ML17332A922
| ML17332A922 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 09/08/1995 |
| From: | Kropp W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17332A919 | List: |
| References | |
| 50-315-95-09, 50-315-95-9, 50-316-95-09, 50-316-95-9, NUDOCS 9509190067 | |
| Download: ML17332A922 (25) | |
See also: IR 05000315/1995009
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION III
REPORT
NO. "-50-316 95009'0-316
95009
, FACILITY
Donald
C.
Cook Nuclear Generating
Plant
V+
LICENSEE
Company
Donald
C.
Cook Nuclear Generating
Plant
1 Riverside Plaza
Columbus,
OH 43216
DATES
June
20 through August 17,
1995
INSPECTORS
J.
A. Isom, Senior Resident
Inspector
D. J. Hartland,
Resident
Inspector
C.
N. Orsini, Resident
Inspector
D. S. Butler, Reactor Inspector
R. A. Paul,
Reactor
Inspector
APPROVED
BY
W. J.
Kropp, Chief
Reactor Projects
Branch
2A
AREAS
INSPECTED
D te
A routine,
unannounced
inspection of operations,
engineering,
maintenance,
and
plant support
was performed.
Safety
assessment
and quality v'erification
activities were routinely evaluated.
Follow-up inspection
was performed for
non-routine events
and certain previously identified items.
95091900b7
9509i.2
ADQCK 050003i5
8
RESULTS
Assessment
of Performance
Performance within the area of OPERATIONS was poor during this inspection
period
see Section 1.0.
Concerns with regard to procedural
adherence
and
awareness
of plant conditions were evident
as described
in Section
1.0.
Some
of these
events
were either identified by the inspectors,
identified by the
licensee,
or were self-revealing.
Each event
by itself was not significant,
but in the aggregate
represented
a marked decline in operator
performance
over
the last two months.
Recent
NRC administered initial operator licensing
examinations
(Inspection
Report 50-315/OL-95-01(DRS)) identified
a weakness
where
a lack of self-checking
caused
operator candidates
to miss steps
during
procedure
performance
and others to miss irregularities in system responses.
The inspectors
were concerned
that this weakness
was observed
in actual plant
'perations.
A violation for operator failure to follow procedural
requirements,
including
response
to
a decrease 'in condenser
vacuum that resulted in a reactor trip,
was identified.
In addition, the inspectors
noted weaknesses
in operator
awareness
of plant conditions,
including failure to recognize
the over-
energization of the main transformer in a timely manner during
a generator
"
paralleling evolution.
The inspectors
also identified
a violation for failure
to comply with 10 CFR Part 72 reportabilty requirements.
The examples
given
for the events that were not reported all pertained to operator errors. and
represent
a programmatic
weakness
in reportability.
Overall performance
in the area of MAINTENANCE was considered
adequate - see
Section 2.0.
However, there were three instances
where procedures
were not
followed during maintenance
and testing activities.
One pertained to the
testing of an
and one to the exercising of the
(MSSV), both of which were identified by the
inspectors.
The other pertained to repair of a manual
voltage regulator
potentiometer that was self-revealing.
A concern
was also identified
regarding failure to perform adequate
post-maintenance
testing
(PHT) resulting
in a violation.
The three
examples
in the violation were either identified by
the inspectors
or self-revealing,
with the other example the subject of
'inadequate
PHT during
a previous inspection.
The inspectors
were also
concerned that actions
taken
by the licensee
to address
a previous event
failed to prevent the miswiring of the voltage regulator.
Performance within the area of ENGINEERING was adequate - see Section 3.0.
The licensee's initiative to attempt to resolve the
MSSV bonding issue
was
considered
a strength.
However, the licensee
did not address
the issue
regarding the Technical Specification
(TS)-required as-left lift setpoint of
the
MSSVs until prompted
by the inspectors.
The inspectors
were concerned
with the non-conservative
approach
by engineering of not assessing
data
obtained during the exercising of the valves for TS compliance.
Performance within the area of PLANT SUPPORT
was good
see Section 4.0.
One
weakness
was identified concerning
an investigation
by the radiation
protection department.
Summar
of 0 en
Items
Violations: identified in Sections
1. 1, 1.2, 1.3, 2.3,
and 2.5
Unresolved
Items: not identified in this report
Ins ector Follow-u
Items: not identified in this report
Non-cited Violations: not identified in this report
INSPECTION DETAILS
1. 0
OPERATIONS
NRC Inspection
Procedure
71707
was
used in the performance of an inspection of
ongoing plant operations.
Operator
performance with regard to procedural
adherence
and awareness
of plant conditions
was poor as evident
by several
events
described
in the following paragraphs.
Some of these
events
were
either identified by the inspectors,
identified by the licensee,
or were self-
revealing.
Each event
by itself was not significant, but in the aggregate
represented
a marked decline in operator
performance
over the last two months.
A recent
NRC administered initial operator licensing examination
(Inspection
Report 50-315/OL-95-01(DRS)) identified
a weakness
where
a lack of self-
checking
caused
operator candidates
to miss steps
during procedure
performance
and others to miss irregularities in system response.
The inspectors
were
concerned that this weakness
was observed
in actual plant operations.
1. 1
Performance of 0 erations at Power
1. l. 1 Unit
1 Technical
S ecification
TS 3.0.3 Entr
On July 4,
1995, while performing
01-OHP 4030.STP.053B,
"ECCS Valve
Operability Test-Train 'B," the reactor operator
missed
step 1.8. l.e., which
required that
RHR discharge crosstie
valves
1-IMO-314 and 1-IMO-324 be opened.
This step
was required to maintain four loop safety injection capability while
the "S" SI
pump discharge crosstie valve, l-IM0-275, was being cycled.
Upon
identifying the discrepancy,
the licensee initially determined that
had
been entered
during the short time that
IMO-275 was closed.
However,
upon
further review as part of the investigation into the event,
the licensee
concluded that
was not actually entered
and that the event
was not
reportable.
The inspectors'eview
of the reportability determination is
discussed
in paragraph
1.3.
1. 1.2 Unit
Low Vacuum Tri
On July 14,
1995, the Unit
1 reactor tripped due to loss of condenser
vacuum.
The licensee
determined that the cause of the loss of vacuum was the fatigue
failure of a 1" main steam
dump valve condensate
drain line.
