ML18016A216
| ML18016A216 | |
| Person / Time | |
|---|---|
| Site: | Harris  |
| Issue date: | 10/09/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18016A214 | List: |
| References | |
| 50-400-97-09, 50-400-97-9, NUDOCS 9710230043 | |
| Download: ML18016A216 (38) | |
See also: IR 05000400/1997009
Text
U. S.
NUCLEAR REGULATORY CONMISSION
REGION II
Docket No:
License
No:
50-400
Report
No:
50-400/97-09
Licensee:
Carolina
Power
8 Li,ght (CPBL)
Facility:
Shearon Harris Nuclear
Power Plant, Unit 1
Location:
5413 Shearon Harris Road
New Hill, NC 27562
Dates:
August
3
- September
13,
1997
Inspectors:
Approved by:
J.
Brady, Senior Resident
Inspector
D. Roberts,
Resident
Inspector
G. HacDonald,
Project Engineer
(Section E8.3)
H. Shymlock, Chief, Projects
Branch 4
Division of Reactor Projects.
9710230043
971009
ADOCK 05000400
8
Enclosure
2-
EXECUTIVE SUHMARY
Shearon Harris Nuclear
Power Plant, Unit 1
NRC Inspection Report 50-400/97-09
This integrated
inspection included aspects
of licensee
operations,
engineering,
maintenance,
and plant support.
The report covers
a six-week
period of resident inspection;
in addition, it includes the results of
announced
inspections
by a regional Project Engineer.
~0erations
In general,
the conduct of operations
was professional
and safety
conscious.
The unit shutdown for the forced outage
was handled well by
the operations
crew.
An unresolved
item was opened to review issues
related to the turbine-driven auxiliary feedwater
pump forced outage
work and recovery efforts (Section 01.1
and 01.2).
o
A violation was identified concerning the marking of a main control
room
chart recorder
(Section 02. 1).
Low employee morale has existed in the Operations organization during
1996 and 1997.
Licensee
management
was aware of recent morale
and
performance
issues
and has undertaken efforts to improve both areas
(Section 04.1)
.
A weakness
was identified in relation to three examples of operator
inattention to plant status
and conditions (Section 04.2).
Safety committee meetings
and Nuclear Assessment
Section
assessments
were good.
The equality Check program
needed
some
improvements.
The
self-assessment
of Non-Licensed Operator cross qualification was
thorough.
Self-assessment
activities, in general,
were thorough
and
identified problems
(Section 07.1).
Haintenance
The inspector
concluded that several
maintenance
and testing errors
caused
and extended
the turbine-driven auxiliary feedwater
pump
(TDAFW)
forced outage.
An unresolved
item was identified in relation to overall
performance
in dealing with the turbine-driven auxiliary feedwater
pump
problems
and the root cause of the errors
(Section H1.2).
The surveillance
performances
observed
were adequately
conducted
(Section H2.1) .
Non-cited violations were identified for items reported in three
LERs;
50-400/96-02-01,
96-17-00,
and 96-05-00 (Sections
H8.1, H8.2,
and H8.5).
En ineering
Several
examples of a weakness
were identified where system description
procedures
were not being thoroughly validated or updated
(Section
E3.1) .
A weakness
was identified in trouble-shooting
the
TDAFW pump problems
prior to obtaining all available data
(Section
E4. 1).
A non-cited violation was identified f'r the item reported in LER 50
400/96-013-00
(Section
E8. 1).
The
FSAR upgrade
work was being accomplished
in accordance
with the
Improvement Plan.
The initial FSAR screening
review was thorough.
Issues identified were properly categorized
and entered into the
corrective action program for resolution (Section E8.3).
'~ltt,t
The general
approach.to
the control of contamination
and dose for the
site was good.
Teamwork between the various. departments
continued to be
a major contributor (Section R1).
Security activities,
Emergency
Preparedness
activities,
and Fire
Protection activities were adequately
conducted
(Sections
P1,
S1,
F1,
F2).
4
Re ort Details
Summar
of Plant Status
Unit 1 began this inspection period at 100 percent
power.
On August 16,
1997,
at approximately midnight,
power
was reduced to approximately
30 percent in
order to investigate
tube leak.
Power was returned to 100
percent
on .August 17,
1997 after the tube leak was repaired.
The unit was
shutdown
on August 29,
1997 due to problems with the turbine-driven auxiliary
pump
(TDAFWP).
The unit restarted
on August 31,
1997 and reached
100 percent
power
on September
1,
1997.
The unit remained at 100 percent
power for the rest of the inspection period.
Ol
Conduct of Operations
01.1
General
Comments
71707
I. 0 erations
Using Inspection Procedure 71707,
the inspectors
conducted
frequent
reviews of ongoing plant operations.
In general,
the conduct of
operations
was professional
and safety-conscious;
specific events. and
noteworthy observations
are detailed in the sections
below.
01.2
F
'
Sb t:6 ~dSC
a.
Ins ection Sco
e
71707
The inspector
reviewed the shutdown
and subsequent
startup
from the
turbine-driven auxiliary feedwater
pump outage to determine if
procedures
were followed.
Procedure
GP-006,
Normal Plant Shutdown from
Power Operation to Hot Standby,
Revision 13,
was applicable to the
shutdown
and procedure
GP-005,
Power Operation
(Node
2 to trode 1),
Revision 18,
was applicable to the startup.
b.
Observations
and Findin s
The inspector
observed that the shutdown conducted
on August 29,
1997
was conducted in accordance
with plant procedures.
Operators
shutdown
the plant due to Technical Specification (TS) 3.7. 1.2 action (a) which
required the plant to be in hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after expi ration
of the
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided to repair
and make operable the turbine-driven
pump.
Section
t11.2 discusses
the maintenance
problems that caused the shutdown.
