ML18012A259
| ML18012A259 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 05/20/1996 |
| From: | Brady J, Shymlock M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18012A257 | List: |
| References | |
| 50-400-96-04, 50-400-96-4, NUDOCS 9606110192 | |
| Download: ML18012A259 (38) | |
See also: IR 05000400/1996004
Text
~g REGS
0
++**+
Report No.:
50-400/96-04
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900
ATLANTA,GEORGIA 303234199
Licensee:
Carolina
Power
8t Light Company
P. 0.
Box 1551
Raleigh,
NC 27602
Docket No.:
50-400
Facility Name:
Harris
1
Inspection
Conducted:
March
17 - April 27,
1996
Inspector:
ra y,
en>or
es>
ent
ector
License No.:
ate
1gne
Approved by:
D. Roberts,
Resident
Inspector
B. Crowley, Maintenance
Inspector,
paragraphs
3. 1, 3.2.4, 3.2.5,
3.2,6, 3.3.1.
>=~-9c
ym oc
,
C
~S9
Reactor Projects
Branch
4
Division of Reactor Projects
SUMMARY
Scope:
Inspections
were conducted
by the resident
and/or regional
inspectors
in the
areas of Plant Operations
which included plant status, shift logs
and facility
records, facility tours
and observations,
event followup, effectiveness
of
licensee
control in identifying, resolving,
and preventing problems;
Maintenance
which included maintenance
observation,
surveillance observation,
and review of licensee
event reports
(LERs); Engineering
which included onsite
engineering
and review of LERs;
and Plant Support which included plant
housekeeping
conditions, radiological protection,
security control, fire
protection,
emergency
preparedness,
licensee self assessment
and review of
LERs.
Results:
Plant
0 erations
Plant operations
were generally performed well.
Operators
were challenged
by
plant equipment
problems
on the shutdown
and startup related to the feedwater
isolation valve outage
and after the reactor trip.
The Plant Nuclear Safety
Committee performed thorough reviews for the root causes
of the events.
ENCLOSURE
2
'pI60biiOi92 960520
ADQCK 05000400
8
Assessments
by the Nuclear
Assessment
Section during the startups
and shutdown
were thorough.
One violation was identified for inadequate
corrective action
related to
a resin transfer event which resulted in the spread of
contamination
{paragraph 2.5. 1).
One non-cited violation was identified that
related to an inadequate
procedure for placing the pressurizer
pressure
master
controller in automatic
(paragraph
2.3. 1.1).
Maintenance
One violation was identified which involved failing to correct
a documented
deficiency
on
an installed voltmeter switch prior to using it in a
surveillance
{paragraph 3.2.2).
One non-cited violation was identified which
involved failure to follow procedure for re-qualification of maintenance
personnel
(paragraph 3.2.6).
Overall, for the activities observed,
the maintenance
and surveillance
programs
were being effectively implemented.
The activities observed
were
planned
and conscientiously
executed
in accordance
with detailed procedures.
Personnel
were qualified for the task performed,
Interface
between
maintenance
and operations
personnel
was good.
Extensive detailed trending of important parameters
is being performed
by the
system engineer for the main transformers.
The maintenance
backlogs for corrective maintenance
work tickets
and overdue
PHs has
been high.
However, the overdue
PH backlog
has
been significantly
reduced with plans to eliminate it.
A reduction plan for the
CN backlog is
being worked with a goal to cut the backlog in half during 1996.
En ineerin
Engineering
was challenged
during the period by the Technical Specification
Surveillance
Review Program
and the two forced outages.
Engineering
performed
good root cause
analyses
and supported
the operations
organization well during
the period.
Plant
Su
ort
Plant housekeeping
and the material condition of components
was satisfactory.
The licensee's
adherence
to radiological controls, security controls, fire
protection requirements,
emergency
preparedness
requirements
and Technical
Specification requirements
in these
areas
was satisfactory.
REPORT DETAILS
Acronyms used in this report are defined in paragraph
9.
1.0
PERSONS
CONTACTED
2.0
2.1
Licensee
Employees
- D. Alexander,
Supervisor,
Licensing
and Regulatory
Programs
D. Batton, Superintendent,
On-Line Scheduling
D. Braund,
Superintendent,
Security
- A. Cockerill, Superintendent,
I&C Electrical
Systems
- J. Collins, Manager, Training
- J. Dobbs,
Manager,
Outage
and Scheduling
- J. Donahue,
General
Manager,
Harris Plant
W. Gautier,
Manager,
Maintenance
- W. Gurganious,
Superintendent,
Chemistry
- H. Hamby, Supervisor,
Regulatory
Compliance
H. Hill, Manager,
Nuclear Assessment
D. McCarthy, Superintendent,
Outage
Management
- K. Neuschaefer,
Acting Manager,
Environmental
and Radiation Control
W. Peevyhouse,
Acting Superintendent,
Mechanical
Systems
- W. Robinson,
Vice President,
Harris Plant
- G. Rolfson,
Manager,
Harris Engineering
Support Services
S. Sewell, Superintendent,
Design Control
- T. Walt, Manager,
Performance
Evaluation
and Regulatory Affairs
- A. Williams, Hanager,
Operations
Other licensee
employees
contacted
included office, operations,
engineering,
maintenance,
chemistry/radiation control,
and corporate
personnel.
PLANT OPERATIONS (93702,40500,92700,92901)
The Harris Operations unit officially completed its reorganization
on
April 4,
1996.
This transition involved the renaming of positions in
the main control
room,
and the redefinition of key roles
and
responsibilities.
The Shift Foreman position was retitled Shift
Superintendent
of Operations.
A second level of supervision,
Control
Room Supervisor,
was also created.
Both positions
are filled by
licensed
SROs.
The reorganization
involved several
promotions within
the Operations unit.
The position of Manager - Shift Operations
(who
previously was the link between the control
room staff and the Manager
of Operations)
was deleted.
While it was still too early to assess
its
effectiveness,
licensee
management
believed this reorganization will
streamline
and enhance
operations
performance.
Plant Status
The plant continued in power operation until March 22,
1996.
On March 22,
1996 at 9:52 p.m., the Harris plant completed
a Technical
Specification required
shutdown after declaring both trains of automatic
load sequencers
The sequencers
had
been declared
at 3:00 p.m. that day due to previously missed surveillances
identified
by the licensee's
ongoing Generic Letter 96-01 Technical Specification
Surveillance
review effort.
The required
sequencer
testing
was
completed later on Harch 22,
1996, for Train "A" and
on Harch 23,
1996,
for train "8".
A further plant cooldown to Hode
5 was completed at 5:35 a.m.
on
Harch 24,
1996, after testing of the "8" steam generator
isolation valve indicated valve stem
and disk separation.
After repair
of the valve the plant was taken critical on Harch 29,
1996,
and went
on-line on Harch 30,
1996.
On April 2,
1996, at approximately 4:30 p.m.
power was reduced to
approximately
90 percent reactor
power to replace
a leaking relief valve
on the 38 feedwater heater.
While placing the 38 and 48 feedwater
heaters
back in service after replacement
of the relief valve, the plant
experienced
a runback from approximately
89 percent to 82 percent,
due
to a trip of the
A heater drain
pump.
The plant continued in power operation until April 25,
1996,
when the
plant tripped from 100 percent
power due to a failure of the phase
A
disconnect for unit output breaker 52-7.
The plant began startup
on
April 27,
1996,
and entered
Hode
1 at 11:40 p.m.
Shift Logs and Facility Records
The inspector
reviewed records
and discussed
various entries with
operations
personnel
to verify compliance with the
TS and the licensee's
administrative procedures.
In addition, the inspector
independently
verified clearance
order tagouts.
Logs were legible
and well organized,
and provided sufficient
information on plant status
and events.
Clearance
order tagouts
were
properly implemented.,
The inspector identified no violations or
deviations in this area.
2.3
Facility Tours
and Observations
Throughout the inspection period, the inspectors
toured the facility to
observe activities in progress,
and attended
morning status
meetings to
observe
planning
and management activities.
The tours included
monitoring instrumentation
and equipment operation, verification that
operating shift staffing met
TS requirements,
and that the licensee
was
conducting control
room operations
in an orderly and professional
manner.
The inspectors additionally observed
several shift turnovers to
verify continuity of plant status,
operational
problems,
and other
pertinent plant information.
During the shift tur novers
and meetings,
plant personnel
clearly communicated
important plant status
changes,
weather related problems,
and other deficiencies.
Overall, licensee
performance
observed
during facility tours
and observations
was
satisfactory.
Plant
Shutdown
and Startup
From Forced
Outage
The inspectors
observed
the shutdown
and startup related to the forced
outage in Harch
1996.
Operator performance
was adequate.
Several
equipment
problems during the shutdown
and startup challenged
the
operators.
In general,
they responded
appropriately
by stopping the
shutdown or startup to repair the equipment.
The
SROs in the control
room conducted mini-briefs with their control
room operators prior to
starting complicated or infrequently performed evolutions or when
unexpected
equipment
responses
were received.