All safety
systems
functioned
as required.
The operators
became
aware of decreasing
vacuum approximately
10 minutes
before the turbine trip when
a condenser
"A" high hotwell level alarm, closely
followed by a low hotwell level alarm,
was received in the control
room.
About three minutes later, the operators
received
vacuum
low" alarm which was
common to all three condensers.
Since the operators
were
not immediately able to determine
the cause for the decreasing
vacuum,
an
attempt
was
made to place the start-up air ejectors
("hoggers") in service to
try to regain
some
vacuum.
However, the operators
encountered
a delay in
placing the hoggers
in service
due to the need to locally close
a valve which
was
open to drain condensate
build-up in the steam
header to the hoggers.
The
condensate
build-up was due to leakby past the steam supply valve,
SM0-400.
4
The unit tripped about
8 minutes after the low condenser
vacuum alarm was
received,
before the operators
were able to place the hoggers
in service.
The inspectors
identified some concerns
regarding operator action taken prior
to the trip.
The inspectors
noted that step 3. 1 of the annunciator
response
procedure,
Ol-OHP 4024. 118 (drop 71), stated to "reduce turbine load as
rapidly as possible".
A note in the procedure
stated that step
1 and step
2
(investigate
the cause for the decreasing
vacuum)
could
be done concurrently.
The operators
decided
not to reduce
load due to the rate at which vacuum was
decreasing
based
on the belief that there would be limited benefit from
reducing load
and operator resources
should
be used to investigate
the
problem.
Licensee's
management
position was that concurrent did not mean at
the
same time but rather the operator
has
a choice of what step to perform.
Licensee
management
stated that the operators
met management's
expectations
in
the response
to the loss of vacuum.
However, the inspectors
concluded that
the operators
decision not to reduce
power was non-conservative
because
a
reduction would have
increased
the margin of safety if complications
had
occurred following the reactor trip.
The operators'ailure
to follow the
procedure to decrease
load rapidly is considered
an example of a
violation of TS 6.8. 1.(50-315/95009-01a(DRP)).
In addition, the inspectors
also concluded that, with vacuum decreasing
at
an
excessive
rate,
the operators
should
have manually tripped the reactor to
avoid challenging the automatic trip function.
The inspectors
noted that
an
error existed in procedure
Ol-OHP 4021.050.001
because
the procedure
required the reactor
be manually tripped only if vacuum could not be
maintained
above 21.6", which was below the automatic trip setpoint of 21.8".
1.2
Performance of 0 erations
While Shut
Down
1.2. 1 Hain Generator
Parallel
0 eration
While the unit was in Node 3, the licensee
repaired the drain line and
performed several
other. corrective maintenance activities, including repair of
the main generator
manual
voltage regulator.
On July 16,
1995, while
attempting to parallel
the main generator
during unit restart,
the operators
. inadvertently applied excessive
voltage to the Unit
1 main generator
and the
Unit
1 main output transformer.
The inspectors
determined that the operators failed to perform step 4.3. 15 of
procedure
Ol-OHP 4021.050.001,
"Turbine Generator
Normal Startup
and
Operation," which required that the generator
core monitor be placed into
service per attachment
1 before closing the exciter breaker
(step 4.4.4).
Shortly after closing the exciter field control breaker the operators
received
some unexpected
including
a
generator internals overheated"
alarm.
Because
the operators
had not yet completed
step 4.3. 15 (placing the
generator
core monitor in service),
the operators
did not respond to the valid
"generator internals overheated"
alarm.
The operators'ailure
to follow
procedure
01-OHP 4021.050.001
to place the main generator
core monitor in
service is considered
another
example of a violation of TS 6.8. 1.
(50-315/95009-01b(DRP)).
About
a minute or two later, the operators
received
gas
relay operated
or hydrogen concentration
high" alarm,
which was symptomatic of
overheating/breakdown
of the transformer cooling oil.
At that point, the
operators
identified that the generator
output voltage
was excessively
high at
approximately
146 volts, well above the expected
value of 106 volts with the
manual voltage regulator adjusted to the minimum position.
After
unsuccessfully
attempting to lower the voltage with the regulator,
the
operators
opened
the exciter breaker.
The operators
then confirmed the high
hydrogen concentration
at
a local panel.
The overvoltage condition for the
Unit
1 main generator
and the main transformer
existed for approximately
5
minutes.
The licensee
determined that the cause of the over-energization
of
the transformer
was incorrectly landed leads
associated
with the manual
voltage regulator that was worked during the forced outage.
This issue is
discussed
further in paragraph
2.0.
Based
on the following, the inspectors
concluded that the operator
performance'uring
the generator parallel operation
was poor because
the over-excitation
of the main generator
was not recognized
in a timely manner:
Paragraph
4.4.5 of 01-OHP 4021.050.001
required that the operators
verify that all three
phases
were energized
on the generator
voltage
meter following closure of the exciter output breaker.
Although no
acceptance
criteria was given for output voltage in the procedural
step,
the operators
had the opportunity at that point to recognize that the
value was outside the normal operating
range.
The operators
did not ensure that the main generator
core monitor was
placed in service prior to closing the exciter field breake'r.
The inspectors
had previously identified concerns
regarding operator
performance
during generator parallel operations
in inspection report
50-315/94022;
50-316/94022.
In response
to this event,
the licensee
updated
Ol-OHP 4021.050.001
to include
acceptance criteria for the generator
output voltage
upon closure of the
exciter output breaker.
In addition, the licensee clarified the procedure to
ensure that the core monitor would be operational prior to closing the
breaker.
The licensee
performed
an internal inspection of the accessible
portions of
the main transformer
and generator
and did not discover
any damage.
However,
on July 27, the licensee
re-energized
the transformer
and
a high hydrogen
concentration
developed
in the transformer cooling oil due to apparent
damage
'in a portion of the transformer that was not accessible
during the inspection.
Due to the extended
outage required for replacement
of the transformer,
the
licensee
elected to enter the refueling outage approximately six weeks prior
to the scheduled
date.
The licensee
had the unit in Mode
5 at the end of the
inspection period.
~
~
1.2.2 Auto Start of Turbine Driven Auxiliar
Pum
On July 28,
1995, the licensee
removed the reserve
feed transformer
from
service for maintenance
to correct
a "hot spot" identified during thermography
inspections.