The inspector
observed the subsequent
unit startup
on August 31,
1997.
Reactor
startup
was in accordance
with procedures
and was handled well
by the operating
crew.
Synchronization to the grid occurred that
same
day and was not handled
as well.
The inspector
observed that procedures
were followed prior to synchronization.-
Reactor
power
was at 9.5
ercent prior to synchronization.
After synchronization,
reactor
power
ad jumped
5 per cent to 14.5 percent
which was consistent with previous
synchronizations.
Due to the power increase,
levels
,swelled followed by a reduction in level
as the feed regulating bypass
valves attempted to control level.
Steam flow had increased
above feed
water
flow immediately at synchronization.
The combination of the
closing of the bypass
valves
due to the swell
and the steam flow/feed
flow mismatch
caused
a level transient
which caused
level to decrease.
The steam generator
level
downward transient
continued
due to the bypass
valves being close to the limit of their flow capability.
Operators
opened the main feedwater regulating valves,
intending to supplement
the
bypass
valves.
However, the block valves upstream of the feed
regulating valves
had not been opened.
Operators
were not immediately
aware of the block valves being closed
and did not identify why level
was not responding.
The Operations
manager
was observing the
synchronization to the grid and pointed out to the operators that the
block valves were not open.
The inspector considered that the opening
of the feedwater regulating valves prior to opening the block valves
was
different than described
in step
102 in procedure
GP-005.
The
Operations
manager
counseled
the operating shift on attention to 'detail
and proper procedural
compliance.
Condition Report
(CR) 97-04109
was
initiated to document this problem.
Based
on current plant performance,
the inspector determined that the feedwater control valve unblocking
steps
should
be prior to their existing location in GP-005.
The inspector
observed that this crew was on shift when the
TDAFWP dead
headed
(section H1.2)
and had difficulty in the latest licensed operator
requalification exam.
In addition, the operator not identifying the
closed block valve was from the most recent initial qualification class.
The examination of this class
was discussed
in Inspection Report
50-400/97-300
and
a training staff weakness
was noted in Inspection
Report 50-400/97-03.
The inspector questioned
why a step increase
in power was necessary
at
synchronization.
The step increase
unnecessarily
challenged
the control
systems
(feedwater flow, steam generator level,
and reactor temperature
control).
The steam
dump system provides
an automatic
method for the
licensee to set
power at the synchronization level prior to
synchronization
and transfer
steam
demand
from the steam
dump system to
the turbine at synchronization.
The appropriate
use of the steam
dump
system during synchronization
allows for
a smooth transfer
without
having
a significant step increase
in power.
The licensee
was
investigating
why a smooth transfer
had not occurred.
During review of operator logs and condition reports,
the inspector
reviewed the circumstances
surrounding
a turbine runback that occurred
later in the startup
on September
1,
1997.
The inspector
found that
CR
97-04112
was initiated due to the runback.
The
CR identified that the
Unit Senior Control Operator
(SCO)
had misread
Procedure
GP-005 for
where to stop the power increase
and start
a second
feed
pump.
The
SCO
misread the procedure to indicate 370 psig turbine first-stage pressure
instead of 310 psig.
The investigation of this event
found that four
procedures
contained conflicting runback initiation setpoint values.
(GP-005,
and APP-ALB-020, t1ain Control Board).
The values varied from 370 to 330 to 310 psig.
The inspector
observed
that the
SCO was also from the latest initial license class
discussed
in
Inspection Report 50-400/97-300.
The inspector
remembered
a runback in 1996 that was documented in CR 96-
01254.
The 1996
CR documented
a conflict with the
same procedures.
Corrective actions to revise the procedures
had not been completed
and
the condition report was still open.
The licensee
was performing
a root cause investigation of'll personnel
errors noted during the
TDAFWP forced outage.
The inspector considered
the root cause of startup errors unresolved
and will be identified as
unresolved
item,
URI 50-400/97-09-01,
TDAFWP Forced
Outage
Problems.
Conclusions
02
02.1
The forced shutdown
was handled well by the operations
crew.
An
unresolved
item was opened to review issues
related to the
TDAFW pump
forced outage
work and recovery efforts.
Operational
Status of Facilities and Equipment
Review of Shi ft Lo s
Ins ection Sco
e
71707
The inspectors
checked the main control
room chart recorders to assure
that pens
were marking properly and the recorders
were timing correctly.
Observations
and Findin s
On August 17,
1997 at approximately 8:45 a.m.,
the inspector identified
where the licensee
had failed to properly check
and initial the main
control
room chart recorders
once
per shift as required
by Procedure
OMM-016, Operator
Logs, Revision
13'hart recorder
PR 649,
Component
Cooling Water red pen,
was not inking and
had not been since
approximately 1:00 p.m. the previous day.
This period of time included
two shift turnovers
and one entire shift period.
The chart
had not been
initialled'ince 11:00 a.m. the previous
day when chart inking problems
were corrected
and the chart motor was restarted.
Procedure
OMM-002,
Shift Turnover Package,
Revision 12, stated that individuals are
responsible
for personally verifying important parameter s,
and reviewing
and understanding
logs applicable to their shift position before
relieving the shift.
The failure to check
and note chart recorder
PR
649 marking problems through two shift turnovers
and one shift marking
period is identified as
a violation of TS 6.8. l.a and is designated
violation 50-400/97-09-02.
failure to properly check main control
room
chart recorders.
This violation is similar to violation 50-400/96-11-01
where operators
were initialing the chart recorder
logs even though the
pens were not marking.
4
The operators
immediately corrected
the inking problem and restarted
the
chart.
Condition Report 97-03888
was initiated to address
the cause of
the problem.
The licensee
found that
a communication
problem during the
shift had caused
the failure to .properly check
and initial some charts.
During the period of time identified,
a condenser
tube leak had been
discovered
and the unit was reducing
power to enable the leak to be
identified.
