ML18011A446
| ML18011A446 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 04/15/1994 |
| From: | Christensen H, Darrell Roberts, Tedrow J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18011A443 | List: |
| References | |
| 50-400-94-06, 50-400-94-6, NUDOCS 9405230101 | |
| Download: ML18011A446 (34) | |
See also: IR 05000400/1994006
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Report No..
50-400/94-06
Licensee:
Carolina
Power and Light Company
P. 0.
Box 1551
Raleigh,
NC 27602
Docket No.:
50-400
Facility Name:
Harris
1
Inspection
Conducted:
February
19 - April 2,
1994
Inspectors:
J.
row,
S
ior
sident Inspector
Licensee
No.:
4-i -e
Date Signed
D.
er
,
sid
Inspector
Approved by:
. Christensen,
Section Chief
Division of Reactor Projects
Date
igned
Date
igned
SUMMARY
Scope:
This routine inspection
was conducted
by two resident
inspectors
in the areas
of plant operations,
review of licensee's
control of overtime hours,
review of
nonconformance
reports,
preparations
for refueling, refueling activities,
followup of onsite events,
maintenance
observation,
surveillance observation,
design
changes
and modifications, plant housekeeping,
radiological controls,
security,
and fire protection.
Numerous facility tours were conducted
and
facility operations
observed.
Some of these tours
and observations
were
conducted
on backshifts.
Results:
One violation was identified:
Failure to properly control vehicles inside the
protected
area,
paragraph
5.c.
Several
instances
were noted where the conduct/control
of activities was
deficient:
inadequate
supervision during deenergization
of a process
instrumentation
cabinet,
paragraph
2.a(4);
poor coordination of testing
and
deenergization
of a process
instrumentation
cabinet,
paragraph
3.b.
Examples
of poor planning activities were noted:
planning/briefings for draining down
the reactor coolant system were deficient,
paragraph
2.c;
efforts to
establish
a containment closure plan were poor, paragraph 2.b(1);
coordination of preventive maintenance
with surveillance testing
was less than
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adequate,
paragraph
3.a(2).
In addition,
implementation of procedure
changes
following modifications
was poor, paragraph
4.b.
The content
and conduct of pre-evolution briefings for fuel handling
and lift
of the upper internals
were considered
to be very good,
paragraphs
2.c.
The
conduct
and content of several
major tests
were likewise found to be very
thorough,
paragraph
3.b.
The development of an outage
schedule to preclude reactor coolant system
reduced
inventory and mid-loop operations
was considered to be
a strength,
paragraph
2.b.
Overview and mockup training for the
RTD bypass manifold removal modification
was considered
to be
a strength,
paragraph
4.
Good efforts were noted to reduce radiation hot spots,
paragraph
5.b.
REPORT DETAILS
1.
Persons
Contacted
Licensee
Employees
D. Batton,
Manager,
Work Control
- D. Braund,
Manager,
Security
- B. Christiansen,
Manager,
Maintenance
- J. Collins, Manager,
Training
- J. Dobbs,
Hanager,
Outages
- H. Hamby,
Manager,
Corrective Action Programs/Operational
Events
- J. Kiser, Manager,
Radiation Control
D. HcCarthy,
Manager,
Regulatory Affairs
J.
Moyer, Hanager,
Site Assessment
- R. Prunty,
Manager,
Licensing
3 Regulatory
Programs
- W. Robinson,
Vice President,
Harris Plant
W. Seyler,
Manager,
Project
Management
H. Smith,
Manager,
Radwaste
Operation
- D. Tibbitts, Manager,
Operations
B. White, Manager,
Environmental
and Radiation Control
A. Williams, Manager, Shift Operations
- L. Woods,
Manager,
Technical
Support
M. Worth, Manager,
Onsite Engineering
Other licensee
employees
contacted
included office, operations,
engineering,
maintenance,
chemistry/radiation
and corporate
personnel.
- Attended exit interview
2.
and initialisms used throughout this report are listed in the
last paragraph.
Operations
a ~
Operational
Safety Verification (71707)
The plant began .this inspection period in power operation
(Node
1).
On March 19,
1994, the unit was taken off-line and
a plant
shutdown performed to commence
a scheduled
refueling outage.
A
plant cooldown was subsequently
performed
and
on March 20 the unit
was placed in the cold shutdown
(Node 5) condition.
On March 26
at 5: 18 p.m. the reactor vessel
closure
studs
were detensioned
and
refueling operations
(Node 6) commenced.
The plant remained in
Mode
6 for the duration of this inspection period.
(1)
Shift Logs and Facility Records
The inspector reviewed records
and discussed
various entries
with operations
personnel
to verify compliance with the
Technical Specifications
(TS)
and the licensee's
administrative procedures.
The following records
were
reviewed:
shift supervisor's
log; outage shift manager'
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log; control operator's
log; night order book; equipment
inoperable record; active clearance
log; grounding device
log; temporary modification log; chemistry daily reports;
shift turnover checklist;
and selected
radwaste
logs.
In
addition, the inspector
independently verified clearance
order tagouts.
The inspectors
found the logs to be readable,
well
organized,
and provided sufficient information on plant
status
and events.
Clearance
tagouts
were found to be
properly implemented.
No violations or deviations
were
identified.
Facility Tours
and Observations
Throughout the inspection period, facility tours were
conducted to observe operations,
surveillance,
and
maintenance activities in progress.
Some of these
observations
were conducted during backshifts.
Also, during
this inspection period, licensee
meetings
were attended
by
the inspectors
to observe
planning
and management
activities.