In order to perform this evolution with Unit
1 shutdown,
the
licensee
revised
Procedure
- 01-OHP 4021.082.001,
"4KV Buses
Power Source
Transfer
and De-energizing
a Safeguards
Bus." This revision described
the
method to parallel
an emergency diesel
generator
(EDG) to a safety bus,
load
the
EDG,
and
open the tie-breakers
between
the related reactor coolant
pump
(RCP)
buses
and the safety bus.
During the initial planning of this evolution, the licensee
discussed
that the
turbine-driven auxiliary feedwater
(TDAFW) pump would receive
an autostart
signal
when two of the four RCP buses
were de-energized,
and that the
possibility existed for the under-frequency
relays to cause
the remaining two
RCPs to trip.
Neither of these
issues
was incorporated into the procedure,
and the pre-job briefing in the control
room did not include
a discussion
regarding the
TDAFW pump auto start.
The
TDAFW pump autostarted
at 3:38 p.m.
when breaker
T1181
was opened,
de-
energizing the second
RCP bus.
The operators realizing why the
pump started,
manually tripped the
pump
and declared it inoperable.
The
TDAFW pump was
reset
and declared
operable at 11: 18 p.m., after the reserve
transformer
maintenance
was
completed.'he
inspectors
had the following concerns with the performance of this
evolution:
The inspectors
determined that the autostart of the
TDAFW pump was
an
ESF actuation that was not indicated
by a procedural
step nor were the
control
room personnel
aware of the specific signal
before its
occurrence.
This concerned
the inspectors
because
the operators
did not
evaluate
the ramifications of deenergizing two'f the
RCP busses
and the
subsequent
initiation of the
ESF signal.
The inspectors
al,so
had
some concerns
regarding the licensee's
justification that the
ESF actuation
was not reportable.
This issue is
discussed
in paragraph
1.3.
~
At approximately
2100, the shift technical
advisor identified that
conditions
1
and
2 were
no longer satisfied for TS 3.0.5 for the West
MDAFW pump because its normal
power source
(reserve
feed)
was not
available
and its redundant
component
(the
TDAFW pump)
was inoperable.
This would have given the licensee
8 hrs.
from 3:38 p.m. to have the
plant in Mode 4.. The shift did not take action to cooldown the plant
because
the reserve
feed
was expected to be returned to service prior to
the 8 hrs expiring.
However, this
LCO entry was not logged in the
control
room log book after being identified.
The licensee
has
'nitiated
condition report No.
1107 to determine
why the planning
process
did not identify this
LCO.
The inspectors'ere
also concerned that since the
TDAFW pump autostart
and the possibili.ty of the under-frequency
relays actuating
were not
documented
in the procedure,
the evolution could be performed in the
future without these
issues
being considered.
1.2.3 Erroneous
0 eration of Containment Ventilation
On July 29,
1995, with Unit
1 in Mode 3,
a licensee
reactor operator performed
the wrong attachment of Ol-OHP 4021.028.005,
"Operation of the Containment
Purge System."
The pro'cedure
required that the system
be operated
in the
"clean-up"
mode when containment integrity was required
(Modes 1-4 per
TS 3.6. 1. 1). However, the operator erroneously
operated
the system in the
"ventilation" mode of service for approximately
5 minutes.
The significance
appeared
to be that the vent stack radiation monitor was not source
checked
and
a release
permit was not forwarded to Radiation Protection.
The licensee
initiated
a condition report for this event.
1.2.4 Unit
1 Cooldown
On July 30,
1995, while cooling down Unit
1 in Mode 4,
a licensee unit
supervisor did not follow the required
sequence
of steps
in procedure
Ol-OHP
4021.001.004,
"Plant Cooldown
From Hot Standby to Cold Shutdown," for
establishing
Low Temperature
and Operating
Pressure
(LTOP) protection
and
prematurely racked out
a
CCP pump.
The consequence
was that the licensee
made
an unidentified entry into TS 3. 1.2.4,
which required
two operable
CCPs in
Mode 4, for over
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> before being discovered
by shift management.
The
licensee initiated
a condition report for this event.
1.2.5 Inadvertent Drainin
S stem
On August 4,
1995, after isolating
a seal injection filter for maintenance
and
attempting to drain the header,
an auxiliary equipment operator
(AEO) observed
excessive
water coming 'from an open vent valve due to the apparent
leakby of a
clearance
isolation valve.
In response,
the
AEO closed the vent valve and
went to the control
room to report the problem.
However, the
AEO left another
valve that was also
used to drain the system in the open position.
Approximately
15 minutes after the drain valve had
been left opened,
control
room operators
noticed that pressurizer
level
had decreased
from about
12
percent to 5 percent,
or about
1500 gallons.
The water had drained to
a
tank.
The operators
immediately initiated
RCS make-up
and the drain valve was
closed.
The licensee initiated
a condition report for this event.
1.3
Followu
on Previousl
Identified Items
A review of a previously opened
unresolved
item was performed
per
NRC
Inspection
Procedure
92901.
This item was closed
based
on
a violation being
identified regarding the failure of the licensee to report events
as required
by 10 CFR Part 72.
Closed
Unresolved
Item 50-316 94024-01:
The inspectors initiated this item
in response
to
a concern regarding the licensee's justification for
classifying events
as not reportable.
During the inspection period,
the
inspectors
identified the following events that should
have also
been reported
to the
NRC:
An example identified as part of the unresolved
item involved an
unintended
entry into TS 3.0.3
on April 2,
1994,
due to the inoperabilty
of both trains of Unit 2 engineered
safety feature
exhaust
(AES) fans.
The function of the
AES fans
was to provide cooling for ECCS equipment
and to ensure that radioactive material leaking from equipment following
a
LOCA is filtered prior to reaching the environment.
The licensee
had
placed the control switch for the 2-HV-AES-2 fan in the "stop" position
after starting the 2-HV-AES-1 fan for post-maintenance
testing
(PNT),
thus making both fans inoperable.
The licensee
had taken the AES-1 fan
out-of-service for replacement
of a
HEPA filter.