Procedure
OIN-16 requires that the charts
be marked for
significant events.
This was accomplished
except that the
down power
did not affect component cooling water pressure,
and therefore the chart
was not,marked.
The operator
who marked the charts for the
down power
and the main control
room operators
inadequately
communicated to each
other that riot all charts
had been marked.
Conclusions
A violation was identified concerning the marking of a main control
room
chart recorder.
04
04.1
Operator
Knowledge and Performance
JOD
N
1
die
El'f t
P f
Ins ection Sco
e
71707
The inspectors
reviewed
a 1996 employee opinion survey and interviewed
operators
in order to determine whether employee
morale problems existed
and whether there
was- any discernable
impact on operator
performance.
Observations
and Findin s
The inspectors
reviewed
a 1996 employee opinion survey which indicated
that responses
obtained
from the Operations unit were generally less
favorable than those obtained
from other organizational
units.
Areas
evaluated by the opinion survey included the licensee's ability to deal
fairly with employees
and treat employees with respect.
The inspector informally interviewed several
operators
(licensed
SROs,
ROs,
and non-licensed auxiliary operators)
including some
who performed
non-shift work such
as procedure writing or work coordination duties.
Everyone interviewed agreed that declining morale
had been
an issue over
the last two years.
The disparity was whether
employee
morale
was still
an issue at the time of this inspection
and whether there
was
a link to
employee
performance
and safety issues.
Some felt employee morale
had
improved in the last few months,
and was better
than that of a year
ago
(when it was generally perceived to be at its worst), while others
thought morale was still pretty low.
The inspector
perceived that the
opinions expressed
were based partially on recent treatment in relation
to personnel
actions or employee. appraisals.
For the most part,
operators
expressed
that employee
morale
had improved over the last
several
months.
In general,
those interviewed'were
happy with some of the recent
management
changes
in Operations.
The consensus
was that the
new
operations
manager
had
made progress
in his attempts to remove
some of
the barriers to good performance
(administrative burdens,
excessive
overtime, external distractions).
They generally felt that the
new
manager
had
made progress
in achieving
some of the objectives in the
site's recently implemented
Near Term Improvement Plan,
allowing
operators to focus more on safely operating the plant.
Recent efforts
to realign the operations organization,
including personnel
changes
in
first-line and middle management,
were viewed positively.
Some negatives still existed,
including
a perceived "pass/fail" approach
to performance
appraisals,
and licensee
management's
alleged
casual
approach to communicating
a recent organization
change.
The results of the above-mentioned
interviews
and employee survey review
were not surprising to the inspectors,
who were aware of recent operator
errors
and
an attempt
by licensee
management
to focus
on performance
issues.
In essence,
operators
have
been
under
a "microscope" for the
year or two because of performance
problems.
The combination of the
"microscope" effect and recent operational
challenges
and
an
unexpectedly lengthy refueling outage
have likely contributed to low
employee morale.
Licensee
management
was aware of the morale
issu~
and
had identified it as
an improvement item in its newly implemented
Near
Term Improvement Plan.
During the above survey review and employee interviews, the inspector
did not identify any immediate safety concerns.
However, it was clear
that low operator morale
had been
an issue in 1996
and 1997.
There
was
no conclusive evidence that linked the low morale to the increased
human
error rate in either year.
However, it was considered likely that the
increased
management
scrutiny of employee
performance
has highlighted
a
morale problem that may have
been developing for
a period of time.
Conclusions
Low employee
morale
has existed in the Operations organization during
1996 and 1997.
Licensee
management
was aware of recent morale
ar 6
performance
issues
and has undertaken efforts to improve both areas.
No
violations or deviations
were identified by the inspectors.
~0 erator
Knowled e of E ui ment Status
and Plant Conditions
Ins ection Sco
e
71707
The inspectors
reviewed operator
performance
during the period in
relation to knowledge of equipment conditions.
Observations
and Findin s
The .inspector
observed
several
instances
where operators
were not fully
aware of plant conditions.
The first related to the feedwater
c
regulating valve block valves discussed
in section 01.2 of this report.
Operators
were attempting 'to use the feedwater
regulating valves without
having the associated
block valves open.
A second
example involved the
chart recorder identified in section 02.2 of the this report where
operators
were not aware that a'ontrol
room chart recorder
was not
marking for over
18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.
The third involved the performance of OST-1005,
Control
Rod and
Rod
Position Indicator Exercise Monthly Interval, Revision 7,
when the bank
insertion limit alarm did not clear.
This had occurred
on three
startups
since refueling outage
7 when the park position for the rods
was changed.
Inspection Reports 50-400/97-06
and 97-08 discussed
the
design
problem associated
with the alarm.
On August 8,
1997 while
performing OST-1005,
the bank insertion limit alarm again did not clear.
The inspector observed that the operating
crew was surprised that the
alarm did not clear.
During the previous
two startups,
which were
observed
by the inspector, this alarm not clearing
was expected
because
operators
had reviewed the work request
and engineering
service request
that
was generated
as
a result of the problem.
A yellow dot had been
placed
on the alarm light box to alert the operators to this previously
identified problem.
The August 8 operations shift did not know why the
dot had been placed
on the main control board.
Condition Report 97-
03822
was initiated to address this unawareness
problem.
In addition,
discussions
were held at the monthly Plant Nuclear Safety Committee
meeting concerning operator attention to plant conditions.
Conclusions
07
07.1
a.
A weakness
was identified in relation to three examples of operator
.inattention to plant status
and conditions.
Quality Assurance in Operations
Licensee
Self-Assessment
Activities
0
~40000
During the inspection period, the inspector s reviewed multiple licensee
self-assessment
activities to determine whether the licensee
was
adequately
finding problems.
