to actuation
of the
power factor relay.
The relay trip setpoint
was checked
and found to
be correctly set.
Inspection of the
8-CW pump motor revealed that
a diode in
the synchronizing circuit had
become disconnected.
The licensee
determined
that this failure would have produced
a power factor trip.
Additionally, one
of the mounting bolts for the baseplate
that attaches
synchronizing circuitry
components
to the motor rotating assembly
was found sheared
at the head.
Localized minor insulation
damage
on the stator windings was also noted.
The
licensee
theorized that when failure of this bolt occurred,
the bolt head
had
struck and broken the diode conductor;
as it continued out, the bolt head also
produced the stator winding insulation damage.
Ultrasonic testing
was
performed
on the remaining baseplate
bolts for the
B-CM pump,
and
no
indications of incipient failure were detected.
Additionally, the
A-CW pump
was shut
down for examination of the baseplate
bolts, with no problems noted.
Licensee efforts to determine
the cause of the belt failure were continuing at
the end of the inspection period.
Following replacement
of the failed bolt and diode,
and repair of the stator
winding insulation,
an operational
test of the
8-CW pump was attempted.
This
test
was unsuccessful,
with the motor breaker
again tripping on actuation of
the power factor relay.
Additional troubleshooting
revealed that
a modul'e in
the synchronizing circuit was defective.
Following replacement
of this
module, the
B-CW pump was tested satisfactorily
and returned to service.
Although no problems
had previously been experienced
with the
A-CW pump, it
also failed to start following completion of the bolt inspection.
Troubleshooting
revealed that the
same synchronizing
module that had failed in
the
B-CW pump was also malfunctioning in the
A-CW pump.
Both pump motors
had
been refurbished during the
1995 refueling outage,
and the licensee
suspected
that heating during application of varnish to the rotors
may have contributed
to failure of the synchronizing modules.
A second
replacement
module was not
immediately available.
Licensee
management
decided that the plant would be
returned to operation,
with power limited to 50 percent until the
A-CW pump
could be returned to service.
A reactor startup
was
commenced
on August 26,
1995,
and criticality was
achieved at 1:53 p.m.
The main generator
was closed
on the grid at 5:56 p.m.,
and plant power was raised to approximately
50 percent
by morning of the
following day.
On August 28,
1995,
a steam plant shutdown
was performed to
support repair of a through-wall pipe leak in a moisture separator
reheater
drain line.
The reactor
was maintained critical during this maintenance.
Coincident with the shutdown,
a replacement
module for the
A-CW pump motor
synchronizing circuit was obtained
and installed.
A steam plant startup
was
conducted later the
same day,
and full power was achieved at 2:44 a.m.
on
August 30,
1995.
The inspector considered that the licensee's
action to manually trip the
reactor following loss of the
B-CW pump was appropriate.
Through discussions
with licensee
personnel,
review of archived plant data,
and attendance
of the
post trip review meeting,
the inspector
concluded that operators
had responded
well to the reactor trip and that the plant had responded
normally.
No
technical specification requirements
had
been violated,
and
no technical
issues
related to the reactor plant were identified.
A four-hour non-
emergency report was
made to the
NRC as required
by 10 CFR 50.72.
Licensee
management effectively integrated resolution of the
B-CW pump motor failure
and other secondary
plant technical
issues with plans for plant restart.
The
licensee's
decision to also inspect the
A-CW pump was prudent
and led to
identification of a malfunction that would otherwise
have gone undetected.
2.0
NAINTENANCE (62703,
61726)
2. 1
Naintenance Activities
2. 1.1 Routine Observations
The inspector
observed
portions of plant maintenance activities to verify that
the correct parts
and tools were utilized, the applicable industry code
and
technical specification requirements
were satisfied,
adequate
measures
were in
place to ensure
personnel
safety
and prevent
damage to plant structures,
systems,
and components,
and to ensure that equipment operability was verified
upon completion of post maintenance
testing.