The facility tours
and observations
encompassed
the following areas:
security perimeter fence; control
room;
emergency
diesel
generator building; reactor auxiliary
building; reactor containment building; waste processing
building; turbine building; fuel handling building;
emergency
service water building; battery rooms; electrical
switchgear
rooms; technical
support center,
and the
emergency
operations facility.
During these tours,
observations
were
made
on monitoring
instrumentation
which included equipment operating status,
area
atmospheric
and liquid r adi ation monitors, electrical
system lineup, reactor operating
parameters,
and auxiliary
equipment operating
parameters.
Indicated parameters
were
verified to be in accordance
with the
TS for the current
operational
mode.
The inspectors
also verified that
operating shift staffing was in accordance
with TS
requirements
and that control
room operations
were being
conducted in an orderly and professional
manner.
In
addition, the inspector
observed shift turnovers
on various
occasions
to verify the continuity of plant status,
operational
problems,
and other pertinent plant information
during these turnovers.
The licensee's
performance
in these
areas
was satisfactory.
No violations or deviations
were identified.
Control of Overtime
The inspectors
conducted
a detailed inspection of the
licensee's
program for controlling the usage of overtime.
The inspection
included
a review of the licensee's
administrative
procedure,
AP-012, Control of Overtime Hours,
and
a study of overtime data dating back to January
1991.
The historical review of overtime records
was done to
develop
a trendline for overtime usage
and to compare data
for the two most recently completed refueling outages
(Fall
1992
and Spring 1991).
As noted in paragraph
2.a of this
report, the plant recently
began
Refueling Outage
(RFO)
5 on
Harch 19,
1994.
Therefore,
overtime data for the current
outage could not be analyzed during this inspection period.
In addition,
November
1992 data
was not available for the
operations
group.
The inspectors
compared
the licensee's
program
as described
in procedure
AP-012 to requirements
contained
82-12,
82-16,
and 83-14
and
The
inspectors
found that the licensee's
administrative
procedure satisfied
NRC requirements.
Specifically,
procedure
AP-012 prohibited the routine heavy use of
overtime for specific job categories,
except in the event of
unforeseen
problems requiring substantial
overtime.
In
those special
cases,
the licensee's
procedure limited
individuals from working more than
16 consecutive
hours,
working more than
16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, working more
than
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period, or working more than
72
hours in a seven
day period.
The above restrictions
were
extended for STAs whose
seven
day limit was
84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br />.
All
of the above restrictions
excluded
hours which were
attributed to shift turnover.
Any instances
where
an
individual was expected
to exceed
the limits had to be
approved
by the Plant General
Hanager
(PGH)
on a case
by
case
basis
before the fact.
Additionally, the
PGH or his
designee
were required to review overtime monthly for each
of the affected job categories
to assure
that excessive
hours
had not been assigned.
The job categories
affected
by
AP-012 included all licensed operators,
auxiliary operators,
radwaste
operators,
EKRC technicians,
maintenance
technicians,
and their first line supervisors.
All other
job categories
were exempted
from the requirements
of AP-
012.
During a review of overtime extensions that had
been
approved
over the previous three years
encompassing
the last
two completed refueling outages,
the inspectors
found that
the licensee
complied with its procedure for controlling and
approving overtime.
Overtime use for the affected work
groups
was heaviest
during the refueling outages,
especially
in the areas of operations,
maintenance,
and
EKRC.
For
example,
during
RFO-4 (September
- December
1992), the
PGH
approved
over
600 instances
of overtime where the
TS limits
were expected to be exceeded.
Approximately two-thirds of
those
instances
were assigned
to the maintenance
unit, with
the balance divided between
the operations
and
E&RC
organizations.
During RFO-3
(March - May 1991), the numbers
were less for the maintenance
unit (approximately
100
instances
were pre-approved),
but greater for the
EKRC (over
40 instances)
and operations
groups.
During March 1991,
virtually all of the operations shifts were pre-approved
to
attend
a mid-loop training class,
which contributed heavily
towards that outage's
overtime totals.
The inspector
found that the occasions
where overtime use
exceeded
TS limits were substantially lower during non-
outage
months for all work groups except the radwaste
operators.
Only one example
was found during each of the
last two completed refueling outages
where radwaste
operators
needed
approved extensions.
However,
an average
of five overtime extensions
per month were granted for
radwaste
operators
between
non-outage
months April 1993
and
November
1993.
Licensed
and auxiliary operators
also
had
an
average of five overtime extensions
approved
per month from
the end of RFO-4
(December
1992) to February
1994, but this
average
represented
decreases
from outage
months for those
groups.
Maintenance
(2.3 per mo'nth)
and
EKRC (1.4 per
month) also registered
fewer extensions
since
RFO-4.
While the inspectors
did not identify any explicit
violations of TS requirements,
questions
were raised
on
various aspects
of the licensee's
implementation of overtime
controls.
For instance,
the inspector
noted inconsistencies
in how the maintenance
organization attributed excessive
hours to shift turnover time.
Specifically,
cases
were
identified where individuals worked
13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />
a day for seven
consecutive
days.
In such cases,
both the
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in two
days
and the
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in seven
days limits were exceeded
during the
same work week, with 26 and
91 hours0.00105 days <br />0.0253 hours <br />1.50463e-4 weeks <br />3.46255e-5 months <br /> having been
worked, respectively.
However, only the two hours that
exceeded
the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> limit were regarded
as shift turnover
time, while the
19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br /> that exceeded
the
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
requirement
were given approvals
by the
PGM.
No specific
guidance
appeared
in procedure
AP-012 on
how to determine
shift turnover time.
Discussions
with maintenance
personnel
indicated that typically one hour per shift was classified
in this manner.