These included:
Plant Nuclear Safety Committee
(PNSC) meeting
on August 27,
1997
Nuclear Safety Review Committee
(NSRC) meeting
on September
2,
1997
Nuclear
Assessment
Section
(NAS) Audits on Technical Specification
Survei llances
(HNAS97-101) Maintenance
(HNAS 97-0117),
Vendor
Services
(HNAS97-081),
and Biennial Procedures
Review
(HNAS 97-
102)
Condition Reports
Line Organization Self Assessments
Quality Check
(Employee Concerns)
b.
Observations
and Findin s
The inspector
observed that the safety committees
(PNSC
and
NSRC) were
thorough in their review of the scheduled
discussion
issues.
Senior
corporate
management
was involved in the
NSRC including the Executive
Vice President,
who has
been at all
NSRC meetings
observed
by the
inspectors
in 1996 and 1997.
The inspector
found these activities good.
NAS Audits reviewed were probing in the areas
reviewed.
The inspector
interviewed the lead auditor concerning the audits
and found him to be
knowledgeable
about the findings and their significance.
The inspector
reviewed the Quality Check Program described in Procedure
REG-NGGC-0001,
Revision 3, with the Quality Check representative
end the
Manager-Performance
Evaluation
and Regulatory Affairs (PERAS).
The
inspector
was told that
a change to the Quality Check Program
was being
prepared.
A sample file was used to demonstrate
implementation of the
procedure.
The inspector
had the following general
observations,
which
were being considered
by the licensee for inclusion in the
new program
revision:
Quality Check files are considered
closed after investigation
completion,
even if corrective actions
are not completed.
The term "resolved"
was not used equivalently with "corrected".
Resolved
concerns
may be those
where investigation is complete
and
corrective actions
agreed
upon,
as opposed to corrective actions
completed
and the concern resolved.
Concerned individuals were not necessarily
informed of corrective
action completion, only of investigation completions
Corrective actions
were being tracked through
a data
base
used
by
Quality Check personnel.
Actions to line organizations
may not be
in a site-wide tracking system.
Procedure
AP-615, Condition Reporting,
Revision 24,
exempts
Quality Check items from the condition reporting program.
However,
Procedure
REG-NGGC-0001 discusses
writing condition
reports for Quality Check items.
Licensee
personnel
were
preparing
a change to AP-615 in response
to this observation.
The inspector
observed
the following related to the Quality Check file:
The investigation
appeared
to be thorough
and well documented.
File organization
needed
improvement.
Corrective actions
were given
a due date which had long since
passed,
but there
was
no evidence in the file that the corrective
actions
were complete.
The inspector
concluded
from discussions
with licensee staff that this was
a documentation
and
administrat
~n issue only.
The file inuicated that
a condition report
(CR) had not been
written for the investigation findings even though they
represented
potential
procedure
implementation
problems.
The
inspector
found that the line organization
had written a
CR, but
the Quality Check staff was not aware.
The inspector
reviewed
a line organization self-assessment
conducted
Hay 7-10,
1996, titled "Assessment of OJT/TPE for cross-qualification of
Non-Licensed Operator
(NLO) Systems".
The self-assessment
was conducted
by the training department to determine if cross-qualification
implementation
on
NLO systems
was effective.
The assessment
identified
two weaknesses.
The first was that the distinction between on-the-job
training (OJT)
and task performance evaluation
(TPE) were not
consistently observed.
The second
was that operators
were allowed to
assume
rad-waste
watch-standing
duties without properly completing the
identified qualification requirements.-
Ten corrective actions
were
identified by this self-assessment
with organizations
and due dates
assigned.
The inspector
reviewed Condition Report 96-01284 which
implemented the corrective actions.
The corrective actions
were
, completed
on July 17,
1997.
The inspector
discussed
the corrective
actions with the former operations
manager
who stated that cross-
qualification was stopped
as
a performance
appraisal
objective in the
fall of 1996.
The former operations
manager
had discussed this action
with the inspector at that time.
That action was not included in the
condition report corrective actions.
The inspector
found the self-
assessment
thorough.
Conclusions
Safety committee meetings
and
NAS assessments
were good.
The equality
Check program needed
some
improvements.
The self-assessment
of Non-
Licensed Operator cross-qualification
was thorough.
Self-assessment
activities, in general,
were thorough
and identified problems.
H1.1
Conduct of Maintenance
General
Comments
62707
II. Haintenance
The inspectors
observed all or portions of the following work
activities:
WR/JO AKLT-001
WR/JO AIWI-002
o
WR/JO 97-AIHH1
WR/JO AIVH-002
WR/JO AIYF-002
Replace
Solenoid
on 1CC-305,
Gross Failed Fuel
Detector
"8" Train
CCW isolation valve.
Perform
PM-M0014 on 1CC-167,
RHR heat exchanger
"B" CCW outlet isolation valve
Fire Door 615 door closer broken
Limitorque PH-H0014 on valve 1CT-1g
Limitorque PM-H0014 on valve 1CT-26
In general,
the inspectors
found the work performed
under these
activities to be professional
and thorough.
All work observed
was
performed with the work package
present
and in active use.
The
inspectors
frequently observed
supervisors
and system engineers
monitoring job progress,
and quality control personnel
were present
whenever
required
by procedure.
When applicable,
appropriate radiation
control
measures
were in place.
In addition,
see the specific discussions
of maintenance
observed
under
H1. 2
Turbine-Driven Auxiliar
Pum
Maintenance
Ins ection Sco
e
62707
The inspectors
observed portions of the maintenance activities to repair
the turbine-driven auxiliary feedwater
pump
(TDAFWP) between
August 27
and August 31,
1997.
These activities were covered
under
WR/JO 97-AJCX1
and Procedure
CH.M0071, Ingersoll-Rand Turbine Driven Feedwater
Pump
Size 4 x 9 NH-7 Disassembly
and Maintenance,
Revision 6.