The following maintenance
activities were observed:
~
Placement of the
new D-SW pump motor (observed
August 15,
1995),
motor
power cable junction box modification (observed
August 21, 1995),
and
motor/pump commercial
grade dedication
and acceptance
testing
(observed
August 24,
1995).
The inspector
concluded that the above activities were performed in a well
controlled manner
and that the maintenance craft actions to install the
new
pump motor
and to perform the required
acceptance
test represented
good
quality performance.
2.2
Surveillance
and Testing Activities
2.2. 1 Routine Observations
Inspectors
observed portions of surveillances
to verify proper calibration of
test instrumentation,
use of approved
procedures,
performance of work by
qualified personnel,
conformance to limiting conditions for operation
(LCOs),
and correct system restoration
following testing.
The following surveillances
were observed:
~
PT-12.2,
"Emergency Diesel
Generator 8," observed
August 6,
1995
~
PT-36M-D, "Standby Auxiliary Feedwater
Pump
C - Honthly," observed
August 16,
1995
~
PT-12. 1,
"Emergency Diesel
Generator
A," observed
September
5,
1995
The inspector determined
through observing the above surveillance tests that
operations
and test personnel
adhered
to procedures,
test results
and
equipment operating
parameters
met acceptance
criteria,
and redundant
equipment
was available for emergency
operation.
Additionally, during
an inspection of the
8-EDG following the performance of
PT-12.2
on September
7,
1995,
the inspector noted that the prelubricating oil
pump was not running.
This pump runs at all times when the
EDG is shutdown in
standby,
and provides engine lubrication during startup
and shutdown.
The
inspector reported the problem to the shift supervisor,
and the
8-EDG was
declared
Troubleshooting
revealed that the
pump motor start relay
had failed.
This suggested
that the motor may never have started after the
EDG had
been
secured
at the conclusion of PT-12.2.
The relay was replaced
and
the
EDG was returned to service later that day.
As corrective action, the
licensee
is modifying PT-12. 1 and -12.2 to include
a verification that the
prelubricating oil pump is running after the 'EDG is secured.
2.2.2 B-Emergency Diesel
Generator
Low Fuel Oil Pressure
and
10 CFR 21 Report
On August 3,
1995, the 8-emergency
diesel
generator
(EDG) was declared
inoperable to investigate
a decreasing
trend in fuel oil pressure.
Normal
fuel pressure
is 38-45 psig, but pressure
had decreased
in July 1995 to the
licensee's
alert range alert limit of 35 psig.
In August 1995, pressure
decreased
below the action limit of 32 psig at full diesel
load.
The licensee
completed
maintenance
on the fuel oil system the
same afternoon
by replacing
system filters, check valves,
the pressure regulating/relief valve,
and
flexible fuel lines.
The inspector witnessed
the post maintenance
acceptance
testing
and observed that fuel oil pressure
remained
below the action limit
with the diesel fully loaded.
During the test,
the licensee's
attempts to
adjust the pressure
higher w'ere not successful.
Consequently,
the licensee
replaced
the fuel
pump with a new spare
from stock and retested
the diesel.
No pressure
improvement
was observed with the
new pump.
The licensee
again
replaced that
pump with another
new spare
pump,
and repeated
the test,
but no
improvement in fuel pressure
resulted.
The licensee
held discussions
with the diesel
vendor to confirm that the fuel
pump was the correct
model (Tuthill Hodel
and to investigate other
possible
causes
for the low pressure.
However, the vendor technical
manual
indicates that fuel
pump performance
can
be improved by removing shims from
the
pump cover gasket.
The licensee
investigated this option and determined
that end play in both of the replacement
pumps
was larger than the minimum
specified in the vendor manual,
and larger than the end play in another
spare
pump
known to have
good pressure.
Cover gasket
shims were removed
from the
replacement
pumps to reduce
end play,
and the diesel
was retested.
The test
was successfully
completed
when fuel pressure
was restored to 55 psig at no
load and 44 psig at full load.