The inspector also noted that the plant technical
support
organization
was not formally included in the licensee's
program for controlling overtime.
The inspector identified
that certain technical
support engineers
have
been actively
involved in safety related activities,
and in some cases
have performed surveillance tests related to plant startup
activities.
A recent
issue
was documented
in ACFR 94-947
regarding the scheduling of engineers'ours
during RF0-5.
It was identified by licensee
personnel
that
a few engineers
had
been
scheduled
to exceed
the limits outlined in TS 6.2.2.f. without the
PGM's approval.
Licensee
management
corrected the specific scheduling
problems prior to RFO-5
and
a procedure
change
was submitted to incorporate
the
technical
support organization
in the licensee's
program.
The inspector also addressed
the scheduling of overtime to
cover for vacationing operators,
operators
in training,
and
other routine situations that
may be considered
to be
"foreseen"
by management.
The inspector
reviewed weekly
operations
schedules
for non-outage
months
and concluded
that, while overtime is being
used in those situations, it
is not being used excessively
and is therefore in compliance
with the intent of Technical Specification 6.2.2.f and other
NRC guidance.
The inspectors
concluded that overall the licensee
had the
proper program in place for controlling overtime,
and that
implementation
was satisfactory.
The inspectors
informed
plant management
of the areas
noted
above related to the
classification of shift turnover time and the incorporation
of technical
support engineers
into the licensee's
program.
No violations or deviations
were identified.
Review of Nonconformance
Reports
Adverse Condition Feedback
Reports
(ACFR) were reviewed to
verify the following:
TS were complied with, corrective
actions
and generic
items were identified and items were
reported
as required
by 10 CFR 50.73.
Adverse Condition
& Feedback
Report 94-1027
documented
an
example of poor communications
which occurred
on March 26,
1994.
An off-shift operator
was tasked with removing the
clearance
from process
instrumentation
cabinet ¹3 (PIC-3)
and then reenergizing it.
The operator
was
handed the
applicable procedure,
AC Electrical Distribution,
which had
been
marked
up by a shift operator
who was
originally intended to perform the activity.
Prior to
performing the task,
the off-shift operator
informed control
room operators
what was about to occur.
After discussions
with control
room operators,
the off-shift operator
proceeded
with energizing cabinet
PIC-3.
Moments later, the
control
room received
several
alarms
and indications that
the "A" ESW pump had auto-started.
A shift operator
was
dispatched
to the IDP-lA-SIII instrument
bus
(which powers
PIC-3) who discovered that the off-shift operator
had
performed steps
in procedure
OP-156.02 for reenergizing
the
entire instrument 'bus.
That evolution involved deenergizing
several
other instrument cabinets first, including one which
processed
pressure
and flow data.
The
resultant
"loss of
ESW pressure"
led to the "A" pump auto-
starting.
Operators
quickly corrected
the situation
by
reenergizing
the affected instrument cabinets.
Operator
accounts of this event later identified that the
operator
who originally marked
up the procedure
had marked
steps for cabinets
PIC-3,
9 and
13.
However, this operator
understood that
he was only to perform steps for energizing
PIC-3.
That intent had not been effectively communicated to
the off-shift operator ultimately tasked with performing the
evolution,
by neither the shift supervisor or the senior
reactor operators.
In reviewing this event,
the inspectors
concluded that the only safety
consequence
was that
an
component
was started
unnecessarily.
However, the above
circumstances
demonstrated
weak supervisory control
and
direction.
No violations or deviations
were identified.
Preparations
for Refueling
(60705)
Outage
Risk Assessment
Review
As discussed
in
NRC Inspection
Report 50-400/94-05,
licensee
personnel
had performed
an outage risk assessment
for the
refueling outage
using procedure
PLP-700,
Outage
Management.
During this inspection period, the inspectors
compared
the
licensee's
risk assessment
with the requirements
contained
in procedure
PLP-700,
and reviewed the level II outage
schedule,
to verify that the licensee
had avoided scheduling
high risk evolutions
when possible.
The inspectors
compared
procedure
PLP-700 to guidelines
contained
in NUREG-1449, the
NRC's Final Report
on Shutdown
and Low-Power Operation at
Commercial
Nuclear
Power Plants in the United States.
The
inspectors verified that procedure
PLP-700 addressed
all of
the shutdown or low power operations
requirements
referenced
in NUREG-1449,
and concluded that the procedure
was adequate
to be used
as
a basis for the licensee's
outage risk
assessment.
The inspectors
independently verified selected
attributes of
the outage
schedule.
The inspectors
noted that the outage
schedule
had
been developed to avoid establishment
of RCS
reduced
inventory or mid-loop conditions.
Since several
industry events
have occurred with the
RCS in reduced
inventory conditions,
the inspector considered
the exclusion
of these situations to be
a substantial
benefit to safe
operation while the plant was shutdown.
The outage
schedule
was discussed
with licensee
personnel
who demonstrated
to
the inspectors that the re'quirements
of procedure
PLP-700
were properly considered.
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The risk assessment
identified that two high risk evolutions
existed
in the outage
schedule.
Similar to the previous
refueling outage,
the activity to switch electrical
power
for the "A" spent fuel cooling
pump following the "A" train
electrical
bus outage
was considered
to be
a higher risk
evolution due to only one spent fuel cooling pump being
available to provide cooling water to the unloaded core.
The other evolution involved repairs to component cooling
water relief valve
1CC-129 which necessitated
the use of a
freeze
seal to isolate the valve.
Potential failure of the
freeze
seal
would jeopardize
CCW system availability.
The
inspectors
reviewed the licensee's
contingency plans for
these activities.