The inspectors
considered
that these mini-briefs provided
good direction
and focus to the
coordination of the operator actions.
Several
evolutions that caused
the operators
some problems
are discussed
below.
Because of the nature of the forced shutdown,
did not receive the normal cleanup time that the licensee instituted
on
planned
outages.
As a result, radiological
dose rates
were higher from
the
RHR system piping in the
RAB than they would have
been if the
additional
cleanup time was available.
2.3. 1. I
Pressurizer
PORV Lifted Unexpectedly
In Hode
3 on Harch 29,
1996 at 12:55 p.m.,
an operator error occurred
when placing the pressurizer
pressure
controller in automatic.
The
operator placed the controller in automatic without matching the
reference
pressure
to the actual
pressure.
General
Procedure
GP-002,
Normal Plant Heatup from Cold Solid to Hot Subcritical
Hode
5 to Hode 3,
Revision 9, described
steps for placing the pressurizer
pressure
master
controller in automatic.
It directed the operator to verify the
pressure controller (PK-444A) was set at 2235 psig and was in auto after
actual pressurizer
pressure
reached
2235 psig.
The controller was set
below the actual
pressure.
After approximately five minutes,
one of the
pressurizer
PORVs (valve 444B) opened.
The
PORV block valve was shut
after determining that pressurizer
pressure
was below 2235 psi.
No
significant pressure
occurred.
The controller
was taken
back
to manual
and after realizing the mistake in not setting the reference
value correctly, the controller was set to the proper value, taken
back
to auto,
and
PORV 444B was unblocked (I:05 p.m.).
At approximately I:25
p.m., the
PORV opened
again.
The
PORV block valve was again closed
and
the controller was taken
back to manual.
No significant pressure
occurred.
After initial investigation
by engineering
and discussion with the
operations'shift
crew, the licensee
concluded that
some of the operators
did not fully understand
the capability and responsiveness
of the
controller to the integrator function (described
in system description
SD-100.03,
Pressurizer
and Controls,
Revision 3/2).
The master
controller circuit takes the difference
between the actual
pressure
and
reference
pressure
(Pact- Pref)
and
adds to that
a signal proportional
to the time integral of the difference
(Pact- Pref) to obtain the
controller output signal.
The purpose of the time integral function is
to allow pressurizer
sprays
and heaters
time to return pressure
to the
reference
set point prior to lowering pressure
by opening the
PORV.
After sufficient time with actual
pressure
and reference
pressure
at the
same value,
the controller was successfully
taken to auto.
This third
time involved placing the master controller in automatic,
then rapidly
placing the heaters
and sprays in automatic.
Substep
64.a in section
5.0 of procedure
GP-02 required verification
that the pressurizer
master controller was in automatic.
Subsequent
substeps
directed the operator to verify the pressurizer
heaters
in auto
(64.b)
and spray loops in auto (64.c).
The operator for the initial two
attempts,
which resulted
in
PORV lifts, indicated that
he
had placed the
master controller in automatic without subsequently
doing the
same with
the heaters
and spray loops.
There were
no instructions in the
procedure to accomplish
steps
64.a,
64.b,
and 64.c in rapid succession.
The inspectors
concluded that not having the pressurizer
heaters
and
spray valves in the controlling equation
caused
the
PORV's unexpected
opening.
Had the operator placed the spray
and heater
loops in
automatic prior to placing the master pressure controller in automatic,
the spray valves
and heaters
would have
by design controlled pressurizer
pressure
around the setpoint
and not required the
PORV to open.
The
inspectors
considered
the order of these
steps to be
a procedural
inadequacy.
The engineering
review that was performed immediately
following the second
PORV liftto assess
the operational
adequacy of the
master controller prior to continuing the startup also identified the
procedural
inadequacy.
The operator's failure to follow the procedure to match the setpoint
with current operating conditions,
the apparent
operator
knowledge
deficiency regarding the time integrator function in the pressure
controller,
and the procedural
inadequacy related to the order of
placing components
in automatic were all contributors to the unexpected
PORV lifting.
The
PORV lifts did not result in any significant plant
transient or radiological
consequences.
Licensee corrective action was
to counsel
the operators
involved, revise the procedure,
and conduct
training to address
the operator
knowledge problem.
The failure to
follow procedure
and the procedural
inadequacy
are considered
violations
of TS 6.8. 1 and are identified as
NCV 50-400/96-04-01.
This licensee
identified and corrected violation is being treated
as
a Non-Cited
Violation, consistent
with Section VII.B.I of the
NRC Enforcement
Policy.
2.3. 1.2
Rod Withdrawal Block
In Node I on March 30,
1996, at approximately 2:45 p.m., the licensee
received
an intermediate
range rod block after synchronizing the
generator to the grid.
The licensee
had experienced
some turbine
governor problems
when preparing the turbine for operation which had
delayed synchronization.
The governor
had
been repaired
and control
circuits adjusted.
The inspectors
observed
slow swings of approximately
'I
0
~.4
3-5 r.p.m.
immediately prior to synchronization.
Immediately after
synchronization
the generator
picked
up approximately
60
HW which was
slightly higher than the operators
anticipated
(30 HW).
As
a result,
a
mild RCS temperature
occurred
which necessitated
operators
to
pull rods out to compensate.
Rods were slightly higher in the core than
normal, resulting in less
rod worth.
The intermediate
range rod stop,
interlock C-l, was reached
at about the time the transient
stopped.
The inspector
observed that the operators
were not anticipating the rod
withdrawal block.
When the block was received the operators
established
that the conditions from General
Procedure
GP-005,
Power Operation
(Hode
2 to Hode 1), Revision
12, step
98, to block the intermediate
range high
flux trip were met, which also
removed the rod block.
Once
a hold point
was reached
in the power ascension
process,
the operations shift
superintendent
briefly critiqued the circumstances
surrounding the rod
block with the crew.
Points that
he made were that the crew had not
adequately
anticipated
the rod block which indicated to him that they
were not monitoring intermediate
range
power indication as carefully as
power range indication.
He pointed out that they should
have noted the
slightly higher position of the rods in the core
and discussed their
overall affect on power indication and rod worth in their mini-brief
held prior to generator
synchronization.
The inspector
concluded that
the shift superintendent's
critique of his crew's performance
was
accurate.
Onsite
Response
to Events
On April 25,
1996 at 9:07 p.m. the plant tripped from 100% power due to
a failure of the phase
A disconnect for unit output breaker 52-7.
The
licensee
made
a 4-hour report
as required
by 10 CFR 50.72 at 12:45 a.m.
on April 26,
1996.
The other unit output breaker,
52-9,
had
been taken
out of service
22 minutes prior to the trip to perform maintenance.
The
turbine tripped
on generator
lockout with a resulting reactor trip.
The licensee
found that the
A phase
disconnect
switch blade
on the 52-7
output breaker .had not fully rotated
90 degrees
into the jaws of the
receptacle.
This resulted
in a high resistance
due to reduced contact
surface
area.
With the high resistance
and doubled current from the 52-
9 breaker
being open, the heating
was increased
by a factor of 4 which
resulted
in the receptacle
melting and
a ground fault.
The licensee
replaced the disconnect
and verified that the other breakers
in the yard
were properly aligned.
Some adjustments
were necessary
on the other
breakers.
Operators
received training from engineering
on how to tell
if the knife blades
are properly aligned.
After the generator trip, the
B train emergency
bus tripped on
and
was reenergized
from the
B train
EDG.
The A train
successfully
completed
a fast transfer to the startup transformer,
therefore
the
A train
EDG was not called
on to start.
The licensee
determined that the
B
EDG started
as required
and that
a valid under
voltage condition existed
on the
B train emergency
bus.
The fast
transfer
was determined to have occurred
on the
B bus,
but not before
0
2.5
the emergency
bus tripped
on under voltage (I second
time delay
allowed).
The licensee
was still investigating
why the
8 train
emergency
bus transfer did not occur within the time limits.
The A train
EDG was found shortly after the reactor trip with local
indications that it was in the operational
mode with the maintenance
mode lights illuminated.
The'nspectors
verified at the
EDG control
cabinet that this condition existed.
The indications in the control
room were that it had tripped.
These annunciators
indicated that the
diesel
received
a stop signal.
The diesel did not receive
an emergency
start signal during the event
and should not have since the
A train
busses
had successfully
completed
a fast transfer to the startup
transformer,
and
no under voltage condition existed.
An operator in the
diesel
building at the time of the event
was at the A EDG control panel
and confirmed that the
A EDG did not attempt to start.
Having the
in the operational
mode with the maintenance
mode lights on would not
have prevented
the diesel
from starting
on
an emergency signal.
However, the licensee
conservatively declared
the
A train
because
of the unexplained indications.
A previous similar instance
occurred during
a lightning strike.
The licensee
investigated
the
situation
and determined that the stop signal coil is susceptable
to
induced voltages
which causes
the circuit to be overly sensitive.
The reactor trip caused
a pressurizer
level transient
due to the change
in
T,,.
Initially, as part of the
EOPs,
letdown was checked
and was in
service.