The licensee
concluded
that since the
PHT on AES-1 fan was successfully
completed,
the event
was not reportable
because
the AES-1 fan was capable of performing its
intended function at the time AES-2 was stopped.
The inspectors
concluded that the licensee's justification, which was
based
on
retroactively applying the successful
completion of testing,
was in
error.
Therefore,
the inspectors
concluded that the event
was
reportable
per
paragraph (b)(1)(ii)(B), as
a condition
outside the design basis of the plant.
On October
10,
1994, during performance of STP 205,
"ESF Time Response
Testing-Train A," the licensee
received
an unexpected
phase
"A"
isolation of the containment
purge system.
As part of the preparatory
steps of the surveillance testing,
the operators
had removed the 'purge
system
and closed the containment isolation valves to prevent automatic
isolation during the testing.
However,
due to poor communication,
an
operator placed the purge system
back in service before the test
was
initiated.
As
a result,
the operators
experienced
the phase
"A"
isolation signal,
which resulted
in the isolation of the containment
purge isolation valves.
The phase
"A" containment isolation signal
was
listed in paragraph
3.a of Table 3.3-3 of TS as part of the
actuation
system instrumentation,
and
was not an expected result of the
procedure.
Therefore,
the inspectors
concluded that the event
was
reportable
per
10 CFR 50.72 paragraph (b)(2)(ii)(A).
As discussed
in paragraph
1. 1 of this report, the licensee initially
determined that
was entered
on July 4,
1995,
due to loss of
four loop safety injection capability.
The licensee
determined that
a
one hour phone call per
was not required
because
manual
four loop injection was available.
In addition,
upon further review of
the event,
as documented
in condition report
(CR) 95-1107,
the licensee
performed
an analysis that demonstrated
that the plant was not in an
unanalyzed
condition that significantly compromised plant safety.
This
conclusion
was
based
on the unit being at
a reduced
power level at the
time (57 percent);
therefore,
UFSAR acceptance
criteria for the
accidents
impacted would continue to be me't.
The inspectors
reviewed the licensee's justification.
The inspectors
noted that the licensee
could not take credit for operator action for
establishing
four loop injection.
In addition,
since the currently
docketed
design
bases
and accident
analyses
approved
by the
NRC does not
recognize
two loop injection for both the
an unanalyzed
condition did exist
and entry into TS 3.0.3
was appropriate.
An
analysis after the event
was not justification for not submitting
an
LER, but rather
an analysis to ascertain
the safety significance of the
event.
Therefore,
the inspectors
determined that the event
was
reportable
as
a condition outside the design
basis of the plant
as
required
~
As discussed
in paragraph
1.2.2
above,
on July 28,
1995, the licensee
experienced
an automatic start of the Unit
1
TDAFW pump while performing
a power source transfer.
The
pump autostart
was
due to reactor coolant
pump bus undervoltage.
This feature
was listed in paragraph
7.b of TS
Table 3.3-3
" Engineered
Safety Feature Actuation System
Instrumentation"
as part of the
ESF actuation
system instrumentation.
The licensee initially concluded that the event
was not reportable
as
an
ESF actuation
because
some individuals discussed this feature during the
initial planning
phase of the evolution.
However, the inspectors
noted
that the actuation
was not addressed
in the procedure
and
was not
expected
by the operators.
The licensee's
procedure that defines the
reportability process,
PHP 7030.001.001,
"Prompt
NRC Notification",
states that
a trip actuation
should not be
a surprise to the operator to
be not reportable.
Therefore the inspectors
concluded that the event
was reportable
per
10 CFR 50.72 paragraph
(b)(2)(ii)(A) because
the
TDAFW pump is an
as defined in TS and the auto start
was not
preplanned
(documented
in a procedure
or logged prior to actuation).
The licensee's
failure to report the above four events is considered
a
violation of 10 CFR 50.72.(50-315/95009-02(DRP)).
2. 0
MAINTENANCE
NRC Inspection
Procedures
62703
and 61726,
and 92902 were used to perform an
inspection of maintenance
and testing activities.
Overall performance in'his
area
was considered
adequate.
However, there were three instances
where
procedures
were not followed during maintenance
and testing activities.
One
pertained to the testing of an
one to the
exercising of the main steam safety valves,
both of which were identified by
the inspectors,
and the other pertained to repair of a manual voltage
regulator potentiometer that was self-revealing.
A concern
was also
identified regarding failure to perform adequate
post-maintenance
testing
(PHT) resulting in a violation.
Of the three
examples
in the violation, one
was identified by the inspectors,
one
was self-revealing,
and the other was
an
example of inadequate
PHT during
a previous inspection.
The inspectors
were
also concerned that actions
taken
by the licensee to address
a previous event
failed to prevent the miswiring of the voltage regulator.
10
Maintenance
and Surveillance Testin
Activities
The inspectors, observed
routine preventive
and corrective maintenance
and
surveillance activities to ascertain
that they were conducted
in accordance
with approved
procedures,
regulatory guides,
industry codes or standards,
and
in conformance with Technical Specifications.
The following activities were
observed
and/or reviewed:
~
JO¹ C0030956,
"Repair Water Leak on 12-ZRV-404-RV"
~
JO¹ C0031204,
"Adjust 12-ZRV-404-RV For 165 Psig"
~
JO¹ C0031146,
"2-(T-502-AB, Replace
Turbo Rotating Assembly"
~
JO¹ C0025062,
"Adjust Limit Switches
on Hain Generator
Voltage
Regulator"
~
12 THP 6040
PER. 106,
"Emergency Diesel
Generator
Control
Panel
Tests"
~
JO¹ C24371, Unit 2
CD EDG, "Replace
Woodward Governor"
~
Ol
EHP 4030 STP.217A,
"CD
EDG Load Shedding
& Performance
Test"
~
02
OHP 4030
STP. 103,'Hain Turbine Stop
& Control Valve Testing"
~
01
OHP 4030
STP. 19F,
Stop Valve Operability Test"
~
12 EHP.6040.PER. 141,
"Main Steam Safety Valve Exercising Using AVK
ULTRASTAR Equipment,"
~
12 EHP4030STP.256,
"Hain Steam Safety Valve Setpoint Verification,"
2.2
Miswired Volta e'Re ulator
The licensee
established
a team to investigate
the root causes
of the main
generator over-excitation
event discussed
in paragraph
1.2.