On August 28,
1995, the licensee
issued
an interim notice to the
NRC of the
problem in accordance
with 10 CFR Part 21, indicating that
a full written
report would be forthcoming by September
25,
1995.
The preliminary
information supplied
by
RG&E indicated that the fuel
pump was
an exact
replacement
(by model
number) for the original
pump that the licensee
had
tested to meet the performance
requirements
established
by the original
manufacturer.
The safety concern
noted
by
RG&E that warranted
a
10 CFR Part 21 report was that the diesel
may not have
been able to maintain its design
loading with reduced
fuel pressure
from similar pumps
on
EDGs at other nuclear
facilities.
Although the diesel
manufacturer
does not specify
a minimum fuel
pressure
for operability, the actual
lower limit varies
from diesel
to diesel
and
had not been established
for the
EDGs at Ginna.
RG&E obtained their spare
replacement
pumps through
a commercial
procurement
process
and later dedicated
them for nuclear service with a shop test using the pumps'riginal
performance specifications.
All of the
pumps that
showed
reduced
performance
when installed
on the
EDG had
been successfully tested
by RG&E prior to being
released
to the spare parts
system.
The reason for this discrepancy
has not
yet been determined.
The inspector discussed
with the licensee
the potential for procurement or
commercial
grade dedication
issues that may have contributed to the degraded
fuel
pump performance.
The licensee
shared
these
concerns
and indicated that
a review of the procurement
and.dedication
processes will be conducted
as part
of the root cause
evaluations
performed through the action report process that
was used to pursue the
pump pressure
problem.
2.2.3
Bus
17 Undervoltage Cabinet Indicating Light Failure
On August 9,
1995, the licensee
was performing
a regularly scheduled
surveillance test
(PT-9.1. 17),
"480
VAC Undervoltage Protection,"
on
safeguards
bus
17.
During the test,
Results
and Test Department technicians
noted that the lamp for the "125
VDC Normal" indication on the undervoltage
(UV) relay cabinet
panel
was not lit as expected.
A technician put
a spare
bulb into the socket,
which lit up momentarily,
but then blew out.
The
technician
then
used
an adjacent
working bulb from the
"120 VAC Normal"
indicator on the cabinet
panel to again "test" the socket.
This bulb also
blew out and caused
a
DC control voltage failure alarm for the bus
17
cabinet to annunciate
in the plant's control
room.
The technicians
and plant operators
immediately notified their supervision of
this condition,
who in turn discussed
the situation with the Plant Production
Superintendent,
the Operations
Hanager,
and the System Engineer.
Loss of UV
protection
on safeguards
bus no.
17 for greater
than
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> requires
an entry
into technical specification
LCO 3.0. 1,
and immediate initiation of a plant
shutdown.
The Plant Superintendent
concluded that the operability of the
cabinet
was not assured
under the existing conditions
and determined that the
B-EDG should
be started
and connected
to bus
17 as
a conservative
action to
assure
the continued availability of normal
power and undervoltage protection
to bus 17.
An entry into the action statement for TS 3.0.1
was therefore not
required.
The licensee
generated
action report
AR 95-0249 to review the causes
of this
incident
and to initiate maintenance
actions to troubleshoot
and repair the
faulty indicator lamp problems.
It was determined that the control
room
trouble alarm resulted
from a blown cabinet fuse (F-1) after arcing in the
socket
was caused
by the installation of a
DC bulb.
The F-1 fuse conducts
120
VAC from instrument
bus
16 to the bus
17
UV cabinet
and energizes
the panel
indication lamps only, without affecting the 480
VAC UV protection function of
the cabinet.
Oper ability of the
UV cabinet
was therefore not lost as
a result
of this event.
However, the F-1 fuse
was replaced,
the proper bulb was
installed in the "125
VDC Normal" socket,
and
PT 9. 1. 17 was completed
satisfactorily before the
B-EDG was secured
and normal
power restored to the
bus
17
UV cabinet.
The licensee dispositioned
AR 95-0249
by listing all the various indicating
lamps of all 480
VAC UV relay and control cabinets
under the applicable
equipment identification numbers
(EINs).