A short time later pressurizer
level reached
17 percent
and
letdown isolated.
Volume control tank
(VCT) level
was slightly above
the auto-makeup
level
(24 percent
vs.
20 percent)
at the time.
Charging
was at
a high flow rate
(140 gpm) which rapidly depleted
VCT inventory
and
an auto makeup signal
was initiated.
At the low level
VCT swapover
point the
VCT suction valves to the charging
pumps closed
and the
valves
opened.
The licensee's
investigation
showed that this occurred
as designed.
The investigation
showed that auto
makeup to the
VCT was
initiated but, timed out when the boric acid makeup
pump did not start.
The licensee
has tested this circuit but was not able to obtain
a repeat
of the event.
Even with auto makeup to the
VCT working, the swapover to
the
RWST would still have occurred.
Because
the trip occurred
two days before the end of this inspection
period, analysis of the post-trip review will be performed during the
next inspection period.
Effectiveness of Licensee
Control in Identifying, Resolving,
and
Preventing
Problems
Condition Reports
(CRs) were reviewed to verify that
TS were complied
with, corrective actions
and generic
items were identified,
and items
were reported
as required
by 10 CFR 50.73.
Several
Plant Nuclear Safety
Committee meetings
were attended
pertaining to the forced outage
and
The inspector determined that quorum requirements
were
met as required
by TS 6.5.2.
Discussions of the events
were thorough
'll
and probing.
The inspector also observed that
NAS personnel
were in the
control
room for the forced shutdown
and startups.
The inspector
reviewed the
NAS summary of observations
and determined that the
NAS
assessment
was thorough,
providing good self assessment.
Resin Transfer Incident
On April 10,
1996, the licensee
became
aware of a problem with resin
around
a floor drain in the waste processing
building.
This problem was
identified when attempting to determine
how two individuals,
who had
been walking down
a modification,
became
contaminated.
The individuals
had alarmed the monitors at the control point to the radiological
controlled area.
The licensee
found small
amounts of resin
around the
floor drains
on elevation
236 of the waste processing
building.
Approximately 7200 square feet of floor space
had
become
contaminated,
mostly because
the contamination
had
been tracked
around that elevation.
The licensee
established
a boundary
and decontaminated
the areas.
A
condition report was written
(CR 96-01007)
and
an investigation
was
initiated.
A resin transfer
was performed
on April 6,
1996,
several
days prior to
the resin being found around the floor drain.
The resin
bed
was part of
the liquid radwaste
processing facility.
During resin transfers,
the
spent resin is transferred
from the resin
bed pressure
vessel,
then the
vessel
is filled with new resin.
During the filling, pressure
builds
up
in the vessel.
The vessel
is vented after the filling process
through
a
vent line on the top of the vessel
that is routed to the floor drain
system.
The licensee
concluded that during the venting operation
a
small
amount of resin in the vent line was vented into the floor drain
collection system.
The pressure
from the venting process
apparently
blew some of the resin out several
other floor drains in the system.
Since the floor drain system
was considered
contaminated,
the venting
operation
spread
the contamination
outside the floor drain system.
Some licensee
personnel
were
aware of a similar incident having occurred
before.
The inspectors
reviewed
CR 95-00053 dated January
4,
1995,
which described
the previous event.
The event
was identical except that
no personnel
contaminations
resulted.
One of the corrective actions
was
to change
the operating
procedure to eliminate the use of the vent
valves.
The corrective action
was later revised to issue
a night order
to use caution
when venting the vessels
to prevent carryover of resin to
the sumps.
The licensee
also stated that the resin
beds
were at one
time a temporary modification that later became
a permanent
modification.
The inspector concluded that introducing gas into an open
system
designed for the draining of liquid was
an improper practice that had
resulted
in (I) contaminating
two personnel
and (2) the spread of
contamination to
a noncontaminated
area within the radiological
controlled area.
10 CFR 50, Appendix B, Criterion XVI, Corrective
Actions requires that measures
be established
to assure that conditions
adverse to quality,
such
as deficiencies
and defective material or
0
2.6
equipment,
are promptly identified and corrected.
This requirement is
further delineated
in Revision
18 to the licensee's
Corporate guality
Assurance
Program manual.
The failure to correct this condition after
the January
1995 event is identified as
example
one of Violation 50-
400/96-04-02:
Inadequate
Corrective Action, Failure to Correct Resin
Venting Problems.
Close Out Issues
- Plant Operations
(Closed)
IFI 400/94-12-02:
Review the Licensee's
Transition of Mork
Control Following Startup
from an Outage.
This item was originally opened to track the licensee's
process for
transitioning from a risk-based
outage
schedule to an on-line work
schedule.
Following the
1994 refueling outage,
on-line work was being
scheduled
during the
same time interval
as work listed
on the outage
schedule without the
same risk reviews associated
with the latter.
Since that outage,
the licensee
has
enhanced its on-line maintenance
schedule
by using
a risk-based
approach to conducting
system outages.
Risk significant maintenance activities were scheduled
using
a 12-week
rolling system
outage
approach
based
on
a risk matrix in accordance
with
procedures
PLP-710,
Revision 4, Mork Management
Process;
and PLP-402,
Revision 2,
NRC Maintenance
Rule Implementation
Program.
This
enhancement
was previously addressed
in NRC Inspection
Report 400/95-18.
Since the licensee
now uses
a risk-based
assessment
process
in
scheduling
both on-line and outage-related
work, the concern with the
previous practice of transitioning
between
the two configurations
has
been alleviated.
This item is closed.
2.7
3.0
3.1
Conclusion
- Plant Operations
Plant operations
were generally performed well.
Operators
were
challenged
by plant equipment
problems during shutdowns
and startups
related to the feedwater
isolation valve outage
and after the reactor
trip.
The Plant Nuclear Safety Committee performed thorough reviews for
the root causes
of the events.
Assessments
by the Nuclear Assessment
Section during the startups
and shutdown were thorough.
One violation
was identified for inadequate
corrective action related to a resin
transfer event,
which resulted
in the spread of contamination
(paragraph
2.5.1).
One non-cited violation was identified related to an inadequate
procedure for placing the pressurizer
pressure
master controller in
automatic
(paragraph
2.3. 1.1).
MAINTENANCE - (62703,
61726,
92700,
92702,
92902)
Hai nten ance Observati ons/Revi ews
The inspectors
observed/reviewed
portions of selected
maintenance
activities
as detailed
below to determine if these activities were
conducted
in accordance
with Technical Specifications
(TS), the Final
Safety-Analysis
Report
(FSAR), approved
procedures,
and appropriate
industry codes
and standards.
In addition to verification that
procedures
were followed and
TS requirements
were met, the inspectors
verified that personnel
were knowledgeable
and qualified, that post
maintenance
testing
(PHT) was performed
and
was appropriate,
that
required clearance
requirements
were met,
and that calibrated
measuring
and testing
equipment
was used.
3. 1.1
WR/JOs
AJAW 002 and
AWAY 002 - Inspect
and Calibrate the following 6.9KV
AC Distribution Ground Alarm Relays
- (Tag 1A-10:006):
Bus Tie lA to
1A4
Bus Tie lA to
1C
Bus Tie
1D to lA-SA
Bus Tie
1D to 1-4A
This calibration was accomplished
in accordance
with Process
Instrument
Calibration
(PIC) Procedure
PIC-E016,
Revision 6, Gould-Brown Boveria
Ground Fault Relay
GR-5 Calibration.
3.1.2
WR/JO
ADDG 001 - Preventive
Maintenance
on Air handling Unit 480
VAC
Motor - (Tag lAV-A93X:005):
This routine Preventive
Maintenance
(PH) was performed in accordance
with procedure
PH-E0009,
Revision 5,
480
VAC Motor Preventive
Maintenance.
~
~
~
~
3. 1.3
WR/JO AEHR 001 - Preventive
Maintenance
on Limitorque Operator for HVAC
Motor Operated
Valve
(HOV) - (Tag 1CZ-35:002):
This routine
PH was performed in accordance
with procedure
PH-I0020,
Revision 8, Limitorque Operator Inspection.
3. 1.4 WR/JO ABSN 002 - Preventive
Maintenance
on Condenser
Vacuum System
480
VAC Load Breaker - (Tag 1D3-3D):
This routine
PH was accomplished
in accordance
with procedure
PH-E0012,
Revision 9,
480
VAC ABB Type
LK Load Center Breaker
and Cubicle P.M.
3.1.5 Main Transformer Maintenance
The inspectors
reviewed the maintenance
practices for the main
transformers.
The following summarizes
the results of this review:
are maintained
by the licensee's offsite
Transmissions
Department
using Substation
Maintenance
Standards
(SHSs).
However, the site system engineer for the switchyard
coordinates
Transmissions
Department
maintenance activities for
the transformers with the site
and tracks results of the
Transmissions
Department
PHs.
are Maintenance
Rule components.
In
addition to tracking the Transmissions
Department
PH results,
the
Systems
Engineer performs weekly walkdowns in accordance
with site
10
procedure
THM-117, Revision 3, Plant Engineer
Walkdown,
Observation,
and Assessment
Procedure,
and records
and trends
a
number of parameters
for the transformers.