Although the
investigation
has not been completed,
the licensee
has determined that the
cause for the event
was improperly landed leads
on the manual
voltage
regulator potentiometer that was replaced
during the forced outage.
The
miswiring caused
the regulator to be at maximum voltage regardless
of the
potentiometer setting.
In addition to the wiring error, licensee
personnel
failed to perform adequate
post-maintenance
testing
(PHT) following the maintenance activity.
The
original scope of the work on the regulator
was to adjust the limit switches
for the maximum and minimum voltage light circuits.
While performing the
activity, the
I&C technicians
damaged
the potentiometer,
expanding the scope
of the job.
Due to poor communication,
lack of understanding
of system
operation,
and perceived
urgency to complete the work, the original
PHT, which
consisted of verifying proper operation of the light circuits,
was not updated
to ensure
the regulator would work properly following the potentiometer
replacement.
The inspectors'oncern
regarding the inadequate
PMT is discussed
in paragraph
~2.5 below.
The inspectors
had several
concerns
regarding this event.
The licensee
had
experienced
a similar event in March 1993,
when
an
EDG load conservation
relay
was improperly wired following a calibration activity during
a refueling
outage,
which would have rendered
the function inoperable.
Fortuitously, the
licensee identified the miswiring during blackout testing,
which was not
specifically performed
as
a
PMT after the work on the'DG load conservation
relay,
but before the
EDG was declared
As action to prevent recurrence
of that event,
the licensee
reinforced the
use'f
self-checking
and verification methods
appropriate
to the consequences
of
improperly performing the activity.
The licensee
also committed to compare
restored wiring configurations with approved
drawings to ensure final
configuration agreed with design.
This comparison
was not performed following
the potentiometer
replacement.
The inspectors
also noted that the form used
to document the verification of leads lifted and landed for the regulator work
activity did not include the potentiometer
Therefore,
the technicians
had to use
a hand-drawn
sketch,
and there were
no signoffs for verification of
lifting and landing these
2.3
Exercisin
of Main Steam Safet
Valves
While exercising the
MSSVs per procedure
12 EHP.6040.PER. 141,
Safety Valve Exercising Using AVK ULTRASTAR Equipment,"
MSSV 1-SV-3-2, which
had
a setpoint of 1085 psig, the equivalent of 1180 psig was applied without
the valve lifting.
The test
was stopped to confer with the valve vendor to
determine if more force could be applied without damaging the valve.
Procedure
12 EHP.6040.PER. 141, step
5. 17 stated that in the event that
a valve
cannot
be exercised,
stop testing immediately and notify the shift supervisor
(SS).
The
and control
room operators
were not informed that testing
had
stopped
because
1-SV-3-2 would not lift.
The inspectors felt that,
although
1-SV-3-2 was already considered
operations
personnel
should
have
been
informed of the status of 1-SV-3-2 and the plans to apply more force on
the valve.
The failure to notify the
SS is considered
an example of a
violation of Technical Specification 6.8. 1 (50-315/95009-Olc(DRP)).
This
activity is discussed
in further detail in paragraph
3.2 of this report.
2.4
Missed Procedural
Ste
s
On June
22,
1995, during performance of an engineering test,
12 THP 6040
PER. 106,
"Emergency Diesel
Generator
Control
Panel Tests,"
the inspectors
observed that the operators
inadvertently skipped
some procedural
step's.
The
objective of the procedure
was to provide
a record of adjustments
made to the
voltage
and speed
following replacement
of the. Unit 2 "CD"
emergency diesel
generator
(EDG) governor.
Redundant
were
located in the control
room and at the
EDG local control panel.
12
Following adjustment of the control
room potentiometers
per paragraph
6.2 of
procedure
12 THP 6040
PER. 106, the operators
shut
down the
EDG to perform the
steps
required for making the local panel
adjustments.
However, the control
room operators
restarted
the
EDG before the remote-local
switch located at the
EDG sub-panel
was placed in the local position,
as required
by paragraph
6.3. 1
of 12
THP 6040
PER. 106.
Paragraph
6.3. 1 was required to be performed in order
to demonstrate
the capability of starting the
EDG locally, which was
an
acceptance
criterion in the procedure.
The cause for the missed
step
was due
to apparent
miscommunication
between
the operators
and the test engineer
coordinating the evolution.
Upon realizing the step
had
been missed,
the engineer
decided to continue with
the procedure
and evaluate
the
need to perform the missed
step afterwards.
However,
because
of the problems
found with the potentiometer
at the local
control panel,
the operators
shutdown the Unit I "CD"
EDG and the engineers
were not able to complete the test.
After making minor adjustments
to the
the licensee
then satisfactorily performed the
"Emergency
Diesel
Generator
Control
Panel
Tests" during
a subsequent
EDG maintenance
run.
The inspectors
discussed
the event with the engineer,
who initially indicated
that the missed
step
was not
a procedural
adherence
issue.
The engineer
based
this determination
on paragraph
3.3 of the procedure,
which stated that test
steps
could
be completed
out. of order if the
EDG was already running.
However, the inspectors
concluded that the statement
did not apply to the
situation,
as the
EDG was not running at the time.
In response
to the
inspectors'oncerns,
the licensee initiated
CR No. 95-0965 to document the
missed step.
The inspectors will review the licensee's
investigation into the
event
and continue to monitor licensee
performance
in this area.
2.5
Follow-u
on Previousl
0 ened
Items
A review of a previously opened
unresolved
item was performed per Inspection
Procedure
92902.
Closed
Unresolved
Item 50-315 94014-06
The inspectors
had previously
documented
an issue regarding
PHT for non-routine corrective maintenance.
The
inspectors
were concerned that work planners
did not always
have
an adequate
background in system operation to ensure that appropriate
PHT would be
performed.
In response
to the inspectors
concern
and other related
events,
the licensee
issued
procedure
PHSO. 154,
"Planning of Post Maintenance Testing
Activities," which outlined the circumstances
when planners
should request
engineering
review of job orders for PNT.
The inspectors initiated the
unresolved
item to monitor the effectiveness
of the
PHSO.
The inspectors
noted three
examples of inadequate
PNT during the inspection
period..