The plan for the
CCW valve repairs
minimized the time during which the freeze
seal
was relied
upon
and provided for a wooden plug to be installed if
necessary
to isolate leakage.
In addition, the availability
of the demineralized
water system
was ensured to provide
sufficient makeup water to the system in the event of freeze
seal failure.
As a followup to the comments
made in NRC Inspection
Report
50-400/94-05,
the inspectors
reviewed the licensee's
response
to an assessment
finding that no comprehensive
plan
for containment closure existed contingent
on a loss of RHR
This item was discussed
with outage
management
and operations
personnel.
The licensee
made
revisions to procedure
AOP-20 to include necessary
announcements
and to check containment penetration
breaches
for closure.
Containment penetration
status
would be listed
on
a tracking copy of procedure
OST-1091 in the work control
center.
A night order was written to notify operating
personnel
of the penetration
tracking requirement.
On March
24 the inspector
checked
the licensee's
actions
and asked to
view the status of containment penetrations.
The inspector
was informed that the previous shift had discarded
the
OST-
1091 tracking procedure.
A new tracking procedure
was
promptly reinitiated.
The inspector also noted that the
night order did not require the tracking status to include
persons
responsible for resealing
the penetrations if
necessary.
The inspector concluded that the licensee's
efforts in establishing
a containment closure plan were
poor.
No violations or deviations
were identified.
Independent
Procedure
Review
Prior to the onset of the refueling outage,
the inspectors
reviewed various
shutdown
and refueling related
procedures
to verify that certain areas,
including- prerequisites for
refueling, provisions for spent fuel inspections,
and
provisions for maintaining proper decay heat removal,
were
addressed.
The following procedures
were reviewed:
PLP-616
FHP-010
FHP-014
FHP-020
OST-1817
OST-1818
OST-1091
MST- I0169
MST- I0170
Fuel Handling Operations
Core Mapping Following Fuel
Loading
Fuel
and Insert Shuffle Sequence
Fuel Handling Operations
Refueling Machine (Manipulator Crane)
Operability Modes:
100 Hours Prior to Fuel
Movement in Pressure
Vessel
Auxiliary Hoist Operability:
100 Hours
Before Control
Rod Drive Movement in the
Reactor
Vessel
Containment
Closure Test Weekly Interval
During Core Alterations
and
Movement of
Irradiated fuel Inside Containment
Nuclear Instrumentation
System Source
Range
N31 Operational
Test
Nuclear Instrumentation
System Source
Range
N32 Operational
Test
Loss of RCS Inventory or Residual
Heat
Removal
While Shutdown
The fuel handling procedures all contained clear statements
of responsibilities for the key personnel
involved in fuel
movement activities.
Various precautions
and limitations
were contained
in the procedures
which addressed
requirements for flux monitoring; containment integrity;
communications
between
the main control
room, the
containment building,
and the fuel handling building; and
expected
actions following identification of damaged fuel
assemblies.
Additionally, the procedures
contained
provisions for checking refueling equipment operability,
underwater lighting, and adequate
water level
above the
reactor
vessel
flange during refueling.
Overall, the
inspectors
concluded that the above procedures
were
technically adequate
to accomplish the desired tasks.
No violations or deviations
were identified.
Refueling Activities (60710)
The inspectors
witnessed refueling activities
and verified that
the refueling was being performed in accordance
with TS
requirements
and approved
procedures.
Areas inspected
included
containment integrity, housekeeping
in the refueling area, shift
staffing during refueling, surveillance testing,
and periodic
monitoring of plant status
during refueling operations.
As part
of this inspection,
implementation of the following procedures
was
observed:
GP-008
Draining the Reactor Coolant System
II
GP-009
FHP-014
FHP-020
Refueling Cavity Fill, Refueling,
and Draindown
of the Refueling Cavity
Fuel
and Insert Shuffle Sequence
Fuel Handling Operations
Integrated
Reactor
Vessel
Head
and Upper
Internals
Removal
The inspectors
witnessed
the removal of the core upper internals,
initial core offload,
and fuel sipping.
The licensee utilized an
underwater
camera to verify that no fuel elements
were lifted with
the upper internals.
Pre-evolution briefs were attended for the
upper internals lift and unlatching of the
RCCAs.
These briefs
were considered
to be very thor ough
and cautioned
operating
personnel
of excessive
reliance
on the contractors
performing the
work.
Licensee
performance
o'f these activities
was satisfactory.
The inspectors
also observed
the draindown of the
RCS to -10
inches
below the reactor vessel
on Parch
26 in preparation
for head removal.
The controlling procedure for this evolution,
GP-008,
was reviewed.
The inspectors
noted that the procedure
contained
precise administrative controls to prevent
an
inadvertent
loss of RHR shutdown cooling.
These
procedure
controls were found to be properly implemented.
Even though
reduced
RCS inventory and mid-loop operations
were not entered,
the inspectors
detected
a heightened
sense of awareness
among the
control
room staff during this evolution.
The level in the
was monitored during the draindown with remote standpipe
level
indication,
a continuous
standpipe
watch inside containment,
and
the RVLIS.
The
RCS draindown
was stopped
at approximately
96 inches
when
operators
detected
a deviation between
RVLIS and the standpipe
indication.
The licensee utilized a curve which compared
upper range to the standpipe
indication.
The deviation
was caused
by two factors which included using the
RVLIS full range
indication vice upper range,
and disconnection of the RVLIS
reference
leg at
a different location from that in the past.
The
difference in length of the
new reference
leg necessitated
the
generation of a new comparison
curve.
When the
new curve was
implemented,
the
RVLIS and standpipe
indications
agreed
and the
draindown
recommenced.
The inspectors
considered
the control of
this evolution to be good.