This was done to assure that bulbs
drawn from spare parts
and used to replace faulted bulbs
on
UV cabinets
would
have the required electrical characteristics
confirmed by Procurement
Engineering.
The licensee
also conducted training on this incident for all
Results
and Test Department
personnel
to review its causes
and corrective
ac'ions.
The inspector discussed
with the licensee
the apparent fact that it
was not unusual
for
ILC technicians
and electrical
maintenance
technicians
(both at
RG&E and industry-wide) to "borrow" light bulbs from adjacent
locations to test whether indicator light problems
were "bulb-related" or
"socket-related."
The licensee
agreed that the potential for a problem
similar to this incident existed in other electrical
maintenance
and test
areas,
and stated that
a review would be performed
and any appropriate
changes
made to the standard
practices for troubleshooting indicator light faults.
Training on the bus
17
UV cabinet incident was subsequently
planned for I&C
technicians
and electrical
maintenance
personnel
to preclude this practice.
2.3
Mater
Leakage Into the Residual
Heat Removal
System
Pump
Room
The licensee
has experienced
water leakage into the residual
heat
removal
(RHR) system
pump room (located in the sub-basement
of the Auxiliary Building)
for several
years.
Water has
been leaking from the
seam
between
the top of
the
RHR pump room west wall and the bottom of the Auxiliary Building basement
floor.
The leakage rate is very low, i.e., less than O.l gallon per day;
however,
as
a result of the long term leakage,
hard scale deposits
(several
inches thick) have
formed
on the wall.
The inleakage is currently too small
to represent
any operational
safety concern for the plant.
All potential
sources of the leakage
have not yet been positively identified.
by the licensee.
Ground water appears
to be entering the room; however,
RGSE's
analyses
also indicate the presence
of boric acid and radionuclides
that are also present
in the spent fuel pool.
The licensee is removing the
scale buildup from the area
around the
seam to facilitate better collection of
the water before it flows down the wall.
The inspector will continue to
monitor licensee efforts to quantify the water inleakage rate
and to
positively identify all sources.
(IFI 50-244/95-15-01).
3.0
ENGINEERING (71707,
37551)
3. 1
Pump Rotor Failure and Subsequent
Upgrade
On August 9,
1995, the licensee
performed
a normal biweekly transfer of
operating service water
(SW)
pumps to place the
D-SW pump
(one of four
installed) in service
and to remove the
B-SW pump (both connected
to the
same
power supply).
Approximately 10-15 seconds
after starting the
D-SW pump, the
auxiliary operator stationed
at the
pump noticed
smoke
and flames emanating
from the motor and immediately notified the control
room operators
to secure
the pump.
The
pump was effectively secured,
and the
smoke
and flames at the
motor ceased.
No apparent effects resulted
from this event in other plant
equipment
connected
to the
same
power supply,
and
no apparent
damage resulted
to any equipment located adjacent to the
D-SW pump.
The Ginna technical
specifications
do not require entry into an
LCO action statement after the
loss of one service water pump, or until one complete train of service water
is lost.
By design,
only one service water
pump and train is required for
accident mitigation at Ginna.
The licensee's initial root cause
analysis
indicated that
an internal short
apparently resulted
from excessive
vibration of the motor windings that
degraded
the winding insulation
and caused
localized overheating to spread
through the winding coils.
The overheating eventually cause
an internal short
to ground in the motor.
The incident represented
a near identical electrical
short
and failure of the
D-SW pump motor that occurred approximately
two years
earlier.
In that instance,
a short occurred in nearly the
same location, but
resulted
in a phase-to-phase
motor winding burnout.
Both instances
were
among
a series of service water
pump and motor failures that have occurred at Ginna
over several
years.
The licensee initially intended to return the motor to
the original manufacturer
for an in-depth root cause
analysis
since
a problem was suspected
with the materials
and processes
used the last
two times the motor was rewound
(1993
and 1994).