~
The inspectors
noted that despite the apparent unfamiliarity of system
operation
by the planner involved with the voltage regulator maintenance
13
0
discussed
in paragraph'.
1 above,
no engineering
review of the job order
was requested
after the scope of the work was expanded
to replace
the
On July 18,
1995, the licensee
performed
an activity to repair
a leak on
the controller associated
with valve 12-ZRV-404,
"West" Diesel
Driven
Fire
Pump back pressure
regulating valve.
The valve was located
on
a
recirculation line back to the fire water storage
tanks
and functioned
to maintain
165 psi header
pressure
under load.
The
PHT specified
by
the planner in JO C0030956
was to verify no leaks at normal
system
pressure.
However,
when Operations
operated
the
pump per
12-OHP 4030.STP. 121FD,
"Diesel Fire
Pump Operability Test," during the
PHT, it was observed
that the
pump only developed
120 psi discharge
pressure.
Although the
procedure
and the work order did not contain
any acceptance criteria
for'he
discharge
pressure,
the operators
questioned
the operability of the
pump.
The operators
contacted
the system engineer,
who initially
determined that the condition
was not
an operabil.ity issue.
On the
following day, the engineer
reconsidered
his position.
The licensee
subsequently
determined that the regulator
was
damaged
during the work
activity and initiated action to replace it.
The unresolved
item had
been initiated when the inspectors
identified
a
similar concern regarding
PHT of the pressure
regulating valve
associated
with the motor-driven fire pump,
12-ZRV-402.
At that time,
the inspectors
were concerned that,
although the setpoint of the valve
was adjusted to 165 psi, the
PHT did not demonstrate
the backpressure
regulating function of the valve to maintain header
pressure.
On August 2,
1995, after the licensee
completed
maintenance
on the
"AB"
emergency diesel
generator
the resident
inspectors
raised
a concern regarding the adequacy. of the
PHT performed.
The licensee
performed the maintenance
in response
to a recent failure
of a similarly designed
at another plant.
The failure was
attributed to
a design
change.to
an insert that provided starting air to
the turbocharger
during initial roll-up to assist
in getting it up to
operating
speed.
The
new insert caused
the compressor
impeller blades
to reach
resonance
frequency at normal turbocharger
operating
speed,
resulting in excessive vibration and fatigue failure of the blades.
During the maintenance activity, the licensee
replaced
the insert with
the design previously used
and inspected
the impeller blades for damage.
The licensee's
PHT consisted
of a slow start
and full load run.
The
inspectors
determined that the test
was inadequate
because
starting air
was not provided to the insert during
a slow start; therefore,
the
licensee did not verify that the turbocharger
would perform its intended
function under
an accident condition.
The inspectors
noted that during
a slow start,
the
EDGs would not typically roll up to normal
speed until
30 seconds after the
EDG was started.
On an auto start signal,
the
would be required to get
up to full speed within 10 seconds
and begin
accepting
sequenced
loading.
In response
to the inspectors'oncern,
the licensee
successfully
completed
a fast start
and run.
The above instances
are considered
examples of a failure to perform adequate
PMT and considered
a violation of 10 CFR Part 50, Criterion XI (50-315/95009-
'3(DRP)).
This unresolved
item is closed
based
on the issuance
of this
violation.
3. 0
ENGINEERING
NRC Inspection
Procedure
37551
was
used to perform an onsite inspection of the
engineering function.
Items closed
as
a result of this inspection
met the
criteria established
in the Inspection
Procedures.
Although the initiative to
attempt to resolve the
MSSV bonding issue described
in paragraph
2.4 was
considered
a strength,
the engineering
personnel
did not address
the Technical
Specification
(TS)-required as-left lift setpoint
issue until prompted
by the
'nspectors.
The inspectors
were concerned with the non-conservative
approach
by engineering of not assessing
data obtained during the exercising of the
valves for TS compliance.
3. 1
Follow-u
on Non-Routine
Events
NRC Inspection
Procedure
92700
was
used to perform
a review of the following
written report
on
a non-ro'utine event:
Closed
LER 50-315
94001
and
LER 50-316 94006:
The
LERs were written
concerning
MSSVs lifting outside the required tolerances.
The
LERs are closed
and resolution of this issue will be tracked
under Inspection
followup Item 50-315/94002-05;
50-316/94002-05(DRP)
as discussed
below.
3.2
Follow-u
on Previousl
.0 ened
Items
A review of the follow'ing previously opened
unresolved
and inspection followup
items
was performed per Inspection
Procedure
92902.
0 en
Ins ection Foll owu
Item
50-315 94002-05
50-316 94002-05
As discussed
in previous
NRC Inspection
Report
Nos. 50-315/94002;
50-
316/94002(DRP),
50-315/93019;
50-316/93019(DRP),and
50-315/92009;
50-
316/92009(DRP),
the licensee
has
had historical
problems with main steam
safety valves
(MSSVs) lifting at pressures
above the setpoint.
The licensee
believes that bonding between the valve disc
and nozzle
may be causing the
setpoint drift.
This theory was supported
by the fact that generally the
MSSVs which lift above the setpoint
on the initial test will lift at lower
pressures
on subsequent
tests without adjustment.
In response
to this issue the licensee
developed
procedure
12
EHP.6040.PER. 141,
"Main Steam Safety Valve Exercising Using AVK ULTRASTAR
Equipment," to exercise
the
MSSVs during power operation.
The purpose of this
evolution was to determine if bonding
was time dependent
(Unit
1 was
12 months
15
into a cycle,
and
MSSV testing is normally performed at the
end of an
18 month
cycle)
and if so, to determine
the proper interval for future exercising to
prevent bonding.
The licensee's
initiative to attempt to resolve this industry wide issue
was
considered
a strength.
However the inspectors
had
some concerns with the
licensee's
implementation.
On June
19,
1995, with the unit at approximately
55 percent
power, the
licensee
began exercising
the Unit
1 MSSVs.
The inspectors
identified the
following concerns:
~
While testing
MSSV 1-SV-3-2, which had
a setpoint of 1085 psig, the
equivalent of 1180 psig was applied without the valve lifting.
The test
was stopped to confer with the valve vendor to determine if more force
could
be applied without damaging the valve.
Procedure
12
EHP.6040.PER.141,
step 5. 17 states
that in the event that
a valve cannot
be exercised,
stop testing
immediately
and notify .the Shift Supervisor
(SS).