However, the inspectors
considered
the
pre-evolution planning
and briefings to be deficient which did not
identify the appropriate
RVLIS range to utilize or where the
reference
leg would be disconnected.
Following a partial refueling cavity fill, the seal ring was found
to be leaking approximately
8 gpm.
This necessitated
another
dr aindown of the refueling cavity with the reactor vessel
head off
and the
RVLIS reference
leg capped.
Licensee
personnel
used
procedure
GP-009 to perform this activity.
This procedure
was
written under the assumption that the core
was offloaded prior to
0
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0
F
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~,
1
'"*g * l
l 4
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f~."j
10
draindown of the refueling cavity and did not include provisions
for diverse
RCS level monitoring.
Operators
nonetheless
monitored
RVLIS indications
and stationed
a watchstander
at the
standpipe
to monitor
RCS level.
The inspector considered
these
precautions
to be very good
and minimized the potential for a loss
of RHR shutdown cooling.
It was also noted that procedure
GP-009
could
be strengthened
by the addition of these precautions.
No violations or deviations
were identified.
Followup of Onsite
Events
(93702)
At approximately
10:00 p.m.
on March 27,
1994 while in the main
control
room, the inspector
observed that operators
received
a
call from the corporate
load dispatcher notifying them that
a
tornado watch was in effect.
The operators
promptly entered
administrative
procedure
AP-301, Adverse Weather Operations,
and
documented
the entry in the control
room logs.
Upon receiving
notice of a tornado watch,
procedure
AP-301 required operators
to
complete
a detailed checklist that verified certain controls were
in place (i.e., loose material
removed or tied down, outlying area
doors shut, fire pumps operable,
external lighting energized,
operability of various safety related
equipment including EDGs).
However, the inspector
knew the tornado watch
had
been in effect
prior to 9:00 p.m. that evening
and inquired to operations
personnel
about the suspected
delay in notification.
Operations
personnel
informed the inspector that the load dispatcher
had only
been
informed ten minutes prior to plant notification.
The
inspector contacted
the National
Weather Service
(NWS) to
ascertain
when the tornado watch actually went into effect.
According to the
NWS, Tornado Watch 847, covering
Wake County and
the majority of the state of North Carolina,
went into effect at
7:30 p.m.
on Harch 27,
1994
and did not cease until 2:00 a.m.
on
March 28,
1994.
The inspector determined that there
had
been
a
two and one-half hour delay between the tornado watch being
declared
and key plant personnel
being notified.
Considering the number of actions
necessary
to take following
notification of a tornado watch or warning, the rapid rate at
which severe
storms
can travel,
and potential
damage
which could
be inflicted upon plant equipment, it is beneficial for the plant
to receive
such information promptly.
The inspectors
discussed
this notification delay with plant management
who stated that they
would investigate it.
No violations or deviations
were identified.
J
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11
Maintenance
a.
Maintenance
Observation
(62703)
The inspector observed/reviewed
maintenance activities to verify
that correct equipment
clearances
were in effect; work requests
and fire prevention work permits were issued
and
TS requirements
were being followed.
Maintenance
was observed
and work packages
were reviewed for the following maintenance activities:
~
Preventive
maintenance
on battery charger
IA-SB in
accordance
with procedure
PM-E0023,
C&D Battery Chargers.
Installation of new manually operated
valve lAF-208 for "B"
motor driven
AFW pump discharge
isolation in accordance
with
modification PCR-6502.
Replacement
of rotating element for the "A" motor driven
pump in accordance
with procedure
CM-N0039, Ingersoll-Rand
Motor Driven Auxiliary Feedwater
Pump Size
3 HHTA-9
Disassembly
and Maintenance.
Replacement
of motor operator with hand wheel for valve 1AF-
5 in accordance
with modification PCR-6925
and procedure
CN-
M0051, Limitorque Valve Operator Size
SB/SMB-00 Disassembly
and Maintenance.
Switchover power feed for the "C"
CCW pump motor from "A"
train to "B" train in accordance
with procedure
Electrical
Power
Feed Switchover For Component
Cooling Water
Pump
Packing adjustment
on 1AF-51
Bridge and megger
"C" CSIP motor in accordance
with NPT-
E008, Environmentally gualified 6.9
KV Motor Electrical
Inspection;
and troubleshooting to determine
cause of-
ground.
Secure
cables to the
DC distribution panel cabinet
raceway
as described
in drawing 2166-B-060 Sheet
97.
Perform lifttest
on relief valve
1SW-171 'in accordance
with
procedure
EST-211, Auxiliary Relief Valve Testing.
In general,
the performance of work was satisfactory with proper
documentation of removed
components
and independent verification
of the reinstallation.
(1)
The inspectors
reviewed the activities of the
EKRC planner
who has
been
assigned
to the work control center.
The
~ licensee
has attributed substantial
radiation exposure
dose
0
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12
savings to these efforts.
Planning activities included dose
reduction
and contamination control technique
incorporation
into maintenance
work requests.
Work tickets were grouped
for work in high radiological risk areas for better
coverage
and work for areas that had
been shielded for other
jobs was coordinated
and scheduled.
Scheduling of RHR
system outage
PMs online to avoid working on this system
when dose rates
are higher was also performed.
The
inspectors
considered this aspect of work control to be
effective in lowering personnel
exposures.
(2)
As a followup to the comments
in
NRC Inspection
Report 50-
400/94-05,
the inspectors
noted another
example of poor
coordination of work activities with planned surveillance
testing.