Parameters
trended
include, oil levels, winding/top oil temperatures,
oil dielectric
strength,
and various
gas concentrations.
The trending is
accomplished
in accordance
with site procedure
ADM-NGGC-0101,
Revision 2, Maintenance
Rule Program.
The inspectors
noted the following SHSs which defined the
Transmission
Department
program for PM of the transformers:
SHS-01 - Equipment Maintenance
Schedules
SHS-02
- Monthly Substation
Inspections
SHS-03-1
- Inspections
and Maintenance of Stationary
Power
Transformers
3. 1.6 Maintenance
Indicators
The inspectors
reviewed licensee
Haintenance
Indicators for the period
January
- Harch,
1996.
The following two indicators
were reviewed in
greater detail
and discussed
with maintenance
management:
Overdue
PHs - In January
1996, the backlog of overdue
PMs was
approximately
250.
The licensee
recognized this to be
a problem
and initiated corrective actions to evaluate
the significance of
the
PM items overdue
and eliminate the backlog.
The following
summarizes
the results of reviews
and discussions
with licensee
maintenance
management:
Nuclear Assessment
H-HA-96-01-12 identified the backlog of overdue
PHs
as being
a problem.
The problem
and corrective actions
are
documented
in
CR 96-0139.
Based
on discussions
with the
Maintenance
Manager,
the excessive
PM backlog occurred
due to
postponement
of work because
of (1) loaning maintenance
personnel
to the Robinson Plant for outage work, (2) extensive
pre-outage
effort for the Harris
RF06 outage,
and (3) the forced outage
immediately after RF06.
The backlog consisted of routine
PH tasks
and not TS or regulatory
required tasks.
An engineering
evaluation
determined that no
safety issues
existed
because
of the backlog.
Reducing the backlog of overdue
PHs has
been
a high priority, with
weekly status
reports provided to plant management.
By April 1,
1996,
the backlog
had
been
lowered to 22, which showed significant
progress
toward elimination.
Corrective Maintenance
(CM) Backlog -
In January
1996, the
backlog
was approximately
800 work tickets.
On April 1,
1996, the
backlog
was still 809 work tickets.
The licensee
has also
11
3.2
recognized
the
CH backlog to be
a problem
and
has developed
plans
to work the backlog off to approximately
400 by the end of 1996.
Based
on discussions
with the Haintenance
Hanager,
the causes
for
the high
CH backlog are the
same
as for the high overdue
PHs.
The backlog
has
been prioritized with the most important jobs
(emerging work, maintenance
rule items,
open work-around items,
main control board items, etc.)
planned first.
Two backlog items,
in addition to routine work, are being assigned
to each work crew
with a goal of reducing the backlog
by approximately
64 tickets
per month.
By April 15,
1996, the backlog
had
been
reduced to 740
work tickets.
Surveillance
Observation
3.2.1
EST-724,
Shutdown
and Control
Rod Drop Test
The licensee
performed hot control rod drop testing using Engineering
Surveillance Test
EST-724,
Shutdown
and Control
Rod Drop Test Using
Computer,
Revision 4, to address
NRC Bulletin 96-01, Control
Rod
Insertion
Problems.
The inspector witnessed
the dropping of control
bank
A which was associated
with the higher burnup Westinghouse
Vantage
5 fuel.
The licensee
used
a contractor with sophisticated
computerized
data acquisition capabilities to record the data.
All of the rods in
the bank dropped within the required time of 2.7 seconds
(TS 3. 1.3.4).
The G-41 rod had the highest time of 2.288 seconds.
The inspector
observed that rebound occurred for this bank, indicating that sticking
problems
were not occurring.
The inspector
reviewed the
EST-724 results
which showed that the remaining rods were all less
than 2.0 seconds
in
drop time except rod J21 which took 2.068 seconds
to drop.
The
inspector
concluded that all rods met the Technical Specification
requirements.
The licensee
submitted the results of the testing to the
NRC on April 8,
1996, in a response
to the
NRC Bulletin.
The response
was consistent
with what the inspector
had observed.
3.2.2 HST-I0320, Revision 9, Train
B Solid State Protection
System Actuation
Logic 5 Haster Relay Test.
On April 2,
1996, the inspector
observed portions of this procedure
which tested logic and permissives
associated
with the "B" train SSPS.
This procedure satisfied,
in part, surveillance
requirements
contained
in TS Tables 4.3-1
and 4.3-2.
Procedure
section 7.5 directed operators
to verify the availability of Permissive
P-4 (Reactor Trip permissive
that actuates
a turbine trip and enables
the safety injection block and
reset logic,
among other items).
This was accomplished
by shutting the
"B" train reactor trip bypass
breaker,
depressing
an auto shunt trip
pushbutton,
verifying the "B" train (main) reactor trip breaker
opened,
and measuring
voltage across
two contacts
in the reactor trip breaker
switchgear cabinet.
The licensee
had previously installed
a permanent
voltmeter (hard-wired into the circuit) to take the voltage reading.
Step
28 directed operators
to verify that the meter read
48 volts (or
between
37 and
49 volts) when its selector switch was placed in the
"BY"
12
position.
While performing this step during the initial test run on
April 2, technicians
obtained
readings of zero voltage.
This indicated
that either the voltmeter switch contact
had not closed properly, or the
P-4 permissive
was not available.
The P-4 permissive
was appropriately
declared
inoperable until it could be satisfactorily tested.
Believing
that the problem was with the switch, technicians
used
a portable
voltmeter (appropriately calibrated)
and measured
the correct voltage
across
the contacts.
This confirmed that the earlier problem was with
the permanent
voltmeter selector switch. 'owever,
the P-4 permissive
remained
because
the procedure'pecified
the use of the
permanently installed voltmeter and did not provide allowances for using
portable digital voltmeters.
The inspector
was informed by the licensee that
a deficiency tag
had
been previously initiated for the voltmeter selector switch.
This tag
was dated
February 2,
1996.
In reviewing the associated
work ticket,
WR/JO AA(Yl, the inspector
noted that it had identified
a similar
instance
where the switch contacts failed to close
on demand during this
procedure.
The work ticket had
recommended
the switch be replaced,
and
that the work be conducted
during the next plant outage
due to the risk
associated
with a plant trip.
Discussions with plant personnel
indicated that the ticket was coded for the next refueling outage.
In
the interim, technicians
had planned to work around the deficiency by
"jogging" the switch until proper contact closure
was
made
and the
acceptable
voltage obtained.
Discussions with personnel
indicated that
this practice
had worked in the past,
however, it did not work on
April 2,
1996.
Consequently,
the licensee
had to initiate a temporary
procedure
change to allow the use of the portable voltmeter.
The time
associated
with the procedure
change required that the technicians
reopen the reactor trip bypass
breaker,
and continue through
a 48-hour
TS limiting condition for operation
(LCO) for the P-4 permissive.
Additionally, because
of the delays during the test
and the time
associated
with restoring the breaker alignment,
the two-hour limit for
having the bypass
breaker shut
was exceeded,
placing the licensee
in a
six-hour shutdown action statement
in accordance
with TS
This action statement
was exited within minutes
when the bypass
breaker
was opened.
The procedure
was later changed
and the test re-performed.
During the
second
attempt,
the voltage reading slightly exceeded
the upper limit of
49 volts using the portable meter.
Licensee
engineering
personnel
evaluated this voltage reading to be acceptable.
The P-4 permissive
was
then declared
and the 48-hour
LCO exited.
The selector switch
was replaced later that day
and the
HST was re-performed with
satisfactory results.
The inspector
concluded that this test evolution involved several
examples of negative
performance.
First,
a previously identified
deficiency
had
been
ignored
by technicians
who decided to use the
permanent
voltmeter anyway.
Secondly,
the switch replacement
had
been
coded for the refueling outage
due to the risk associated
with possibly
tripping the plant.
The licensee
had completed
a week-long forced
13
3.2.3
outage
on March 29, just days before this test
was scheduled,
yet the
work ticket was not considered for work during the shutdown.
10 CFR 50, Appendix B, Criterion XVI, Corrective Actions requires that
measures
be established
to assure
that conditions
adverse to quality,
such
as deficiencies
and defective material
or equipment,
are promptly
identified and corrected.
This requirement is further delineated
in
Revision
18 to the licensee's
Corporate guality Assurance
Program
manual.
The failure to promptly correct the deficiency associated
with
the selector
switch contributed to the licensee
entering
two TS
LCOs and
is contrary to those requirements.
This is identified as example
two of
Violation 50-400/96-04-02:
Inadequate
Corrective Action, Failure to
Correct Voltmeter Switch Deficiency.
OST-9018T,
Revision 0, Test of the
A Train Sequencer
Blocking Functions,
18 Month Interval.
This temporary test procedure
was developed to test several
blocking
relays in the emergency
safeguards
sequencer
panels.