The
and control
room operators
were not informed that testing
had stopped
because
1-SV-3-2 would not lift.
The inspectors felt that,
although
1-SV-3-2 was already considered
operations
personnel
should
have
been
informed of the status of 1-SV-3-2 and the
plans to apply more force on the valve.
On the subsequent lift attempt,
the valve lifted at approximately
1179 psig,
and
was returned to
service.
TS 3.7. 1. 1 requir'es that
a safety valve shall
be reset to the nominal
value a
1 percent
whenever
found outside the a
1 percent tolerance.
After 10 of the
20
MSSVs were exercised,
the inspectors
questioned
why
valves found outside the a
1 percent tolerance
were not being reset.
Initially the licensee
responded
that actual lift pressures
were not
required to be recorded
by procedure
12
EHP 6040.PER. 141
and therefore
TS 3.7. 1. 1 did not apply.
However,
although lift pressures
were not
being recorded,
the pressures
were displayed
and saved
by the testing
equipment.
Also, knowing the pressure
at which the valve lifted was
essential
to the purpose of this evolution.
Without knowing the actual
lift pressure,
the licensee
would not be able to determine if bonding
forces were present during the initial lift, nor ensure that the bonding
forces were relieved during subsequent lifts.
After further discussion,
the licensee
determined that
TS 3.7. 1. 1
applied whether or not the data
was required to be recorded.
The
licensee
then tested all Unit
1
MSSVs according to procedure
12
EHP4030STP.256,
",Main Steam Safety Valve Setpoint Verification," which
required all valves to be left within a
1 percent of the nominal
setpoint.
This approach
to testing
MSSVs did not demonstrate
a
conservative
approach
to TS surveillance
requirements.
This inspection followup item will remain
open pending the final determination
by the licensee of the. cause
and actions
necessary
to prevent the
MSSVs from
lifting above the setpoint.
I
16
Closed
Unresolved
Item
315 316 92003-04 DRS:
The Electrical Distribution
System Functional
Inspection
(EDSFI) team
was concerned
that the safety-
related electrical
buses
could decrease
to 79 percent of rated voltage
and set
at this value for 2 minutes until initiation of the degraded
voltage logic.
In response,
the licensee
provided the inspectors
the "D.C.Cook Voltage
Performance
Study,
1991-1995 Operating Period" system voltage analysis.
The
analysis indicated that the low and medium voltage safety-related
buses
would
not decrease
below 90 percent of rated voltage during the worst case
transmission
system contingency.
Safety-related
motors were designed
to start
at 80 percent of rated voltage
and were capable of operating within a voltage
range of a 10 percent.
The
2 minute time delay was selected
to provide
sufficient time to start
pump.
This time delay was accepted
by the
NRC in the June
1,
1981, safety evaluation,
"Adequacy of Station
Electric Distribution System Voltages," that was issued to D.C.Cook.
The
inspectors
concluded
the licensee
was operating electrical
equipment within
the design basis.
This item is considered
closed.
Closed
Unresolved
Item
315 316 92003-06
The
EDSFI team identified
that
250 Vac rated fuses
were
used in
DC applications.
The team was concerned
that the licensee's
evaluation,
"Analysis of D.C.Cook 250 Vdc System
Compared
to UL198L Test Results," did not substantiate
that
AC rated fuses
could be
used in
DC circuits.
In response,
the licensee
re-evaluated
the analysis
and issued calculation
No.
PS-FUSE-001,
"AC Rated
Fuses
in
DC Applications."
The calculation
showed that
the stored
energy dissipated
in TR-R fuses during
DC fault current
interruptions
were
bounded
by the fuse manufacturer's
stored energy test
values.
The inspectors
concluded that 30A and
100A TR-R current-limiting
fuses
would interrupt
a
DC circuit fault and limit the let-thru current to
a
value that would not damage
equipment.
This item is considered
closed.
0 en
Ins ection Followu
Item
315 94002-13 DRP:
In late September
1993,
Unit
1 operators
received
a low oil level alarm to the No.
pump
(RCP) motor lower radial bearing.
The low oil condition eventually led
to damage to the lower radial bearing.
Based
on this event,
the inspectors
had additional
questions
on the causes
for the low oil condition.
On July 21,
1995, Unit 2 operators
received
a similar low oil level alarm on
the
No.
23
RCP.
The lower radial bearing temperature
appeared
stable during
the remainder of the inspection period.
The lower radial bearing temperature
indicated
about
132 degrees
Fahrenheit
and was in the observed
temperature
range for the other three
RCPs with normal oil levels.
The operators
continued to monitor the
No.
23
RCP bearing temperature.
Based
on the fai'lure observed with the Unit
1 No.
14
RCP, the system engineer
estimated that the No.
23
RCP could experience
a lower radial bearing failure
as early as October or November of 1995.
At the
end of the inspection,
licensee
management
was reviewing actions required to address
the low oil
level condition with the No.
23
RCP.
Inspectors will monitor conditions of
the No.
23
RCP and licensee
followup actions.
17
4.0
PLANT SUPPORT
NRC Inspection
Procedures
71750,
83750,
and 92904 were used to perform'an
inspection of plant support activities.
Two non-cited violations were
identified in the area of radiological controls.
Overall performance
in the
area of plant support
was considered
good.
4. 1
Radiolo ical Controls
The health physics staff has
remained stable.
Although
a corporate health
physicist left the company,
the radiation protection department
remains
technically sound.
The station also
has
a large
number of employees
who are
National Registry Radiation Protection Technician qualified.
The inspectors
reviewed several
quality assurance
(gA) audit
and surveillance
reports covering work activities that occurred over the previous
18 months.
Audit activities appeared
to be probing
and critical of the subject
area
being
reviewed.
Results
were effectively communicated
to the appropriate
department
and,
when appropriate,
a condition report was generated
for identified
deficiencies.
The inspectors
concluded that the licensee's
gA program,
specifically with regard to radiation protection,
was effective in identifying
opportunities for improving overall performance,
as well as procedural
deviations,
and
was considered
a licensee
strength.