The inspectors
also reviewed the circumstances
associated
viith a post-maintenance
test
in which the
TDAFW pump was deadheaded
for five minutes.
The inspectors
reviewed the test procedure,
OST-1080, Auxiliary Feedwater
Pump
Full Flow Test Quarter ly Interval, Revision 1,
and the licensee's
corrective actions
as described
for condition report
(CR) 97-04104.
Observations
and Findin s
The work was initiated due to vibration problems
found during the
initial performance of OST-1411, Auxiliary Feedwater
Pump
1X-SAB and
1AF-106,
1AF-87 forward flow operability test.
Vibration on the
inboard bearing
was approximately double what it had been in the
previous test.
The licensee
was
aware that at the pressure
and flow
being used,
hydraulic pulsation
was being experienced
when using the
recirculation line to the condensate
storage
tank.
The line was not
sized for full flow.
NRC Bulletin 88-04. Safety-related
Pump Loss,
had warned of flow
instability at low flows while on recirculation.
Flow instability
becomes
more severe
as flow is decreased,
and can cause
pump damage
from
pump vibration, excessive
forces
on the impeller,
and cavitation.
The
bulletin recommended that the limitations associated
with these
hydraulic phenomena
be considered
when specifying minimum flow capacity.
The licensee's
response
to the bulletin dated July 11 and November
1,
1988 did not identify any problems with the auxiliary feedwater
system.
The licensee
determined that the inboard bearing
needed to be replaced.
This was confirmed with the vendor.
The work request
was initiated to
replace the inboard
pump bearing.
After replacement,
the turbine-to-
pump coupling was erroneously installed backwards.
While attempting to
remove the reversed
several
other problems occurred.
First
the coupling had to be heated to be removed.
Not all of the oil from
the bearing replacement
had been cleaned
up and the torch was placed too
close causing
some
smoke
and in a later attempt,
a small fire.
Neither
caused
equipment
damage.
In pulling the coupling off the shaft, the
shaft
and coupling galled.
This necessitated
complete disassembly
and
replacement of the rotating element
and coupling.
During disassembly
10
the oil for the outboard bearing
was found discolored.
i>s indicated
that the outboard bearing
was really the one that had caused
the problem
(see section E4.1).
Problems with the
pump leaking occurred during reassembly.
The first
involved jacking bolts for removal of the stuffing box which were left
inserted too far on reassembly.
The second
involved the discovery that
the upper case to lower case
was slightly undercut in the
stuffing box 0-ring seal
area.
The licensee later discovered that the
undercut
problem had occurred in the past but had never
been
documented.
The third involved
a slight leak (1 drop every 4 seconds)
that stopped after the
pump was started
and its speed
increased
to 4100
rpm.
These
problems
caused
the limiting condition for operation
(LCO)
time to expire
and
a unit shutdown
was accomplished
(see section 01.2).
Post maintenance
testing included vibration testing, full flow testing,
and the verification of the
pump curve for the
new rotating element.
The inspector
observed the vibration testing of the
pump which was
successfully
accomplished
on recirculation
(procedure
OST-1411).
During
full flow testing of the
new rotating assembly,
performed using
procedure
OST-1080,
the operators
encountered
a situation where steam
generator
(SG) level
was high and flow needed to be secured.
The
operators
forgot that during the full flow test the recirculation line
was isolated.
The operators
closed the flow control valves, prior to
reestablishing
a recirculation flow path,
causing the
pump to be dead-
headed for about five minutes.
Procedure
OST 1080, step 37, established
recirculation flow, followed by the shutting of the flow control valves
in step 38.
These steps
were not followed.
Subsequent
inspection
by the licensee
and vendor
concluded that the
pump
was probably not damaged.
Testing was accomplished
by repeating
procedures
OST-1411
and OST-1080 which confirmed that the
pump was not
damaged.
Then EPT-115,
Dynamic test of Auxiliary Feedwater
Pump 1X-SA8,
Revision 2,
was used to verify the
pump curve.
These tests
had
satisfactory results.
The inspector
found that the maintenance
and testing problems that
caused
the
TDAFWP forced outage
were related to personnel
errors.
However, there were other factors associated
with these
problems that
bear further analysis.
These included the previous history of problems
during assembly of this
pump which had caused
rework,
and supervision
and monitoring of the work.
In addition, operator
performance
during
the post-maintenance
test should be analyzed collectively with the other
operator errors performed during this period to determine if their is
a
common relationship
(see Section 01.2).
The licensee
was performing
a
collective root cause investigation of the
TDAFWP forced outage errors
which was not complete.
The inspector considered
the root cause of the
maintenance
and testing errors unresolved
pending review of the
licensee's
root cause investigation
and resulting corrective actions.
These
issues
are considered
part of the overall
TDAFW forced outage
issue
and are included in the unresolved
item,
URI 50-400/97-09-01,
11
TDAFWP Forced Outage
Problems,
identified in section 01.2 of this
report.
Conclusions
H2
H2.1
The inspector
concluded that several
maintenance
and testing errors
caused
and extended
the forced outage.