However, the motor remains
onsite pending
a management
decision to rewind the failed motor or purchase
a
new one.
The licensee
did not have
a spare
motor that was immediately available for
replacement,
and
a search for motors nationwide resulted
in no suitable motors
available in a short time period.
A rewind of the failed motor would have
taken
a few weeks,
and purchase of a new safety-related
motor was expected
to
take several
months.
The licensee
had previously procured
an alternate
replacement
motor that was located in the site warehouse.
However, the motor
was
a commercial
procurement
item intended for installation
and dedication
during the next refueling outage in Harch/April 1996.
The licensee
determined
that the spare
motor could be inspected,
installed,
and dedicated to safety-
related service
as
a replacement for the failed motor.
Since limited test
data that could be validated
was available
from the motor vendor (U.S.
Motors),
and since the
new motor was not identical to the failed motor (350
H.P.
and 460
VAC new vs.
300 H.P.
and 440
VAC old), the licensee initiated
internal engineering
actions to analyze all of the
known new motor
characteristics,
to determine the extent of dedication testing necessary,
and
to perform
10 CFR 50.59 safety evaluations of any plant modifications
necessary
to connect the
new motor to safeguards
bus
17 and perform dedication
testing during plant operations.
The licensee
developed
Plant
Change
Request
95-046
and Design Analysis
DE-EE-95-129-06 to evaluate the potential effects
on installed plant equipment
of the
D-SW pump replacement.
The analysis
reviewed the critical motor
characteristics
such
as the inrush, full load,
and fault currents;
motor
acceleration
time; steady state
and dynamic responses
during safeguards
sequencing;
and degraded
voltage performance
during normal
and accident
conditions.
The analysis
also considered
the effects of the
new motor on the
existing power circuit breaker,
the safeguards
bus
17,
and the
B-EDG under
worst case loading scenarios.
RG&E concluded
hat the
new motor's expected
performance
under accident conditions
was
bounded
by existing safety analyses,
and was based
on thorough analysis that was validated through testing.
The
inspector considered
the analysis to be in-depth,
and comprehensive
in
addressing
concerns
related to the safe installation
and testing of the motor
with the plant at power.
After a seismic analysis
concluded
the
new motor was acceptable
for use, it
was installed
on the
D-SW pump.
Some modifications were
made to the power
cables
and the bearing temperature
instrument wiring.
Complex test
instrumentation
was installed
on the motor to obtain performance
data
and to
permit detailed engineering
analysis of the test results.
Preliminary motor
testing
was performed with the motor uncoupled
from the
D-SW pump in order to
obtain accurate inertial
and torque reaction data,
and to validate the
licensee's
motor performance
model.
The motor was then coupled to the
pump
and tested
under normal operating conditions for an extended
period.
The test
results indicated that the motor performed
more efficiently, drew less
current,
and operated
at
a lower temperature
than the old motor.
The
hydraulic characteristics
of the
D-SW pump were unchanged with the
new motor.
The inspector concluded that the licensee
made
a sound decision to replace the
D-SW pump motor and restore
the
pump to operability in a timely manner through
dedication testing.
The new motor's performance
was thoroughly modeled
and
reviewed, with conservative
engineering
assumptions
and ample consideration
for the existing plant design
and safety evaluations.
3.2
Replacement
Project
The licensee
is planning to replace
both steam generators
(SGs) during the
next refueling outage,
currently scheduled
to begin in March 1996.
A special
Cl
10
crane will be used to move the
SGs into and out of containment
through two
openings that will be made in the containment
dome.
The dome will then
be
restored
and
a full-strength pressure
test of the containment building will be
performed.
The old SGs will be stored
on site in a newly constructed
temporary storage facility.
The inspectors
are monitoring the licensee's
preparations
for SG replacement
and are reviewing the effectiveness
of RG&E's project management
controls,
the
safety evaluations
prepared for the project,
and the engineering
specifications
associated
with the
new SGs.