These
relays'unction
were to ensure that normal process
demand signals
were blocked,
thereby preventing non-essential
or undesirable
safety loads from
energizing
and overloading the emergency diesel.
The licensee
had
previously identified (as part of the review per Generic Letter 96-01,
Testing of Safety-Related
Logic Circuits) that these
blocking relays
had
not been properly tested.
The inspector
observed testing activities
under the "A" train procedure,
although
a similar procedure
was
developed to test the "B" train components
which had also
been missed
previously.
The fact that these
components
had not been previously
tested
required that the licensee
enter
TS
which allowed
24
hours to complete the testing or declare
the affected
system inoperable.
After 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />,
because
both trains of the emergency
sequencer
were
involved, the licensee
entered
TS
This ultimately lead to a
TS-required
shutdown
when delays
associated
with the procedure
and other
unrelated plant equipment
problems occurred
as discussed
in paragraph
2.1 of this report.
The inspector
observed
good workmanship during the procedure.
Steps
were appropriately followed,
and the procedure
accomplished
the stated
goal of verifying proper relay actuation.
One stumbling block occurred
during the initial test while performing Section 7.4.
While all other
continuity readings
had
been
measured
in ohms (resistance),
one of the
data points in Section 7.4 was specified in voltage (potential).
The
procedure's
authors
expected to see potential
across
the contacts
associated
with this particular step.
During the test,
technicians
measured
zero volts (DC), requiring
an evaluation
and procedure rewrite
to specify acceptance
criteria in ohms.
This correction
was
made
and
the procedure
completed satisfactorily later that night after the plant
was shut down.
The delays
associated
with the error in Section 7.4 may
have contributed to the forced shutdown,
however, this complex procedure
was well coordinated
and implemented.
1 4
3.2.4
HST-
T-I0026, Revision 6,
B Narrow Range level
(L-0484)
Calibration
WR/JO
AAGS 001 - Calibration of Steam Generator
(SG)
2B Narrow Range
Level
Loop L-0484 Protection
Set I covered the surveillance of the
2B SG
Narrow Range
Level
Loop to meet
TS 3/4.3. 1, 3/4.3.2,
and 3/4.3.3.6.
Requirements
were also specified in paragraphs
3. 1.17, 7.2.2.2.3.10
7.3.2.2.10.1
and 15.0.6 of the
FSAR.
3.2.5 HST-I0270, Revision 4,
Lo-Lo T., P-12 Interlock (T-0432) Operational
WR/JO AFZA 017 - Operational
Check of Loop T-0432 Lo-Lo T., P-12
Interlock covered the surveillance of Loop T-0432 Lo-Lo T., P-12
Interlock to meet Table 4.3-2,
Item 10b, of the TS.
Requirements
were
also specified in paragraphs
3.1. 17, 7.3.2.2. 10. 1 and 15.0.6 of the
3.2.6
HST-
.
.6 HST-I0126, Revision 4, Main Steamline
Pressure,
Loo
(P-0475)
Operational
Test
e,
oop
-
),
WR/JO AASH 017 - Operational
Test of Hain Steam
(HS) Line Pressure
Loop
1 P-0475 Protection
Set III covered the surveillance of the
HS Line
Pressure
Loop
1 P-0475 Protection
Set III to meet
TS 3/4.3.1, 3/4.3.2,
and 3/4.3.3.6.
Requirements
were also specified in paragra
hs 3. 1. 17
7.3.2.2. 10. 1 and 15.0.6 of the
FSAR.
Du
'
'
ai
e
in paragraphs
During observation of the surveillance activities
d t
'1
d
'
,
and 3.2.6 above,
the inspectors
reviewed qualification
records for IRC technicians
performing the surveillances.
A
gualification Checkout
Card System
(gCC)
was
used to
ualif
and
document qualifications.
Inn accordance
with Training Program Procedure
-102, Revision 2,
Conduct of On-The-Job Training
and Task
Performance
Evaluation, re-qualification review was re
'
years
(maximum 30 months).
equire
every two
The qualification status for all personnel
with'
maintained
b
the suerv'n
a wor
crew was
y
e supervisor of the crew.
Training procedures
provided
kee t
a gualification Checkout
Card matrix as
a tool for th
~
~
~
o
or
e supervisor to
not
a mandator
re
p
rack of qualifications for his crew.
The matrix
t
1
d
y
equirement.
In reviewing the matrix for the supervisor
ix was
a
oo
an
of the personnel
performing the surveillances
of par agraphs 3.2.4,
3.2.5,
and 3.2.6 above,
the inspectors
noted that
2 technicians
had
exceeded
the 30-month re-qualification review.
One of the two had
performed
one of the surveillances
observed.
His re-qualification
review was
due in April 1994.
The other technician
was due for re-
qualification in June
1995.
For the individual due in June
1995,
within
official records
showed
he did receive the re-qu 1'f
in the required time,
even though the supeqvisor's
matrix showed
otherwise.
No records
were found to show the other individual had
received his re-qualification review.
15
The licensee
issued
CR 96-1001 to document this issue
and took immediate
corrective actions for this problem.
The following summarizes
the
corrective actions taken
and the results
obtained
by the licensee:
The technician
was not allowed to perform any work that required
OCCs until the official Document Control records
could be reviewed
to determine if records
could be retrieved to support his re-
qualification review.
No records
were found.
Therefore,
the re-
qualification review was performed to bring the individual's
qualification up to date.
No problems
were identified in the re-
qualification review.
The technician's training records
were reviewed
and compared with
other
I&C technicians
on similar job responsibilities.
The
records
showed his training was in alignment with his peers
and
continued participation in routine
IEC training and attendance
in
appropriate
specialty training.
In addition, maintenance
management
reviewed the individual's work practices
over the
period in question
and found no evidence of degraded
performance.
Maintenance
and Training supervisors
reviewed the maintenance
staff qualification status
and identified no additional
occurrences
of lapsed qualifications from not performing prompt
re-qualification reviews.
In addition, Training management
reviewed qualification status for the Environmental
and Radiation
Control personnel,
who have re-qualification requirements
similar
to the Maintenance
Department,
and found no errors.
The Training organization
began
a process
in January
1996,
of
listing all qualifications
on the station's
computerized training
tracking system
and considered
the loading process
would have
identified the one error found above
and corrections
would have
been taken.
The new computerized
system will enable
anyone to
view the qualification record
and status
at any time and can
be
used to automatically forecast expiration dates
and
keep
supervisory
personnel
informed of qualification status.
The licensee is currently reviewing the existing two-year re-
qualification process
and considering replacing the two-year
across-the-board
requirement with a process
w'hich includes
a
routine training/retraining
program for critical (to safety or
operations),
infrequently performed,
and difficult tasks.
This
review and resulting actions
are expected to be complete
by June
1996.
The inspectors verified the above corrective actions
by reviewing the
following documentation:
MEMO to File dated April 18,
1996
gualification Review Form dated April ll, 1996 for technician
whose qualification had lapsed
I
Condition Report 96-01001
16
Training Record history for technician
whose qualification had
lapsed
The technician that performed the observed
surveillance
was also not re-
qualified.
Failure to follow procedures
for Re-qualification
Review is
identifed
as
a violation of 10 CFR 50, Appendix B, Criterion V.
This
ailure constitutes
a violation of minor significance
and is being
treated
as
a Non-Cited Violation, consistent with Section
IV of the
NRC
This item is designated
as
NCV 50-400/96-04-03,
Failure to Follow Procedure for Re-qualification of Maintenance
Personnel.
This item is closed.
3.3
Close Out Issues
- Maintenance
3.3.1
(Open)
VIO 400/95-17-02:
Failure to Provide Adequate Instructions for
Repairing Isolation Valve Pressure
Sealing
Surfaces
This violation involved failure to provide adequate
procedures for
repair of Hain Feedwater
Isolation Valve 1FW-217 and Pressurizer
PCV-444B.
The cause of the problem was attributed to a failure to
properly implement Regulatory
Guide
(RG) 1.33,
Appendix A.
The inspectors
reviewed the following documentation
to verify that
appropriate corrective actions
had
been identified and performed:
Procedure
CH-H0204, Revision 2, Hain Feedwater
Isolation Valves
HFIVs.
(MFIV), which provided appropriate instructions for repa'r f
1
0
A Maintenance
memorandum
and flowchart, dated January
9,
1996,
which implemented
a review process
to determine
when procedures
are required
by
If a procedure is required for a
maintenance activity and is not available,
one will be developed
before the maintenance
is allowed to proceed.
Internal
memorandum,
dated January
9,
1996,
documenting review
with maintenance
and training personnel
of the causes
and
circumstances
of this violation.
Procedure
CH-H0206, Revision 0, Pressurizer
Power Operated Relief
Valve (PORV), which provided appropriate instructions for
disassembly,
inspection,
and re-assembly of PORYs.
Action Item 5 of CR 95-03003,
which documented
review of
maintenance activities which could affect performance of safety-
related
equipment in accordance
with
RG 1.33 to identify those
components
requiring detailed procedures.
The review included
greater
than 20,000
EDBS safety-related
tags to determine if
procedures
existed.