An unresolved
item was
identified in relation to overall performance
in dealing with the
TDAF'l
(ith the normal service water pump breaker and discharge valve operation as referenced in procedure AOP-22, Loss of Service Water, General Section, and in training lesson plan AOP-SIM-3.07. Operators uiere unaware of this feature which con:ributed to a 1996 manual reactor trip event as described in LER 50-400/96-018-01. The inspectors observed numerous cases during review of 1996 and 1997 LERs where operator lesson plans were updated to include important information about how systems operate. However, the inspectors could not remember a single instance where a system description was called out for updating as a corrective action for an L'ER. The inspectors also held discussions with operators and training department personnel concerning their perception of system descriptions. The overwhelming opinion was that the system descriptions were not as good as training lesson plans in describing how systems work. In Inspection Report 50- E4 15 400/96-10, the inspector identified where the emergency boration function was not described in the Chemical and Volume Control System description (SD-107). This function was one of the most important functions of that system. The inspector concluded that these procedures, which are controlled documents, should contain current and accurate information about system design and operation to serve as reliable aids to operators and others who may reference them. This is identified as a weakness. Engineering Staff Knowledge and Performance Turbine- dri ven Auxi1iar Feedwater Pum Ins ection Sco e 37551 The inspectors observed the performance of engineering personnel in resolving problems identified from the performance of quarterly turbine driven auxiliary feedwater pump vibration testing. Observations and Findin s Section H1.2 discussed problems with the repair of the turbine-driven auxiliary feedwater pump. As a result of increased vibration found on the inboard pump bearing while performing quarterly pump testing (OST 1411), Engineering became involved to determine the cause of the problem. Vibration on the inboard bearing was approximately double what it had been in the previous test. Licensee engineering personnel were aware that at the pressure and flow being used, hydr'aulic pulsation was being experienced when using the recirculation line to the condensate storage<. tank. The line is not sized for full flow. NRC Bulletin 88-04, Safety-related Pump Loss, had war ned of flow instability at low flows while on recirculation. Flow instability becomes more 'severe as flow is decreased, and can cause pump damage from ump vibration, excessive forces on the impeller, and cavitation. The ulletin recommended that the limitations associated with these hydraulic phenomena be considered when specifying minimum flow capacity. The licensee's response to the bulletin, dated July 11 and November 1, 1988, did not identify any problems with the auxiliary feedwater system. The licensee had considered that the vibration readings could indicate a lack of stiffness in the rotating element and support components. The inboard bearing was considered one of those components. The licensee determined that the inboard bearing needed to be replaced. The decision was based solely on the vibration data which indicated little if any increase in vibration on the outboard bearing.'roblems with the rotating lement stiffness would entail a complete pump disassembly which was being considered if the bearing rep'lacement did not correct the vibration problem. The licensee confirmed with the pump vendor that the appropriate initial action would be to replace the inboard bearing. The bearing was replaced, but no problems were found with the bearing. E7 E7.1 E8 E8.1 16 After replacement, the pump coupling was inadvertently installed backwards, as discussed in section H1.2 of this report. This resulted in a complete pump disassembly and rotating element replacement. During disassembly the oil for the outboard bearing was found discolored. This indicated that the outboard bearing was really the -one that had caused the problem. Discussions with the vendor indicated that the balance drum on the outboard end can mask bearing problems in relation to vibration. The inspector observed that the licensee made a decision that the problem was a bad bearing without taking oil samples. The oil sample is a quick way to get an indication of bearing failure. The inspector considered that the licensee's troubleshooting plan did not include obt'aining and evaluating all available data for determining the cause of the problem prior to setting the course of action. Inspection Report 50-400/97-06 also discussed a problem with troubleshooting. In that report the licensee began executing a plan for determining the cause of a failed tast bus transfer without obtaining all available data. The inspectors considered the problem with the turbine-driven auxiliary feedwater pump similar, in that, had oil samples been taken, the correct bearing would have been initially replaced. The inspectors con'sidered the two examples a weakness in troubleshooting in relation to not obtaining and evaluating all available data prior to implementing a course of action. Conclusions A weakness was identified in troubleshooting iA relation to determining a course of resolution prior to obtaining and evaluating all available data. Quality Assurance in Engineering Activities S ecial FSAR Review (3~7531 ~A recent discovery of a licensee operating their facility in a manner contr ary 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. This issue is discussed in section E8.3 under Unresolved Item 50-400/96-04-04, Tracking FSAR Discrepancy Resolution. Hiscellaneous Engineering Issues (92700) Closed LER 50-400/96-013-00 50-400/96-013-01 and 50-400/96-013-02 Condition outside of design basis where RWST had been aligned with a non-seismically qualified system. This LER and its'upplements were issued to address connecting nonseismic portions of systems to seismic portions of systems. Systems 17 and components involved were the refueling water storage tank (RWST) lines to spent fuel pool cooling and the hydrotest pump; chemical addition lines to component cooling water and essential services chilled water; and boric acid tank (BAT) lines to the refueling water storage tank and recycle holdup tank. The inspector found that the corrective action was to declare the affected components inoperable when isolation valves at the seismic interface were opened. Corrective action for the BAT included a procedure revision to declare the BAT inoperable when pumping through the non-seismic piping. The inspector verified that a note was added to OP-107, Chemical and Volume Control System, in Revision 14. A similar change was made to OP-148, Essential Services Chilled Water System, in Revision 8, to declare the system inoperable when the chemical addition valves are open. For