Hajor construction activities for
the project to date
have included:
~
Installation of the two concrete
foundations for the
SG lift crane
(a
Lampson Transi-Lift crane).
Fabrication of a full-thickness containment
dome mockup.
This structure
is sufficiently large to accommodate
the actual
size
and geometry of one
opening
as it will be made in the containment
dome.
The construction
details of this mockup (steel-reenforced
concrete with a steel liner)
closely simulate the actual
containment
dome.
The mockup will be used
for testing, refining,
and proving excavation
and reconstruction
techniques,
and will also
be used for personnel
training.
Construction of the Old
SG Storage Facility (OSGSF).
Rerouting of various site services
and construction of several
onsite
support facilities.
The
NRR and Region I-based Project Hanagers visited the site to obtain
an
overview of the
SG replacement
project
(SGRP)
and to coordinate
inspection
plans with the
NRC Senior Resident
Inspector.
Discussions
were held with RG&E
and Bechtel
managers,
supervisors,
craftworkers
and quality assurance
personnel
on the project team.
Procedures
and specifications
related to the
project were sampled for review.
Work in progress
and sites of planned work
were observed.
From these discussions,
reviews
and observations, it was found
that the
SGRP is being conducted
by a team of utility and contractor
personnel,
using the experiences
gained through completion of similar
projects,
in preparation of detailed plans
and procedures
to accomplish the
replacement.
The work in progress
showed careful attention to detail; for
example,
the manufacturing of the
new
was being covered
by a full time
licensee quality inspector in residence
at the fabrication plant.
Aspects of the project that were reviewed or observed
included
an overview of
the project, the lifting equipment
(Lampson
and tower cranes),
the containment
dome mockup,
dome cutting plans,
welding training/qualification plans,
the
Lampson crane foundations,
a video/computer-photographic
tour of containment
in the project affected areas,
the measurement
method, controls
on
fabrication,
the
OSGSF,
SG transportation
to the site,
secondary
side water
chemistry, Quality Assurance/Quality
Control involvement, the project library,
and overall project control.
11
The
NRR Project
Manager obtained
and reviewed several
licensee
safety
evaluations
and design criteria, including:
SEV 1019
SEV 1024
SEV 1021
SEV 1025
SEV 1018
BWNT 77-
1235965-01
DC 10034A
Containment Structural Modifications
DRAFT SG Rigging and Handling,
SG Vessel,
Piping,
and Insulation
Temporary Utilities, Services
and Shielding
Facilities Outside Containment
Replacement
Safety Evaluation
Replacement
Design Criteria-
Containment Structural Modifications
The licensee
is required to submit to the
NRC, for review and approval,
any
change that constitutes
an unreviewed safety question or requires
a change
in
technical specifications
(TSs).
During this inspection visit, no unreviewed
safety questions
or required
changes
to TSs were identified. If the
containment
access
is enlarged,
design reviews should
be coordinated with
NRR/ECGB, via the Project Manager,
to confirm the restored
design margin.
If
necessary,
this will be performed
by NRR in the future during the licensee's
structural integrity test
(SIT) and integrated
leak rate test
(ILRT) on the
reconstructed
containment.
No areas of concern
were identified during review of the
SGRP.
The licensee
was well prepared to address
questions
posed during the discussions.
4.0
PLANT SUPPORT
(71750)
4.1
Radiological
Work Controls
and External
Exposure Monitoring in
Radiologically Controlled Areas
During recent
months,
several
incidents
have occurred
where personnel
entering
a radiologically controlled area
(RCA) in the plant did not log into the
licensee's
radiation work permit
(RWP) access
control system,
and/or did not
have the secondary
alarming dosimetry required for entry.
None of the
incidents involved entry without the primary personnel
exposure monitoring
devices
(thermoluminescent
dosimeters);
however, all represented
a failure of
qualified radiation workers to adhere to the procedure
requirements
pertaining
to
RCA access,
RWP work controls,
and possession
of alarming dosimetry.
Three
of the documented
incidents
are described
as follows.