In addition, maintenance
procedure lists from
other licensee sites
and other utilities were reviewed.
This
0
17.,
effort identified the need for an additional
18 procedures.
At
the time of this inspection,
only a few of these
procedures
had
been written.
However,
as noted
above,
maintenance
on the
components will not be allowed until procedures
are written and
issued.
3.4
Action Items 6, 7, 8,
and
9 of CR 95-03003,
which documented
review of procedures
in other areas to ensure
proper
implementation of RG 1.33
and
TS 6.8. l.a.
This violation remains
open pending further reviews to verify issuance
of the additional
18 procedures
identified by the licensee's
review.
Review of LERs - Haintenance
(Open)
LER 400/96-002:
Failure to Properly PerForm Technical
Specification Surveillance Testing.
This
LER was supplemented
twice during the inspection period
as
additional findings were discovered
by the licensee
during
a continuing
review per Generic Letter 96-01.
LER Supplement
96-02-02
was issued
on
Harch 22,
1996
and discussed
three additional
requirements.
These involved logic testing for control
room ventilation
fans which start
on high radiation signals, ventilation dampers
associated
with the reactor auxiliary building electrical
equipment
protection
room,
and trip actuating device operational
testing for the
main feedwater
pump trip following safety injection actuation.
LER
Supplement
96-02-03
was issued
on April 10 and discussed
two additional
missed requirements.
One of these
involved
a "channel
out of service"
alarm test or control
room annunciation verification for four radiation
monitors.
The second
involved the blocking relays associated
with the
emergency
safeguards
sequencers.
This latter item was discussed
in
report paragraph 3.2.3.
Hecause
the plant entered
and later
completed
a TS-required plant shutdown
due to the missed
sequencer
surveillance
requirements,
the licensee
reported
these
events
under the
same
LER.
The inspector determined that the
LER supplements
appropriately
described
the circumstances
for these
events.
and its
supplements will remain
open until the licensee
completes its Technical
Specification Surveillance
Review program later this year.
At that time
the inspector will review the licensee's
long-term corrective actions
for the deficiencies
and causes
noted.
3.5
Conclusion
- Haintenance
One cited violation and
one non-cited violation was identified.
The
cited violation involved failing to correct
a documented
deficiency
on
an installed voltmeter switch prior to using it in a surveillance
(paragraph 3.2.2).
The non-cited violation involved failure to follow
procedure for re-qualification of maintenance
personnel
(paragraph
3.2.6).
4.0
4.1
4.1.1
18
Overall, for the activities observed,
the inspectors
concluded that the
maintenance
and surveillance
programs
were being effectively
implemented.
The activ'ities observed
were planned
and conscientiously
executed
in accordance
with detailed
procedures.
Personnel
appeared
to
be well qualified for the task performed.
Interface
between
Maintenance
and Operations
personnel
was good.
Extensive detailed trending'f important parameters
was being performed
by the system engineer for the main transformers.
The maintenance
backlogs for corrective maintenance
work tickets
and
overdue
PMs has
been high.
However, the overdue
PM backlog
has
been
significantly reduced with plans to eliminate it.
A reduction plan for
the
CH backlog is being worked with a goal to cut the backlog in half
during 1996.
ENGINEERING (37551,
40500,
92700,
92903)
Onsite Engineering
Isolation Valve Problem
On March 19,
1996, the system engineer
had noted
a flow reduction trend
on the main feedwater line.
The trend
showed
a change
in the split in
flow between
the normal feedflow path to the steam generator
and the
bypass flow through the
AFW feed line path.
This split is normally 80
percent
through normal feedwater
and
20 percent through the bypass line
but on March 4,
1996,
had changed to 70/30.
The trend indicated that
the reduction
had occurred
when the feedwater isolation valve was
stroked in accordance
with surveillance
procedure
OST-1018.
Condition
Report 96-00774
was written to document this problem.
On March 22,
1996, during the forced shutdown,
the licensee
cycled the valve and
determined that there
was
a problem.
The licensee
drained the
B steam
generator
and disassembled
the
B feedwater isolation valve (a wedge gate
valve).
The valve stem was found broken just prior to where the stem
and disc connect.
Condition Report 96-00792
was initiated to document
the problem
and Engineering Service
Request
96-00168
was initiated for
engineering
assistance
in determining the cause of the failure.
Metallurgical analysis of the valve stem indicated
low cycle fatigue
as
the failure mechanism.
The analysis
also confirmed that the stem was
made from 17-4 ph stainless
steel
which had
been properly heat treated.
The stem was part of the original installation prior to 1986
and
had in
excess of 133 valve cycles.
Inspection of the valve, disc and bonnet
revealed
marks where the disc and bonnet
had
come in contact.
The valve
is not designed for the disc and bonnet to come in contact,
but is
designed for the stem to backseat
in the bonnet under hydraulic
pressure.
The contact points were offset from the valve centerline
by
approximately
1/4 inch.
The valve is also oriented approximately
50
degrees
from vertical.
The licensee
consulted with the valve
manufacturer
and
an engineering
consulting
company.
The licensee
19
concluded that the following factors
had contributed to the failure of
the stem:
1.
The backseat
was deeper
than normal in the bonnet.
2.
With the valve oriented at 50 degrees
from vertical, the disc was
riding on the lower side valve disc guides.
These
two resulted
in the disc hitting the bonnet in a 1/4 inch offset
from center causing
a bending
moment
on the stem.
Computer modeling by
the engineering
consultant
confirmed that the bending
moment
on the stem
was sufficient to have caused
low cycle fatigue failure based
on the
number of cycles the stem
had received.
The crack initiation point on
the stem identified by the metallurgical failure analysis
matched with
that predicted
by the computer analysis.
The licensee,
after consultation with the valve manufacturer,
modified
a
replacement
stem
based
on the above conclusions
and measurements
taken
in the field to ensure that. the bonnet
and disc would not
come in
contact.
The modified stem design did not change
the stem weak link
analysis.
The valve was reassembled
with the modified stem
and was
checked to make sure the disc and bonnet did not come in contact
when
the stem was in the backseat.
The licensee's
analysis
showed that the other two feedwater
isolation
valves
have relatively new stems with approximately
20 cycles each.
They were both disassembled
in the last two years
due to unrelated
problems.
The licensee
stated that valve disc to bonnet contact
marks
were not evident
when the other two valves
were disassembled.
The inspectors
reviewed the metallurgical failure analysis,
observed
the
failed stem under the microscope
at the licensee's
metallurgical lab,
and discussed
the failure mechanism with the metallurgist.
The
inspectors
viewed the disassembled
valve and valve parts,
including the
stem,
and confirmed that the disc and bonnet
had
made contact.
The
inspector
attended
the
PNSC meeting where the root cause of the failure
was discussed.
The inspector
concluded that the licensee
had done
a
good job of investigating the failure.
4.1.2 Auxiliary Feedwater
Flow Control Valve Deficiency
The inspectors
reviewed system engineer activities associated
with the
three automatic flow control valves for the motor-driven
AFW pumps.
Each valve controls
AFW flow to one of the steam generators
and is in
the
AFW flowpath upstream of the motor-operated
AFW isolation valves
near the containment building penetrations.
Operators
used the flow
control valves during the forced outage
in Harch
1996
and in prior
outages
to control
steam generator levels within their required
operating
bands.
After entering
Hode
4 on Harch 23,
1996, operators
noted that two of the three valves failed to open under high
differential pressure
(AFW pump discharge
pressure
minus steam generator
pressure).
Operators
had worked around this problem in the past
by
20
4.2
4.2.1
shutting the motor-driven
AFW isolation valves,
thereby reducing the
differential pressure
across
the flow control valves.
The valves would
then
open allowing operator control of AFW flow.
The
AFW system engineer
had
been investigating this operator work-around
just prior to the recent plant shutdown
and
had documented this in a
CR
after discussing it with off-shift operators 'the week before.
The newly
assigned
engineer
had just recently
become
aware of the sticking problem
and
had raised operator
awareness
to the point where they should provide
feedback
on any related recurrences.
After the sticking in Harch, the
engineer
decided that
a special
surveillance test should
be performed
prior to exiting Hode
4 to determine
SG pressures
under which the valves
were sticking.
This testing would provide data points below which the
valves would have to be administratively maintained full open or the two
motor-driven
AFW pumps would be declared
Such
a test
was
developed
and completed during plant heatup activities at the
end of the
Harch outage.
Based
on the results of this test
(EPT-711,
Revision 0,
Hotor Driven Auxiliary Feedwater
Pumps
Flow Control Valve Stroke Test),
plant personnel
determined that the two AFW pumps should
be declared
any time these
valves were less
than full open with steam
generator
pressures
less
than 320 psig.
The inspectors
considered this deficiency to represent
a significant
operator work-around.
It required that operators
perform special
manipulations to open the flow control valves in Hode
4 or Hode
3 while
at low steam generator
pressures
with the
AFM pumps running.
These
manipulations
(shutting motor-operated
isolation valves prior to opening
flow control valves)
could
be pe}formed from the main control
room and
were covered in auxiliary feedwater
system operating procedures.