the RWST lines, similar actions were prescribed in OP-116, Fuel Pool Cooling and Cleanup, in Revision 9 for the RWST to spent fuel pool cooling, and OP-112, Containment Spray, in Revision 10 for the hydrotest pump. The corrective action for the component cooling water system was found inadequate as described in Violation 50-400/97-04-02 and will be reviewed under that item. The issue of operating the plant outside the design basis which resulted in violation of various TS LCOs was considered a non-repetitive, licensee-identified and corrected violation and is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy (50-400/97-09-06). These LERs are closed. = Closed LER 50-400/96-008-00 and 50-400/96-008-01: Reactor trip due to the failure of a switchyard breaker disconnect switch. This LER was issued due to a reactor trip/turbine trip caused by a switchyard disconnect failure. This issue was addressed'in NRC Inspection Reports 50-400/96-05 sections 01.2, 01.8. and E1.1; and 50- 400/96-07 section H8.2. The corrective action for the switchyar d disconnect problem was addressed in those reports. The inspector verified that thermography of the disconnects was being conducted to ensure that overheating does not occur. In addition, the inspector verified during refueling outage 7 that switchyard work was integrated into the site outage schedule. Engineering review of the pressurizer pressure master controller concluded that the controller worked as designed. The inspector reviewed the operations analysis of'he trip that was used to train the operators. The inspector determined that the analysis was thorough and emphasized the appropriate places where improvement was needed. The inspector reviewed the attendance sheets for the training and determined that operators were trained on the event. Performance during the September 1996 manual reactor trip, the January 1997 reactor trip, the June 1997 reactor trip, and July 1997 reactor trip showed that the training was effective in relation to limiting primary plant cooldown after the trip. The inspector considered that the information learned in relation to the normal service water pump and discharge valve logic was important to E8.3 include in the system description (SD-139), however, it had not been included. This observation is addressed in section E3.1. Section H8.4 of this report for LERs 50-400/96-018-00 and 01 further discuss normal service water pump problems. This item is closed. Closed URI 50-400/96-04-04: Tracking FSAR Discrepancy Resolution This URI was opened in NRC Inspection Report 50-400/96-04 to track the licensee's resolution of discrepancies identified between plant configuration, plant practices, procedures and/or parameters and the descriptions in the FSAR. A meeting was held on Nay 30, 1996, between NRC and CPSL to discuss the UFSAR Review and Upgrade Plan for the three CP8L nuclear facilities. The UFSAR Review and Upgrade Plan contained 5 basic elements: Accountability for FSAR sections, Performance of an initial FSAR review to identify significant discrepancies, Validation of selected FSAR sections, Deficiency Resolution, and Effectiveness assessment. The Harris Nuclear Plant (HNP) FSAR Improvement Plan was issued to licensee staff on Hay 14, 1996. The accountability element was implemented by assignment of FSAR sections to individual owners for initial review and ongoing maintenance. This was verified by the . nspectors review of the FSAR Section Responsibility Hatrix. The Initial FSAR Screening Review was performed by the individual section owners in accordance with Attachment 2 to the improvement plan, "Objective and Instructions for Performing Initial FSAR Section Reviews." The initial review was intended to be a qualitative review not a complete FSAR validation. Individual discrepancies including minor typographical changes were documented on Condition Reports (CRs) and entered into the Corrective Action Program. Each FSAR Discrepancy processed as a CR received a 10CFR50.59 unreviewed safety question determination screening. When discrepancies required FSAR changes, corrections to the FSAR were documented on FSAR Change Request Review Approval Forms (RAFs) .in accordance with administrative procedure AP- 603, FSAR Revisions. Individual FSAR discrepancies were categorized per AP-603 as: Category A (Potential Operability or Reportability Concern), Category B (Technical or Substantive Discrepancy Requiring Reconciliation of FSAR), Category C (Low Significance Low Impact Technical Discrepancy) and Category D (Editorial Items). Procedure AP- 603 provided target FSAR discrepancy disposition guidelines by category for completion of operability/reportability evaluations, CR evaluations, RAF completions, and completions of CR actions. The initial screening effort was completed on September 1, 1997 with 5 Category A CRs (1 open), 68 Category B CRs (31 open), 200 Category C CRs (61 open), and 62 Category D CRs (14 open) for a total of 335 FSAR discrepancies identified. The inspectors reviewed the Reactor Trip System (RTS) Safety System Functional Evaluation which was performed as an FSAR validation effort using nuclear industry consultants. The review assessed RTS engineering and maintenance and compared the design of the RTS to FSAR section 7.2. 19 The review identified 2 strengths and 25 issues of which 14 were categorized as CRs. All the issues were thoroughly evaluated and dispositioned and tracked under. the licensee's corrective action program. The inspectors reviewed the following FSAR Discrepancy CRs and the related RAF packages: 9602260 9601796 9700865 9603593 9600936 9403625 9502976 9600140 9700087 9602590 9601667 9602546 9601338 9602268 9602534 9600699 9601946 9602683 9603161 The sample selected included the closed category A CRs and 15 closed, category B CRs. The inspectors concluded that the CRs were properly categorized, additional unresolved safety question items which should have been reported were not identified in the population of category B CRs reviewed. The RAF packages reviewed were found to be in accordance with AP-603 requirements, however the timeliness goals for RAF and CR completion were not being met. During review of CR 9601338/RAF 2160 the inspectors identified that the revision to FSAR table 9.2.2-3 "Typical System Flowrates During Normal Operation" for the Component Cooling Water System failed to include the 160 gallons per minute flow to the Sample Heat Exchanger Package which was a non-safety related load. Since this was a non-essential load and was isolated on a safety injection signal, this had no safety impact. The licensee initiated CR 97-04222 to correct this issue. The initial FSAR screening review was thorough. Issues from the FSAR review and Reactor Trip System SSFI were properly categorized and entered into the corrective action program for resolution. Hany CRs were identified and 67%%d of the CRs remained open as well as several of the RAF packages. Further review of FSAR discrepancy CRs is planned as part of routine corrective action assessment. The inspectors concluded that the licensee was accomplishing the FSAR upgrade work in accordance with the FSAR Improvement Plan. This item is closed. IV. Plant Su ort Radiological Protection and Chemistry (RPEC) Controls G 1 C t it71750 The inspector observed radiological controls during the conduct of tours and observation of maintenance activities and found them to be acceptable. The general approach to the control of contamination and dose for the site was good. Teamwork between the various departments continued to be a major contributor . 