On April 21,
1995, during the last refueling outage,
a qualified radiation
worker entered
the containment
enclosure
(a posted
inspect work on reactor coolant system piping.
Upon exiting the containment
approximately
one hour later,
he realized that
he entered
the containme'nt
without the required
secondary
dosimetry
(ALNOR) and without signing in on the
b0
12
applicable
RWP.
The radiation protection
(RP) technician
on duty subsequently
initiated an action report
(AR 95-082) to investigate
the cause of this
incident and to initiate the appropriate corrective actions.
The worker's
exposure
during the containment entry was temporarily estimated
from the
ALNOR
dosimeter reading
(4 mR) of a coworker who accompanied
him during his entire
stay inside containment.
Subsequent
analysis of the worker's
TLD confirmed
the
4
mR exposure.
RG&E's immediate actions to address
this incident included
temporarily restricting the individual's access
to restricted
areas,
conducting interviews with other individuals in the
same work group, reviewing
the incident with all
RP personnel,
and posting signs at the
RCP access
point
to remind workers of the
RWP and dosimetry requirements for RCA entries.
RGEE's
RP department
reviewed this incident
and concluded that the Technical
Specification
(TS) requirements
(Section 6.13) were satisfied
since the TSs
allow for a group of individuals to use
a single alarming dosimeter inside
a
Also, no work had apparently
been
performed outside .the
restrictions of the applicable
RWP.
However, several
plant procedures
require
that all individuals entering restricted
areas (i.e.,
RCAs) shall log into the
RWP access
control system
and obtain secondary
alarming dosimetry.
Procedure
A-l, "Radiation Control Manual," stipulates
that workers must acknowledge all
RWP requirements
by logging into the access
system
and obtaining
a secondary
dosimeter that must
be worn continuously
by each individual while inside
a
restricted
area.
Also, procedures
A-1.3, "Restricted Area Entry and Exit,"
and A-l.8, "Radiation Work Permits,"
both require worker acknowledgement
of
the radiological controls associated
with their job by logging into the
system
and obtaining alarming dosimetry prior to
RCA entry.
AR 95-082 was
closed in August 1995,
and
recommended
a longer term corrective action to
investigate
a possible link between
the
RWP and security access
systems to
prevent unauthorized
access
to the
RCA.
This was later investigated
by the
licensee,
but was not implemented
because
the two systems
are not physically
compatible.
On June
27,
1995,
an
RP technician discovered that
a qualified radiation
worker had entered
the
RCA to work in the Intermediate Building without his
required dosimetry
(RADOS).
The worker had signed into the
RWP access
system,
indicating he had read,
understood,
and would comply with the
RWP requirements
applicable to his work assignment.
However,
he subsequently
entered
the
without taking the
RADOS dosimeter with him.
After approximately five
minutes,
the
RP technician
on duty noticed his dosimeter still at the access
control desk
and paged the worker to return to the entry point.
The
technician
allowed the worker to return to the
RCA after giving him the
dosimeter,
and counselling
him on the
RWP and procedure
requirements for
possessing
a
RADOS when entering the
RCA.
The
RP technician then initiated an
action report
(AR 95-166) to investigate
the incident
and to pursue corrective
actions.
As of this inspection,
the final disposition of this
AR was not
complete.
On August 3,
1995,
a qualified radiation worker self-identified that
he had
entered
and worked in a high radiation area inside the Auxiliary Building.
After receiving
a pre-job briefing from an
RP technician,
the individual
entered
the high radiation area without his required
RADOS dosimeter.
Prior
to entering the
RCA, the individual had donned anti-contamination clothing,
13
but did not register into the
RWP electronic
access
system.
Upon exiting the
RCA, the individual discovered
his missing dosimeter
and immediately discussed
the situation with RP personnel
and his supervisor.
The worker subsequently
initiated an action report
(AR 95-0240) to investigate
the causes for this
incident and to pursue corrective actions.
RP personnel
were able to estimate
the worker's dose
from the job duration
and the radiation levels in his work
area.