The
new system engineer's
efforts in raising the awareness
of these
deficiencies to plant management's
attention
was commendable.
At the
end of the inspection period, the system engineer
had communicated
the
sticking problems to the valve vendor for consideration
as
a potential
application or design deficiency.
Review of LERs - Engineering
(Closed)
LER 94-003:
Improperly Analyzed Single Failure in Emergency
Service Mater
This
LER reported the event that was the subject of Violation
400/94-21-01.
The inspector reviewed the
LER corrective actions
and
determined that they were the
same
as those for the violation.
The
violation was closed in paragraph
4.3 below.
This item is closed.
4.2.2
(Open)
LER 400/96-006:
Feedwater Isolation Valve Stem
and Disk
Separation.
This
LER was related to the forced shutdown discussed
in paragraphs
2. 1
and 4. 1. I above.
The licensee
plans to revise Corrective Haintenance
Procedure
CH-H0204 by August 31,
1996 to include verification that the
21
4.3
feedwater isolation valve disc does not strike/contact
the bonnet.
This
item remains
open.
Close Out Issues
- Engineering
4.3.1
(Closed)
VIO 400/94-21-01:
Inadequate
Design Control for
System/CSIP
Coolers
This violation was issued
because
two independent trains of emergency
service water were not achieved for all postulated
single failure
conditions.
With the existing valve lineups, train cross-connects
existed at each of the charging
pump coolers which would have allowed
backflow of hot water causing
pump damage
when the single failure of
auxiliary reservoir return valve
1SW-270 was postulated.
The licensee
corrected this problem by closing the charging
pump cooler cross-train
valves.
The Emergency Service
Water system flow drawings
CPL-2165-S-
0547
and CAR-2165-G-047 were revised to reflect the
new positions
as
well as Operating
Procedure
Service
Water System,
Revision 6.
The inspector field-verified the valve positions, verified that the
drawing changes
were made,
and verified that the operating
procedure
had
been
changed.
Single failure training was given to the onsite
engineers.
The inspector reviewed the attendance
records for the
training and concluded,
based
on sampling, that the engineers
received
the training.
The licensee
also performed
a review of other decay heat
removal
systems for similar cross-connect'problems
and self-initiated
a
Service
Water System Operational
Performance
Inspection.
No other
similar problems
were found.
This item is closed.
4.3.2
(Closed) IFI 400/94-12-01:
Review of Licensee Activities to
Upgrade/gualify
AFW MOVs for Higher Thrust Values
This item was
opened
because
the licensee
had increased
the torque for
several Auxiliary Feedwater
Valves above the calculated
long term
allowable.
The short term values
(extended thrust ratings)
were
determined
through engineering
evaluation
PCR 7284 to be acceptable
until the end of refueling outage
6 (October 1995).
The valves were
qualified for
a higher thrust rating on
a short term basis to ensure
valve closure.
This item was
opened to track the licensee
long term
resolution
and ensure that long term valve damage
would not occur.
The inspector
reviewed Engineering Service
Request
ESR 95-00021 which
evaluated this condition for long term acceptability.
The
determined that
a 98 percent
closed torque switch bypass
would allow the
torque switches to be set at
a minimum value which removed
them from
short term operability status.
The valve disc will cover the valve
seating
surface
by 98 percent of the stroke.
The new setup
was
determined to allow the full output of the
MOV motor to isolate flow but
does not over thrust the valve when seating it.
Two valves,
lAF-55 and
lAF-74, had
been set at the higher thrust ratings although several
others
had
been qualified for it.
The inspector
reviewed the work
request/job
orders that implemented the changes for the subject valves
(WR/JOs
95-ABKH1, 95-ABKI1, 94-AHUZ1, 95-ABMU1, 94-AHWB1, 94-AHWB1, 95-
22
4.3.3
ABNWl, 95-ABNTl, 94-AHWC1, 95-ABNU1, 94-AHWDl).
The work orders reset
the torque values for the two valves
and set the torque switch bypass
for all the valves.
The documentation
supported that the described
changes
had
been
implemented.
The two valves that had their thrust reset,
post-modification tested
using
a dynamic test at design basis
differential pressure
conditions per Engineering Periodic Tests
EPT-301,
revision 1/1, for 1AF-55 and
EPT-302, revision 1/2 for 1AF-74.
In
addition,
lAF-93 was dynamically tested.
The inspector
reviewed the
test results
and determined that they met the test criteria.
The other
valves,
which were identical,
were diagnostically tested
under static
conditions.
This item is closed.
(Closed)
IFI 400/94-17-02:
Biofouling Potential
in
ESW Systems.
This item was
opened
because
the licensee
found, some asiatic
clams in
the service water intake structure.
A program of monitoring the
system through periodic inspection of components
had
been ongoing.
At
the time the
ESW system
was not being chlorinated,
although the
circulating
and normal service water systems,
and the cooling tower
basin were under continuous chlorination.
The licensee clarified/revised their commitment in relation to
chlorination in an April 16,
1996 submittal.
The revision was based
on
experience
with intermittent chlorination with sodium hypochlorite.
The
change did not revise what systems
would be chlorinated,
but did
identify action that was being taken to control
and identify the spread
of the asiatic clams.
This included inspecting the intake structure
where the clams were first identified.
The inspector verified that
procedure
PLP-620,
Service
Water Program
Revision
1, contained that requirement.
The inspector discussed
the
inspection results with licensee
personnel
who indicated that there
have
been
no clams found in the service water systems,
only in the intake
structure.
They stated that when the clams are found during the
inspection,
they are removed.
Procedure
PLP-620 also requires safety-
related
heat
exchangers
to be inspected.
There
has
been
no evidence of
biofouling from these
inspections.
The inspector concluded that their
was
no evidence that the clams
had spread into the service water systems
and that the licensee
program
was effective in preventing their spread.
This item is closed.
4.4
Conclusion
- Engineering
Engineering
was challenged
during the period by the Technical
Specification Surveillance
Review Program
and the two forced outages.
Engineering
performed
good root cause
analyses
and supported
the
operations
organization well during the period.
0
E
j
5.0
5.1
5.2
23
PLANT SUPPORT
(71707,
71750,
40500,
92700,
92904)
Plant Housekeeping
Conditions
The inspectors
found plant housekeeping
to be adequate.
Radiological Protection
Program
The inspectors
reviewed radiation protection control activities to
verify that these activities were in conformance with facility policies
and procedures,
and in compliance with regulatory requirements.
The
inspectors
also verified that selected
doors which controlled access
to
very high radiation areas
were appropriately locked.
Radiological
postings
were likewise spot checked for adequacy.
On April 10,
1996,
the licensee
had two personnel
contamination
events
which were related
to the resin transfer
issue
discussed
in paragraph
2.5. 1.
Radiological
protection personnel
did
a good job of containing
and cleaning
up the
contamination.
5.3
5.4
Security Control
During this period, the inspectors
toured the protected
area
and noted
that the perimeter
fence
was intact
and not compromised
by erosion or
disrepair.
The fence fabric was secured
and barbed wire was properly
installed.
Isolation zones
were maintained
on both sides of the barrier
and were free of objects which could shield or conceal
an individual.
The inspectors
observed
various security force shifts perform daily
activities, including searching
personnel
and packages
entering the
protected
area
by special
purpose detectors
or by a physical
patdown for
firearms,
explosives
and contraband.
Other activities included vehicles
being searched,
escorted
and secured;
escorting of visitors; patrols;
and compensatory
posts.
In conclusion,
the inspectors
found that
selected
functions
and equipment of the security program complied with
requirements.
Fire Protection
5.5
The inspectors
observed fire protection activities, staffing and
equipment to verify that fire alarms,
extinguishing equipment,
actuating
controls, fire fighting equipment,
emergency
equipment,
and fire
barriers
were operable.
During plant tours, the inspector looked for
fire hazards.
The inspector
concluded that the fire equipment
and
barriers
inspected
were in proper physical condition.
Emergency
Preparedness
On Harch 21,
1996 the inspectors
observed portions of an
EP drill
exercise
in the plant simulator control
room and the
Emergency Operation
Facility.
Each of the four site emergency
teams
were receiving the
same
training and the
same scenario.
Three of those
teams
were observed
during the last reporting period
as documented
in IR 50-400/96-02.
This
5.6
was the first series of exercises
that the Harris Plant simulator was
utilized to simulate plant conditions
and feed information to the
ERFIS
data display screens
in the Technical
Support Center
and
Emergency
Operation Facility.
The inspector considered
the performance of the
emergency
teams to be adequate.
The inspector discussed
the use of the
simulator-fed
ERFIS displays with several
Emergency Operation Facility
team members
including the Director.
The overwhelming response
was that
it enhanced
the realism of the drill and simplified communication flow.
The inspector
noted that several
additional
issues
were
added to the
scenario for this performance
as
compared to the previous three
discussed
in IR 50-400/96-02.
The additions
improved the scenario.