During the week of February
28,
1994, licensee
personnel
performed maintenance
on several different valves
associated
with the
ESW system
(1SW-130,
and
1SW-129) which necessitated
partial
performances
of procedure
OST-1215,
Emergency Service Water
System Operability Train
B quarterly Interval, to stroke
time the valves
as part of post maintenance
testing.
Approximately four partial tests
were performed during this
week.
On the following week of March
7 the entire test
-procedure
was scheduled
to be performed.
The inspector
considered
the work activities/test
scheduling effort to be
deficient
and resulted
in redundant
component testing
and
equipment out of service time.
(3)
The inspector
observed
the performance of preventive
maintenance
on the battery charger which verified the
current limiting device.
Battery charger current
was found
to be limited to 172 amperes.
The inspector noticed that
procedure
PM-E0023 specified
an acceptable
range for this
current
between
171.64 - 173.36
amperes.
The inspector
further noticed that the computerized test
system
measured
this current
and provided indication to the nearest
whole
ampere.
- The -inspector -considered
the specified
acceptance
criteria to be irrelevant
since current indication could not
be measured
to the nearest
hundredth of an ampere.
This
observation
was brought to the attention of the maintenance
supervisor
who stated that appropriate
procedure
changes
would be implemented.
No violations or deviations
were identified.
Surveillance Observation
(61726)
Surveillance tests
were obse} ved to verify that approved
procedures
were being used; qualified personnel
were conducting
the tests; tests
were adequate
to verify equipment operability;
calibrated
equipment
was utilized; and
TS requirements
were
followed.
The following tests
were observed
and/or data reviewed:
1'I
13
HST-EOOll, lE Battery quarterly Test
HST-I0133, Hain Steamline
Pressure,
Loop
3 (P-0496)
Operational
Test
OST-1813,
Remote
Shutdown
System Operability 18 Honth
Interval
Hades
5 or 6.
OST-1091,
Containment
Closure Test Weekly Interval During
and Hovement of Irradiated
Fuel Inside
Containment.
HST-E0010,
lE Battery Meekly Test
OST-1011, Auxiliary Feedwater
Pump lA-SA Operability Test
EST-209,
Type
B Local
Leak Rate Tests
The performance of these
procedures
was found to be satisfactory
with proper
use of calibrated test equipment,
necessary
communications
established,
notification/authorization of control
room personnel,
and knowledgeable
personnel
having performed the
tasks.
The quarterly battery test
was being accomplished
on
a
monthly frequency.
Good use of personnel
protective equipment
was
observed
during the performance of this test.
The inspectors
observed
some of the preparations
for complex tests
to be performed during this refueling outage.
Operations
personnel
have prepared briefing packages
for the complex tests.
These
packages
included
a summary of the test procedure,
breakdown
of manpower requirements
to perform specific tasks,
the
PLP-100
briefing papers for the performance of infrequent tests
and
evolutions,
and applicable industry events
which have occurred
during the performance of the specific test.
The inspectors
attended
a pre-evolution briefing for procedure
OST-1813.
The items discussed
above were thoroughly covered.
The
test
was subsequently
performed without incident.
The inspectors
considered
the preparations
for the performance of these
types of
tests to be
a program strength.
An activity was allowed to be performed concurrently with
procedure
OST-1813 to deenergize
instrument cabinet
PIC-3 for RTD
bypass elimination modification wor k.
When cabinet
PIC-3 was
deenergized
the P-13 permissive
was activated
which generated
a
turbine trip/reactor trip signal.
The reactor trip breakers
were
open at the time this signal
was generated
which alleviated
reporting requirements.
However, this event necessitated
delaying
the performance of procedure
OST-1813 since the reactor trip
breakers
were required to be closed during performance of other
portions of the test.
The inspectors
considered
the decision to
4
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1
deenergize
PIC-3 during the performance of the test procedure to
be poor.
No violations or deviations
were observed.
Engineering
Design
Changes
and Modifications (37828)
Plant
Change
Requests
(PCR) involving the installation of new or
modified systems
were reviewed to verify that the changes
were reviewed
and approved
in accordance
with 10 CFR 50.59, that the changes
were
performed in accordance
with technically adequate
and approved
procedures,
that subsequent
testing
and test results
met approved
acceptance
criteria or deviations
were resolved in an acceptable
manner,
and that appropriate
drawings
and facility procedures
were revised
as
necessary.
In addition,
PCR's documenting
engineering
evaluations
were
also reviewed.
The following modifications and/or testing in progress
was observed.
a 4
The inspector
attended
an
RTD bypass manifold overview training
course
which was presented
to a wide variety of licensee
personnel
involved with modification
PCR 0420,
RTD Bypass Elimination.
The
overview training was
an introductory level course
which covered
the history of the
RTD bypass manifold problems which led to the
pending removal.
It also covered the logistics of the whole
project from demolition of the old manifold piping, to
installation
and welding of the
new
RTDs (to be directly immersed
in the
RCS loop piping).
By using floor elevation sketches,
the
course instructor discussed
radiological protection plans which
included low dose waiting areas for personnel
and logistics for
removing highly radioactive
bypass manifold piping from the
containment structure.
b.
In addition, the inspector walked down and observed training on
a
mockup of the
RTD bypass
manifolds which was setup in one of the
plant's warehouses.
The mockup training classes
were presented
to
individual work groups which were responsible for various aspects
of the
RTD bypass
removal project.
The training classes
were
custom designed for each work group depending
on that group's job
(e.g., insulation removal, demolition of old piping, placement of
radiological shielding,
or decontamination).
The mockup was
an
impressive
model of a typical Harris
RCS loop.
An entire
bypass manifold was depicted
as
was its associated
isolation
and
drain valves,
and its connections
to the
RCS hot, cold,
and
crossover
legs.