His actual
exposure
was later confirmed by reading his TLD.
As of this
inspection,
the final disposition of AR 95-0240
was not complete.
On August 3,
1995,
RG&E initiated
a Human Performance
Evaluation System
(HPES)
report
(HPES 95-0240) to perform an in-depth root cause
analysis of these
three incidents
and to determine
the necessary
corrective actions to prevent
recurrences.
HPES 95-0240
was not complete
as of this inspection;
however,
the licensee's
detailed
comparison
between the security
and
RWP access
logs
indicated that twenty instances
of per'sonnel
entry into the
RCA actually
occurred without the required
secondary
dosimeter
between
January
1,
1995,
and
August 6,
1995.
Most of these
instances
also involved
a failure to log into
the
RWP system prior to
RCA entry.
The draft HPES indicated that
a turnstile
barrier could be installed to prevent
RCA access
without the necessary
entries
into the
RWP and
RADOS systems.
This initiative is considered
to be
a
positive measure
by the licensee.
However, the final root cause
evaluation
and 95-0240,
and the
HPES are still ongoing.
Although of minor radiological
consequence,
these
incidents represent
a
relatively high occurrence
over
a seven
month period of a lack of adherence
to
procedure
requirements for radiological work controls
and access
to radiation
and high radiation areas.
This item is unresolved
pending
NRC review of the
completed
HPES95-240 report
and the licensee's
implementation of permanent
corrective actions.
(URI 50-244/95-15-02)
5. 0
SAFETY ASSESSMENT/EQUALITY VERIFICATION (71707)
5. 1
Periodic Reports
Periodic reports
submitted
by the licensee
pursuant to Technical Specification 6.9.1 were reviewed.
The inspectors verified that the reports contained
information required
by the
NRC, that test results
and/or supporting
information were consistent
with design predictions
and performance
specifications,
and that reported
information was accurate.
The following
reports
were reviewed:
~
Monthly Operating
Reports for July and August
1995
No unacceptable
conditions were identified.
5.2
Licensee
Event Reports
Two Licensee
Event Reports
(LERs) submitted to the
NRC were reviewed
and the
inspector determined that the details
were clearly reported,
the causes
were
properly identified,
and the corrective actions
were appropriate.
The
inspectors
also determined that the potential safety consequences
were
properly evaluated,
the generic implications were indicated,
events that
14
warranted additional follow-up were identified,
and the licensee
met the
applicable
requirements
of 10 CFR 50.73.
The following LERs were reviewed
(Note: date indicated is event date):
~
95-006,
Loss of 34.5
KV Offsite Power Circuit 751,
Due to Offsite
Lightning Strike, Results
in Automatic Start of "A" Emergency Diesel
Generator
(June
30,
1995)
~
95-007,
Loss of 34.5
KV Offsite. Power Circuit 751,
Due to Offsite
Electrical Storm, Results
in Automatic Start of "B" Emergency Diesel
Generator
(August 3,
1995)
The inspector concluded
the
LERs met regulatory requirements
and appropriately
evaluated
the safety significance of the events.
LERs95-006
and 95-007 are
closed.
6.0
ADMINISTRATIVE
6.1
Senior
NRC Management Site Visits
During this inspection period, three senior
NRC managers visited Ginna
Station.
On August 16-17,
1995, Hr. James
C. Linville, Chief of Reactor
Projects
Branch 3, toured the site
and met with senior licensee
management.
On August 22,
1995, Hr. Thomas T. Hartin, Regional Administrator for NRC
Region
1, toured the site
and met with senior licensee
management.
On August
23-24,
1995, Hr. William J.
Lazarus,
Chief of Reactor Projects
Section
3B,
t'oured the site
and met with senior licensee
management.
6.2
Exit Meetings
At periodic intervals
and at the conclusion of the inspection,
meetings
were
held with senior station
management
to discuss
the scope
and findings of
inspections.
The exit meeting for the current resident
inspection report 50-
244/95-15
was held
on September
11,
1995.