Licensee Self Assessment
The licensee's
Nuclear Assessment
Section
completed
two assessments
this
month,
as listed below.
The inspectors
reviewed the assessments,
discussed
the findings with the licensee
NAS organization,
and concluded
that the assessments
were thorough
and resulted
in substantive
findings.
Areas
assessed
were:
Inservice Inspection
and Testing Functions
Assessments
(H-ISI-96-01)
Emergency
Preparedness
Program Assessment
(H-EP-96-01)
The inspectors
identified no violations or deviations in the Nuclear
Assessment
area.
5.7
Review of LERs - Plant Support
(Closed)
LER 94-005:
Failure to Perform Analysis Prior to Release
This
LER was issued to report
a failure to perform an analysis of the
Treated
Laundry and Hot Shower Tank prior to release
as required
by
Technical Specification Surveillance
Requirement
4. ll.l.l.l.
Licensee
personnel
took the sample but entered
the wrong counting detector into
the computer
when the analysis
was performed.
The release
was
made with
erroneous
values
on the discharge
permit.
When the problem was
discovered
several
hours later during
a radiation monitor trending
evaluation,
the sample
was reanalyzed
and the discharge
permit was
updated to the correct value.
The licensee
counseled
the personnel
involved and briefed the other applicable
department
personnel.
The
licensee's
analysis
concluded that there
was
no adverse
safety
consequences
because
the sample reanalysis
showed
no abnormal
radioactivity levels
and because
the radiation monitor that monitored
the release
was set at
a conservative
value
and
showed
no abnormal
radioactivity levels.
The inspector reviewed the
LER, the licensee's
Adverse Condition
and
Feedback
Report (94-02763-4),
the
human factors
analysis,
and concluded that the licensee
had completed the corrective
action.
The inspector
concluded that this was
an isolated instance of
personnel
error that resulted in no radiological
consequences.
This
item is closed.
25
5.8
6.0
Conclusion
Plant Support
The inspectors
found plant housekeeping
and material condition of
components
to be adequate.
The licensee's
adherence
to radiological
controls, security controls, fire protection requirements,
emergency
preparedness
requirements
and
TS requirements
in these
areas
was
satisfactory.
OTHER
NRC
PERSONNEL
ON SITE
7.0
On Harch
19 - 20,
1996, Hr. Johns
Jaudon,
Deputy Director, Division of
Reactor Safety,
was
on site to tour the facility and discuss
previous
issues relating to the
SALP board meeting
on April 3,
1996.
On Harch 29,
1996, Hr. Jon Johnson,
Deputy Director, Division of Reactor
Projects,
was
on site to tour the facility and discuss
previous
issues
relating to the
SALP board meeting
on April 3,
1996.
SPECIAL
FSAR REVIEW
A recent discovery of a licensee
operating their facility in
a manner
contrary to the Updated Final Safety Analysis Report
(UFSAR) description
highlighted the need for a special
focused review that compares
plant
practices,
procedures
and/or parameters
to the
FSAR descriptions.
While
performing the inspections
discussed
in this report,
the inspectors
reviewed the applicable portions of the
FSAR that related to the areas
inspected.
The following inconsistency
was noted
between
the wording of
the
FSAR and the plant practices,
procedures
and Technical
Specifications
by the inspector
and licensee.
The licensee
entered
when
a review for condition report 96-1137
revealed that control
room ventilation had not been tested
per Technical
Specification Surveillance
Requirement 4.7.6.d,3
in that the positive
pressure
was only measured
in reference to one adjacent
area,
not all
adjacent
areas.
In discussing this issue at the
PNSC meeting
on
April 27,
1996, the licensee
and inspector discovered that the
TS and
FSAR were in conflict with respect to the computer
room being adjacent
to the control
room.
FSAR Section 9.4.9. 1. 1 states
that the computer
room will be maintained at
a positive pressure
to prevent
inleakage of
the surrounding
environment.
This was in conflict with the control
room
ventilation
TS bases
which requires
the control
room ventilation
be
maintained
at
a positive pressure
with respect to adjacent
areas,
including the computer
room.
This issue
was resolved
by performing
a
modification under
a
10 CFR 50.59 review to the plant ventilation
system.
The modification placed the computer
room ventilation system in
a configuration that will not pressurize
the computer
room.
The
licensee
was planning to issue
a
FSAR change to include this item.
Due to several
FSAR discrepancies
noted in this report
and in
IR 400/96-02
URI 400/96-04-04 Tracking
FSAR Discrepancy
Resolution is
opened.
Inspector
Followup Item 400/96-02-04,
Tracking Licensee's
Progress
in Resolving
FSAR Spent
Fuel
Pool Cooling Discrepancies
is
26
closed.
The licensee
has
scheduled
a meeting
on Hay 30,
1996 with the
NRC, in Washington, to discuss their approach
discrepancies
at all of their sites.
8.0
EXIT
The inspection
scope
and findings were summarized
on April 30,
1996,
by
the Senior Resident
Inspector with those
persons
indicated
by an
asterisk in paragraph
1.0.
An interim exit was conducted
on April 12,
1996.
The inspector described
the areas
inspected
and discussed
in
detail the inspection results.
A listing of inspection findings is provided.
Proprietary information
is not contained
in this report.
Dissenting
comments
were not received
from the licensee.
~T
e
Item Number
96-04-01
96-04-02
96-04-03
96-04-04
Status
Open/Closed
Open
Open/Closed
Open
Descri tion and Reference
Inadequate
Procedure for
Placing Pressurizer
Haster
Pressure
Controller in
Automatic,
Paragraph
2.3. 1. 1.
Inadequate
Corrective Action:
1) Failure to Correct Resin
Venting Problems,
Paragraph
2.5. I;
2) Failure to Correct
Voltmeter Switch Deficiency,
Paragraph
3.2.2.
Failure to Follow Procedure
for Re-qualification of
Haintenance
Personnel,
Paragraph
3.2.6.
Tracking
FSAR Discrepancy
Resolution
IFI
94-12-01
IFI
94-12-02
IFI
94-17-02
Closed
Closed
Closed
Review of Licensee Activities
to Upgrade/gualify
AFW HOVs
for Higher Thrust Values,
Paragraph
4.3.2.
Review the Licensee's
Transition of Work Control
Following Startup
from an
Outage,
Paragraph
2.6.
Biofouling Potential
in
Systems,
Paragraph
4.3.3.
94-21-01
95-17-02
Closed
Open
27
Inadequate
Design Control for
ESW System/CSIP
Coolers,
Paragraph
4.3.1.
Failure to Provide Adequate
Instructions for Repairing
Isolation Valve Pressure
Sealing Surfaces,
Paragraph
3.3.1.
IFI
96-02-04
LER
94-003
LER
94-005
LER
96-002
LER
96-006
9.0
Closed
Closed
Closed
Open
Open
Tracking Licensee's
Progress
in Resolving
FSAR Spent
Fuel
Pool Discrepancies
Improperly Analyzed Single
Failure in Emergency Service
Water,
Paragraph
4.2. 1.
Failure to Perform Analysis
Prior to Release,
Paragraph
5.7.
Failure to Properly Perform
Technical Specification
Surveillance Testing,
Paragraph
3.4.
Isolation Valve Stem
and Disk Separation,
Paragraph
4.2.2.
CFR
CR
CSIP
EDBS
ERFIS
g pill
IS,C
IFI
IR
KV
As Low As Reasonably
Achievable
Code of Federal
Regulations
Corrective Maintenance
Condition Report
Charging/Safety
Injection
Pump
Engineering
Data
Base
System
Emergency Diesel
Generator
Emergency Operating
Procedure
Emergency
Preparedness
Emergency
Response
Facility Information System
Engineering
Service
Request
Final Safety Analysis Report
gallons per minute
Heating Ventilation and Air Conditioning
Instrumentation
and Control
Inspector
Follow-up Item
Inspection
Report
Kilovolts
LCO
LER
NFIV
HS
HSIV
HST
NW
NAS
NRC
OST
PH
PNSC
RII
SNS
SSPS
Tavg
TPP
TS
VAC
WR/JO
28
Limiting Condition for Operati on
Licensee
Event Report
Hain Feedwater
Isolation Valve
Motor-Operated
Valve
Maintenance Surveillance Test
Megawatt
Nuclear Assessment
Section
Non-Cited Violation
Nuclear Regulatory
Commission
Nuclear
Reactor Regulation
(NRC Office)
Normal Service
Water
Operations
Surveillance Test
Public Document
Room
Preventive
Maintenance
Plant Nuclear Safety Committee
Power Operated Relief Valve
Pounds
Per Square
Inch Gage
Reactor Auxiliary Building
Refueling Outage
Region II (NRC Office)
Refueling Water Storage
Tank
Systematic
Assessment
of Licensee
Performance
Substation
Haintenance
Standard
Senior Reactor Operator
Solid State Protection
System
Average Reactor Coolant Temperature
Training Program
Procedure
Technical Specification
Updated
Final Safety Analysis Report
Volt Alternating Current
Volume Control Tank
Violation (of NRC requirements)
Work Request/Job
Order