Physical conditions
such
as elevations,
and layout of trash
removal
paths
were also mimicked.
The
RTD bypass manifold training efforts were considered to be
good.
Several
ACFRs were generated
over the past
few months related to
untimely revision of procedures
affected
by PCRs.
An engineer
15
reviewing procedures
in August
1993 noted that
PCR-6540
was closed
in April 1993 but the affected
procedures
were never revised.
An
ACFR was generated
(ACFR 93-317) to document this discrepancy.
The
PCR was
a document-change-only
PCR which revised torque values
for fasteners
used in electrical
connections.
In January
1994,
one of these
procedures
was being used for maintenance
when
electricians
discovered that the
same
procedures still had not
been revised to incorporate
the
new torque values.
Another ACFR
was generated
(ACFR 94-400)
on January
26,
1994 to document this
fact.
Due to previous
and subsequent
problems with timely procedure
changes
caused
by PCRs,
an event review team
was established
to
investigate
the above
ACFRs and to recommend corrective actions.
Since there
had
been
no formal method for ensuring that procedures
affected
by document-change-only
PCRs were revised following PCR
closeout,
one corrective action that had already
been
implemented
for ACFR 93-317 was to develop
a list of required procedure
changes
from document-change-only
and incorporate the list
into the newly created
Nuclear Revision Control
System
(NRCS)
computer tracking system.
Procedure writer groups routinely
received
a printout of the outstanding
procedure
change list
generated
by NRCS.
Some procedure writers effectively utilized
the NRCS-generated list.,
However, others did not fully understand
the relationship
between
PCRs,
the
new
NRCS system,
and the
procedure
change
process.
The event review team noted that no
existing plant procedures
described
the above relationship or how
NRCS should
be used.
The team
recommended
the development of such
a plant procedure,
along with the training of procedure writers on
NRCS,
as corrective actions.
Concerning
ACFR 94-400
the event review team noted that the
corrective actions for ACFR 93-317 focused
on correcting the
generic
problem (updating the
NRCS database
with outstanding
procedure
changes)
and not the specific maintenance
procedures
identified in ACFR 93-317.
The
ACFR was closed
based
on
completion of the more generic corrective actions.
The'event-
review team
recommended
that this situation
be reviewed with the
involved organizations
to improve their understanding
of the
ACFR
process
and improve communications
between
work groups.
In a separate
incident,
on January
27,
1994,
an operator initiated
ACFR 94-401 to document that control
room alarm response
procedures
had not been revised to incorporate
new alarm setpoints
for three
emergency
exhaust
fan units.
Plant
Change
Request
6731,
modified the setpoints
and required that the documents
be changed
prior to
PCR turnover but not prior to implementation.
Since
partial implementation
occurred well before turnover,
a delay
occurred
between
the time that the setpoints
were changed
in the
field and the time the procedures
would have reflected those
changes.
Upon discovery,
the affected procedures
were revised via
the temporary
change
process.
i
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7
16
The event review team for ACFRs93-317
and 94-400 also
investigated
ACFR 94-401.
The corrective action proposed for ACFR
94-401
was to develop
a process for linking work tickets to
prerequisite
or subsequent
manual
tasks (i.e., procedure
and/or
drawing changes).
These
manual
tasks
would be formally tracked
by
the work control process
to ensure that field changes
affecting
working procedures
are incorporated
into those
procedures
in
a
timely manner.
The event review team presented
the
above
recommended
actions for
the two events
before the
PNSC
on Harch ll, 1994.
The proposed
corrective actions
were approved.
In addition, the team provided
an assessment
of the safety significance of the
above events
and
concluded that neither of the specific cases
had
any safety
consequences.
In the case of the fastener
torque specifications,
the worst consequence
in using the unrevised
procedures
would have
been using old values to which the plant had always
been designed.
For the three
emergency
exhaust
fan units,
PCR-6731 actually
lowered their alarm setpoints to ensure that alarms
came in before
TS differential pressure limits were exceeded.
Due to the low
significance of these
items, the event review team
recommended
that the corrective actions
be given due dates
beyond the
completion of the current refueling outage.
The inspector
attended
the
PNSC meeting
and concluded that while
the specific examples
noted
above did not have safety
significance,
the licensee
had identified areas
in need of
improvement.
Along with the areas
discussed
above,
the inspectors
noted that even after corrective actions
were implemented for the
initial discovery of PCR-6540 procedural
deficiencies,
the
NRCS
system which was
used for verifying working documents
(and relied
upon heavily in the event review team's
recommended
corrective
actions)
did not flag to the user in January
1994 that the
maintenance
procedures
required
changes.
The inspector's
overall conclusion
was that the licensee's
implementation of procedure
changes
following modifications
was
poor.
Licensee
management
agreed that more attention
was
needed
in the area of PCR implementation.
No violations or deviations
were identified.
Plant Support
'a ~
Plant Housekeeping
Conditions
(71707)
- Storage of material
and
components,
and cleanliness
conditions of various
areas
throughout
the facility were observed to determine
whether safety and/or fire
hazards
existed.
b.
Radiological Protection
Program
(71707) - Radiation protection
control activities were observed routinely to verify that these
activities were in conformance with the facility policies
and
17
procedures,
and in compliance with regulatory requirements.
The
inspectors
also reviewed selected
radiation work permits to verify
that controls were adequate.
The inspectors
reviewed licensee efforts in reducing radiation
"hot spots" which existed in several
plant areas.
These efforts
were responsible for significant reductions
in radiation dose
rates for the
VCT room,
RCS filter valve gallery,
and for the
filter backflush storage
tank room.
Reductions
by a factor of 10
were achieved
in these
areas.
