ML16341F188
| ML16341F188 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 05/16/1989 |
| From: | Mendonca M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F189 | List: |
| References | |
| 50-275-89-09, 50-275-89-9, 50-323-89-09, 50-323-89-9, NUDOCS 8906050279 | |
| Download: ML16341F188 (38) | |
See also: IR 05000275/1989009
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REgION
V
Report Nos:
50-275/89-09
and 50-323/89-09
Docket Nos:
50-275
and 50-323
License
Nos:
DPR-80 and
Licensee:
Pacific Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
Facility Name:
Diablo Canyon Units 1 and
2
Inspection at:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
March 5,
1989 through April 22 and
May 5,
1989
Inspectors:
P.
P. Narbut, Senior Resident Inspector
Approved by:
K.
E. Johnston,
Resident
Inspector
M.
M. Mendonca,
Chief
Reactor Projects
Section
1
~r ~Ye
Date Signed
~Summar:
Ins ection from March
5 throu
h
A ril 22 and
Ma
5
1989
Re ort Nos.
50-275/89-09
and 50-323/89-09
Areas Ins ected:
The inspection included routine inspections
of plant
operations,.
maintenance
and surveillance activities, follow-up of on-site
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
30703,
37702,
40500,
61726,
62703,
71707,
71710,
90712,
92700,
92701,
92702,
92720,
93702,
and
94703 were used
as guidance during this inspection.
Results of Ins ection:
No violations or deviations
were identified.
Areas of Stren ths
During the reporting period, the following strengths
were noted:
o
The licensee
has
expanded
the use of "Justification for Continued
Operation"
(JCO) evaluations.
The JCOs,
which were performed
on 10 CFR Part 21 issues,
the steam generator
tube plug issue,
and the leaking Unit
2 pressurizer
safety relief valve, indicate
a licensee
trend towards
06050278
890515
DR
ADOCK 09500
l2575
6
timely performance
analysis of plant and industry problems
as they apply
to the operational
safety of the Units.
o
It was noted that the licensee's
decision to shutdown to repair the
leaking Unit 2 pressurizer
a conservative
decision
made in the interest of safety.
The Technical Specifications
did not require
shutdown
and industry experience
was available to
indicate that the valve may have continued to be functional with greater
leak rates.
o
The licensee initiated a quarterly System Status
Report Program,
in which
the system engineer
and design engineer
review existing problems,
perform
a system walkdown,
and summarize planning
and proposed actions in a
report for management's
review.
Although the program is in its formative
stages, it appears
that the program will be
a good vehicle to strengthen
engineering
involvement in plant activities
and problems.
Areas of Weakness
During the reporting period weaknesses
were noted
as follows:
o
Continued instances
of equipment misalignment were noted.
Specific
examples
were the plant vent radiation monitor misalignment (section 4h)
and the racked out circulating water
pump potential
transformers
(section
41). It should
be noted that subsequent
to this report period,
on April
25, 1989, during an enforcement
conference
(see
Inspection
Report
50-275/89-15),
the licensee
proposed
extensive revisions to their
equipment lineup program to address
this problem area.
o
The licensee's
program for lubrication of important manual
valves
was
found to be not fully implemented despite
the fact that the issue
had
received
management
attention
subsequent
to a team inspection in February
1987.
The failure of the licensee
to ensure that such
commitments
are
successfully
completed in a timely and thorough manner
was
a subject of
the enforcement
conference
of April 25,
1989 (Inspection
Report
50-275/89-15).
DETAILS
Persons
Contacted
J;
D. Townsend,
Plant Manager
"D. B. Miklush, Assistant Plant Manager,
Maintenance
Services
"L'. F.
Womack, Assistant Plant Manager,
Operations
Services
B.
W. Giffin, Assistant Plant Manager,
Technical
Services
"C.
L. Eldridge, Quality Control Manager
"W. T.
Rapp, Onsite Safety
Review Group Chairman
T.
A. Bennett,
Maintenance
Manager
"D. A. Taggert, Director Quality Support
"B.
D. Guilbeault, Material Services
Manager
W.
G. Crockett,
Instrumentation
and Control Maintenance
Manager
J.
V. Boots,
Chemistry
and Radiation Protection
Manager
"T.
L. Grebel,
Regulatory Compliance Supervisor
"M. J.
Angus,
Work Planning
Manager
"J.
A. Shoulders,
Onsite Project Engineering
Group Manager
"M.
E.
Leppke,
Engineering
Manager
S.
R. Fridley, Operations
Manager
R.
P.
Powers,
Radiation Protection
Manager
M.
R. Tresler,
Project Engineer
E.
C. Connell, Assistant Project Engineer
The inspectors
interviewed several
other licensee
employees
including
shift foremen
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general
construction/startup
personnel.
Denotes
those attending the exit interview on May 5, 1989.
The exit
meeting
was delayed
from the week of April 22 due to the involvement
of plant management
and the inspectors
in preparations
for the
enforcement
conference
held on April 25,
1989.
0 erational
Status of Diablo Can
on Units 1 and
2
During the inspection period both units remained at 100K power except for
periodic condenser
cleaning
and an Unit 2 outage,
beginning April 7 and
continuing to April 15, to replace
a leaking pressurizer
code safety
relief valve.
Unit 2 experienced
an avoidable reactor trip on April 16,"
1989, at 50K power during power ascension
following the outage.
A load
rejection occurred
due to the opening of the units output breakers.
The
reactor did not operate
through the load rejection
as designed
due to the
loss of the ocean circulating water system
due to an electrical
equipment
lineup error.