20 P1 Conduct of EP Activities P1.1 General Comments 71750 The inspectors observed portions of an emergency preparedness drill conducted on September 9, 1997 from the simulator control room and tne Emergency Operations Facility. The drill was being appropriately monitored by drill controllers. The inspectors found that when transitioning back to the plant, security personnel at the road gate were prepared to deny the inspectors access, had they been drill participants, because they were not on the licensee's emergency response organization roster. Access was not denied and security management took immediate corrective action. S1 S1.1 Conduct of Security and Safeguards Activities Gener al Comments 717~50 The inspector observed security and safeguards activities during the 'onduct of tours, observation of maintenance activities, and the emergency preparedness drill, and found them to be generally good. Compensatory measures were posted when necessary and properly conducted. A comment related to the emergency drill is contained in section Pl.l. Control of Fire Protection Activities F1.1 General Comments 71750 F2 F2.1 The inspector observed fire protection equipment and activities during the conduct of tours and observation of maintenance activities and found them to be generally acceptable (see section H1.2 for one exception). Status of Fire Protection Facilities and Equipment Safe Shutdown Anal sis 71750 90712 The licensee initiated Condition Report 97-03861 to document a problem found during review of the safe shutdown analysis under Engineering Service Request 9500433. The problem involved a lack of adequate fire protection measures for several cables associated with the emergency diesel generator fuel oil transfer pump electrical cable for each train. The cable was routed through the unit 2 auxiliary building which was never completed. No fire suppression or detection was provided in that area. The inspector walked down the area with the associated engineer and verified that fire watches were established. The issue was appropriately reported to the NRC under 10 CFR 50.72 and 10 CFR 50.73 (LER 50-400/97-020-00). 21 V. Hang ement Heetin s Exit Heeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on September 12, 1997. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified. PARTIAL LIST OF PERSONS CONTACTED Licensee D. Batton, Superintendent, On-Line Scheduling D. Braund, Superintendent, Security B. Clark, General Manager, Harris Plant A. Cockerill, Superintendent, 18C Electrical Systems J. Collins, Manager, Maintenance J. Donahue, Director. Site Operations, Harris Plant J. Eads, Supervisor, Licensing and Regulatory Programs W. Gurganious, Superintendent, Environmental and Chemistry H. Hamby, Supervisor, Regulatory Compliance H. Keef, Manager, Training B. Meyer, Manager, Operations B. Morrison, Manager, Outage and Scheduling K. Neuschaefer, Superintendent, Radiation Protection W. Peavyhouse, Superintendent, Design Control W. Robinson, Vice President, Harris Plant G. Rolfson, Manager, Harris Engineering Support Services S. Sewell; Superintendent, Mechanical Systems D. Tibbitts, Manager, Nuclear Assessment C. Vandenburgh, Hanager, Regulatory Affairs NRC Y. Rooney, Harris Project Manager, NRR H. Shymlock, Chief, Reactor Projects Branch 4 0 IP 37551: IP 40500: IP 61726: IP 62707: IP 71707: IP 71750: IP 92700: IP 90712: 22 INSPECTION PROCEDURES USED Onsite Engineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Surveillance Observations Maintenance Observation Plant Operations Plant Support Activities Onsite Followup of Events In-Office Review of Written Reports of Non Routine Events at Power Reactor Facilities ITEHS OPENED, CLOSED, AND DISCUSSED ~0ened 50-400/97-09-01 50-400/97-09-02 URI VIO 50-400/97-09-03 NCV 50-400/97-09-04 NCV 50 '00/97-09-05 NCV 50-400/97-09-06 NCV TDAFW forced outage problems (Section 01.2 and H1.2). Failure to properly check main control room chart recorder (Section 02.1). Failure to test valve 1CS- 196 constitutes a violation of TS surveillance requirement 4.3.2. 1 (Section H8. 1). Failure to perform procedure OST-1052 between March and June 1996 (Section H8.2). Failure to test PAL door caused violation of TS 4.6. 1.3.a. (Section H8.5) Operation outside design basis by connecting non- seismic piping to RWST causing TS violations. (Section E8.1) Closed 50-400/97-09-03 NCV 50-400/97-09-04 NCV 50-400/97-09-05 NCV 50-400/97-09-06 NCV 50-400/96-002-01 LER 50-400/96-017-00 LER 50-400/96-017-01 LER 50-400/96-021-00 LFR 50-400/96-018-00 LER Failure to test valve 1CS-197 constitutes a violation of TS surveillance requirement 4.3.2. 1 (Section HS. 1). Failure to perform procedure OST-1052 between March and June 1996 (Section H8.2). Failure t'o test PAL door caused violation of TS 4.6. 1.3.a. (Section H8.5) Operation outside design basis by connecting non-'eismic piping to RWST causing TS violations. (Section E8. 1) Failure to properly perform TS surveillance testing (Section H8.1) . Failure to perform surveillance testing required by TS (Section H8.2). Failure to perform surveillance testing required by TS (Section M8.2). Inadequate post maintenance testing f'ollowing repairs on containment isolation valve 1SP-208 (Section H8.3). Manual reactor trip due to loss of normal service water (Section H8.4). 50-400/96-018-01 LER 50-400/96-005-00 LER 50-400/96-013-00 LER 50-400/96-013-01 LER 50-400/96-013-02 LER 50-400/96-008-00 LER 50-400/96-008-01 LER 50-400/96-04-04 URI Discussed 50-400/97-020-00 LER 23 Hanual reactor trip due to loss of normal service water (Section H8.4). Failure to properly test the containment building outer personnel air lock door (Section H8.5). Condition outside of design basis where RWST had been aligned with a non-seismically qualified system (Section E8.1) ~ Condition outside of design basis where RWST had been aligned with a non-seismically qualified system (Section E8.1) . Condition outside of design basis where RWST had been aligned with a non-seismically qualified system (Section E8.1). Reactor trip due to the failure of a switchyard breaker disconnect switch (Section E8.2). Reactor trip due to the failure of a switchyard breaker disconnect switch (Section E8.2). Tracking FSAR discrepancy resolution (Section E8.3). Inadequate fire protection provided for safety-related EDG fuel oil transfer pump cables resulting in operation outside design basis (Section F2.1).