The inspectors
considered
the
licensee's
dose reduction efforts to be successful.
On February 8,
1994, the inspectors
found
a key which was similar
to those
used
by the
HP department to control
access
to plant
areas.
The inspector
informed licensee
personnel
of this matter
and discussed
possible
doors which this key could provide access
through.
The inspector
was informed that this type of key (RCl-1)
was
a generic
key which would allow access
to equipment
storage
areas
and to several
plant areas
which contained
abandoned
equipment.
Typically the storage
areas
were for supplies
in
general
use
by decontamination
personnel.
The abandoned
equipment
rooms were infrequently visited and not routinely surveyed
therefore,
access
was controlled by these
types of keys.
The
inspectors
toured plant areas
which were classified
as
The
inspectors verified that the RCl-1 key would not allow access
to
these
areas.
The key was subsequently
returned to
HP personnel
on
February
25.
The inspector discussed
control of these
keys with
HP personnel.
In contrast to the good controls established
for
LHRA keys, the licensee
simply maintained
an informal log of RCl-1
key holders.
No plant procedure controlled the issuance/use
of
these
types of keys.
No violations or deviations
were identified.
Security Control
(71707)
- The performance of various shifts of
the security force was observed
in the conduct of daily activities
which included:
protected
and vital area
access
controls;
searching of personnel,
packages,
and vehicles;
badge
issuance
and
retrieval; escorting of visitors; patrols;
and compensatory
posts.
In addition, the inspector
observed the operational
status of
closed circuit television monitors, the intrusion detection
system
in the central
and secondary
alarm stations,
protected
area
lighting, protected
and vital area barrier integrity,
and the
security organization interface with operations
and maintenance.
On March 5,
1994, while on routine patrol,
a security officer
located
an unattended
vehicle with keys left in the ignition.
The
vehicle was parked inside the protected
area
and
had
been driven
by a contract
employee.
Upon discovery,
the keys were removed
from the vehicle
and returned to the responsible
individual's
supervisor
who was reminded of the importance of maintaining
proper control of vehicles within the protected
area.
18
d.
Previous
problems
have
been identified regarding vehicle control.
A non-cited violation (400/93-20-03)
was issued
in October
1993
for failing to secure
a vehicle parked within the protected
area
on April 15,
1993.
In addition, the licensee's
NAD organization
has identified three other occasions
(September
27,
30 and October
13,
1993) where vehicles
were not positively controlled
as
required
by the licensee's
Physical Security Plan.
Following
those
instances,
the licensee
implemented
several
corrective
actions which included briefing licensee
and contract personnel
on
the importance of securing designated
vehicles.
Written articles
on the control of designated
vehicles
appeared
in the weekly plant
newsletter
and
on video screens
located throughout the plant.
Interviews with security personnel
indicated that the individual
responsible for the March 5,
1994 incident
had signed
a roster
indicating that training on the requirement for controlling
designated
vehicles
had
been provided.
In addition, the affected
vehicle
had
been
equipped with a placard
on the dashboard
reminding the driver to "Remove Ignition Key Prior to Exiting
Vehicle".
The licensee
concluded that the Harch
5 incident was
clearly due to personnel
error.
The licensee's
Physical
Security Plan,
paragraph
1.6.4. l.a,
and
Procedure
Access
Control
5 Personnel
Identification,
require positive control over designated
vehicles.
The several
examples
above indicate that the licensee's
security plan is not
being properly implemented
which is considered
to be
a violation.
Violation (400/94-06-01):
Failure to properly control vehicles
inside the protected
area.
Fire Protection
(71707)
- Fire protection activities, staffing and
equipment
were observed to verify that fire brigade staffing was
appropriate
and that fire alarms,
extinguishing equipment,
actuating controls, fire fighting equipment,
emergency
equipment,
and fire barriers
were operable.
The inspectors
found plant housekeeping
and material condition of
components
to be satisfactory.
The licensee's
adherence
to radiological
controls, fire protection requirements,
and
TS requirements
in these
areas
was satisfactory.
Exit Interview (30703)
The inspectors
met with licensee
representatives
(denoted
in paragraph
I) at the conclusion of the inspection
on April 2,
1994.
During this
meeting,
the inspectors
summarized
the scope
and findings of the
inspection
as they are detailed in this report, with particular emphasis
on the Violation addressed
below.
The licensee
representatives
acknowledged
the inspector's
comments
and did not identify as
proprietary
any of the materials
provided to or reviewed
by the
inspectors
during this inspection.
No dissenting
comments
from the
licensee
were received.
19
Item Number
Descri tion and Reference
400/94-06-01
Failure to properly control designated
vehicles,
paragraph
5.c.
and Initialisms
ACFR
CFR
CSIP
E&RC
GPM
KV
NAD
NRC
NRCS
PGM
PNSC
RCCA
RVLIS-
TS
Adverse Condition Feedback
Report
Component
Cooling Water
Code of Federal
Regulations
Charging Safety Injection
Pump
Emergency Diesel
Generator
Engineered
Safety Feature
Emergency Service
Water
Environmental
and Radiological Controls
General
Procedure
Gallons
Per Minute
Health Physics
Kilovolt
Nuclear Assessment
Department
Nuclear Regulatory
Commission
Nuclear Revision Control
System
National
Weather Service
Public Address
Plant
Change
Request
Process
Instrumentation
Cabinet
Plant General
Manager
Preventive
Maintenance
Plant Nuclear Safety Committee
Rod Cluster Control Assembly
Refueling Outage
Residual
Heat
Removal
Resistance
Temperature
Detector
Reactor
Vessel
Level Indication System
Technical Specification
Volume Control Tank
4
0