4. 1. 1 Follow-u
on Non-Routine
Events
NRC Inspection
Procedure
92700
was
used to perform
a review of the following
written reports of non-routine events:
Closed
LER 50-315
94011
and
LER 50-315 94012:
The
LERs were written
concerning analysis
problems in the liquid and gaseous
sampling program.
The
LERs are closed
based
on inspector review of the procedural
changes that were
made to strengthen
the program
and to prevent recurrence.
4. 1.2 Radiolo ical Occurrences
The inspectors
reviewed the licensee's
investigation of a radiological
event
which involved 'two operators
who entered
Unit
1 upper containment during in-
core detector
movement operations.
Upper containment
was posted
as
a
radiation area instead of an extreme high radiation area
(EHRA) as
appropriate,
because
a Radiation Protection Technician
(RPT) failed to post
and control the area
as
an
EHRA when the moveable detector
system
(IHDS)
clearance
was not in effect.
Although the dose rates
in upper
and lower
containment
ranged
from about
26 mR/hr to 6 mR/hr, respectively,
during this
evolution, containment entry procedures
required that both entry areas
be
posted
and controlled
as
an
EHRA during any incore detector
movement.
When
the containment is properly posted
and controlled, the operators
are allowed
entry and provided constant
Radiation Protection
(RP) coverage.
Thes'e
controls are required to prevent
access
into the instrument
room where
extremely high dose rates
could exist when moving in core-detectors.
The
licensee identified this event
when another
RPT who knew the clearance
was not
in effect, discovered
operators
coming out of the upper containment.
The
18
operators
wore electronic dosimeters
(EDs), were exposed
to low dose rates
and
received less
than
5
mRem each,
and
made
no attempt to enter lower containment
from upper containment:
Any attempt to enter lower containment
(where the
instrument
room is located)
from upper containment"would
have required
an
intentional violation of the hatch entry access
controls leading into lower
containment.
During the investigation of this matter,
the licensee
also found that the
entrance
into Unit I lower containment
was not posted
and controlled
as
an
EHRA.
The instrument
room is located
immediately inside the entry hatch
and
although
none of the detectors
from the reactor vessel
were sent to the seal
table in the instrument
room during this specific evolution, the entrance
should
have
been
posted
and controlled
as
EHRA. If the operators
had entered
from the Unit I lower containment
entrance
during in-core detector
movement,
the controls in place to prevent possible
consisted of personal
use of alarming
EDs,
area radiation monitors
(ARMs) located inside the
containment
near the instrument
room which had remote annunciator
alarms,
a
requirement to notify the control
room before entry,
and the issuance
of the
lower containment
entrance
lock key by
RP staff.
The investigation of this
event included discussions
with all participants,
and radiation verification
surveys
in both upper
and lower containment during flux mapping operations.
As
a result of the investigation,
the licensee
concluded that there
was not
a
substantial
potential for a whole body overexposure.
The root cause
assessment
indicated there
was
an
RPT personnel
error, procedural
and key
control weaknesses,
and
no verification to ensure
the
IMDS clearance
was not
in effect.
Although the inspector's
review of the licensee's
investigation indicated that
the assessment
of the root causes
and corrective actions to prevent recurrence
was good, the inspectors identified some weaknesses
in the lower containment
alert/control
warning system that were not identified by the licensee
during
followup of this event.
For instance,
after the inspectors
entered
into the
Unit 2 lower containment
near the seal. table during unit operation,
the
inspectors
found that the
ED alarm and warning light worked, but the alarm was
barely audible
because
of the noise level from operating
equipment.
The
inspectors
also noted that in Unit 2 there
was
an operable
seal table area
. radiation monitor
(ARM) with a local warning light and alarm function with the
alarm setpoint at
20 mR/hr.
However, the Unit I seal table area
ARM did not
'have local alarm
and
a warning light, but instead
had annunciator
alarms in
the control
room and in a designated
RP office in the turbine building; the
alert alarm set point was
20 mR/hr and the high alarm was set at
100 R/hr.
Because
these
weaknesses
in the Unit I alarm /control warning
system
(no local
alarm
and warning light,
a high
ARM set point and possible
inaudible
EDs in
noisy areas)
were not identified in the condition report for the subject
radiological event,
no corrective actions would have
been taken to strengthen
the alert/control
warning system.
The inspectors
discussed
this matter with
the licensee
who indicated that these
weaknesses
were corrected
by installing
an interim local
ARM with both audible
and visible functions
and
an alarm set
point of 20 mR/hr in Unit I;
a permanent
system revision will.be
made in the
near future.
Although .there were
19
weaknesses
in the overall control of this evolution
and in the alert/control
system, it did not appear likely that there
was
a substantial
potential for a
whole body exposure
in excess of regulatory limits.
5.0
PERSONS
CONTACTED AND MANAGEMENT MEETINGS
The inspectors
contacted
various licensee
operations,
maintenance,
engineering,
and plant support personnel
throughout the inspection period.
Senior personnel
are listed below.
At the conclusion of the inspection
on August 17,
1995, the inspectors
met
with licensee
representatives
(denoted
by *) and summarized
the scope
and
findings of the inspection activities.
The licensee
did not identify any of
the documents
or processes
reviewed
by the inspectors
as proprietary.
- A. A. Blind, Site Vice President/Plant
Manager
- K. R. Baker, Assistant
Plant Manager-Operations
- J.
R.
Sampson,
Assistant Plant Manager-Support
- D. L. Noble, Radiation Protection Superintendent
- T. K. Postlewait,
Site Engineering
Support
Manager
- J. S.
Wiebe, Superintendent,
Plant Performance
Assurance
L. H. Vanginhoven,
Superintendent,
Material
Management
- W. M. Hodge,
Plant Protection Superintendent
- W. A. Nichols, Acting Operations
Superintendent
- G. A. Weber, Superintendent,
Plant Engineering
- M. E. Barfelz, Superintendent,
Nuclear Safety
8 Analysis
"A. A. Lotfi, Superintendent,
Site Design
- J.
D. Allard, Maintenance
Superintendent
- D. 0. Morey, Chemistry Superintendent
- D. M. Fitzgerald,
Superintendent,
Environmental,
Safety
and Health
- T. P. Beilman, Superintendent,
Integrated
Scheduling
- T. E. guaka,
Superintendent,
Project
Management
and Installation Services
- P.
G. Schoepf, Staff Assistant
20