Unit 1 operated at power throughout the inspection period.
3.
0 erational
Safet
Verification
71707
a ~
General
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's
facility.
The observations
and examinations
of those activities
were conducted
on a daily, weekly or monthly basis.
On a daily basis,
the inspectors
observed control
room activities to
verify compliance with selected
Limiting Conditions for Operations
(LCOs) as prescribed
in the facility Technical Specifications
(TS).
Logs, instrumentation,
recorder
traces,
and other operational
records
were examined to obtain information on plant conditions,
and
trends
were reviewed for compliance with regulatory requirements.
Shift turnovers
were observed
on a sample basis to verify that all
pertinent information of plant status
was relayed.
During each
week, the inspectors
toured the accessible
areas
of the facility to
observe
the following:
(a)
General plant and equipment conditions.
(b)
Fire hazards
and fire fighting equipment.
(c)
Radiation protection controls.
(d)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved procedures.
(e)
Interiors of electrical
and control panels.
(f)
Implementation of selected
portions of the licensee's
physical
security plan.
(g)
Plant housekeeping
and cleanliness.
(h)
Engineered safety feature
equipment alignment
and conditions.
(i)
Storage of pressurized
gas bottles.
The inspectors
talked with operators
in the control
room,
and other
plant personnel.
The discussions
centered
on pertinent topics of
general
plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
I
No violations or deviations
were identified.
4.
Onsite Event Follow-u
93702
a 0
Im ro er Control of Radio ra
h
On March 6, 1989, the licensee notified the residents
of problems
incurred by a radiography contractor
performing nondestructiVe
examination in the turbine building.
The contractor
had failed to
perform adequate
postings,
barriers,
and surveys.
These conditions
were found by the licensee's
health physics personnel
and the job
was stopped.
The licensee
concluded
were involved.
The highest exposure
was estimated
to be four mi llirem.
A
nonconformance
was written.
The regional inspection staff notified
the licensing authority for the radiographer
and action
was taken
by that authority.,
Auxiliar Buildin Ventilation Fan Fails to Start
Due to a
Maintenance
Error
On March 8, 1989,
mechanical
maintenance
personnel
reported off a
clearance
on Auxiliary Building Ventilation Fan S-33,
signed the
shift foreman's
Technical Specifications
sheet reporting that the
fan was operable
and indicated that
no work had been performed
on
Fan Discharge
Damper M-21 as scheduled.
Later that day,
when
operations
attempted to start
Fan S-33,
the fan failed to run
because
Fan Discharge
Damper M-21 failed to open.
It was later
discovered that the actuator for damper
M-21 had been in fact
partially disassembled
by the maintenance
mechanic.
The confusion
appeared
to stem from the mechanic's failure to document his actions
(which were beyond those stated
in the work order)
and poor verbal
turnover from the mechanic to his foreman
and that foreman to his
relief.
The licensee initiated a guality Evaluation
and an
evaluation in accordance
with the
Human Performance
Evaluation
System
(HPES).
The
HPES evaluation
had not been completed at the
end of the report period.
Licensee corrective action will be
followed up during routine inspection.
Ten Percent
Atmos heric Steam
Dum s 0 en At Power
On March 13, 1989, the Unit 2 10K steam
dump valves
opened
unexpectedly
when
a main turbine first stage
pressure
channel
(PT
506) was
removed from service for calibration.
The licensee
determined that the actuation resulted
from an out of
calibration module which inputs to steam
dump demand logic.
Further, it was determined that the module was out of calibration
because
contract technicians,
while attempting to calibrate
another
module,
had inadvertently adjusted
the wrong module.
The licensee
determined the root cause to be personnel
error with
the technicians failing to perform adequate self-verification.
Corrective actions
focused
on emphasizing
the self-verification
policy and to revise existing policy,to allow only experienced
technicians
to work independently in the "Hagan" racks,
which
contain plant controls instrumentation.
The inspector
has reviewed
the licensee's
actions
and found them acceptable.
Unit 1 Containment Ventilation Isolation
On March 14, 1989, Unit 1 experienced
a containment ventilation
isolation (CVI) due to an I8C technician working on leads to the
Equipment
Rooms temperature
monitor annunciator
alarm.
The
technician inadvertently grounded the power lead with a screwdriver.
This resulted in a voltage transient
on a vital instrument inverter
which initiated the CVI.
The licensee
prepared
nonconformance
report
NCR DCI-89-TI N027 and event report LER-1-89-001.
Corrective actions described
in the
LER involve counseling the
technician regarding precautions
for working on energized
equipment,
training all I8C technicians
on the event,
and developing
a policy
to clear
power circuits whenever feasible
(as it was in this case).
The inspector
found these
actions acceptable.
Wron
Oil Used In Turbine Driven Auxiliar
Pum
s=
On March 18,
1989, the licensee
operations
personnel
discovered that
the wrong oil had been
used in Auxiliary Feedwater
Pump 2-1 when oil
in the turbine
had been
changed following testing.
The pump was declared
inoperable, its oil was changed
and it was
declared
the next day after analysis,
testing
and
contacting the vendor.
The vendor
had stated that due to its
slightly higher viscosity, the oil used
may have resulted in
slightly higher bearing temperatures
but was not harmful.
On the
same
day of the event,
the licensee
launched
an investigation
first into the other auxiliary feedwater
pumps
and then into all
other safety related
pumps to determine if any other
pumps
had
received
improper oil.
The results of the investigation
showed that
Unit 1 auxiliary feedwater
pump l-l had also received the wrong oil.
Additionally, the investigation revealed that containment
spray
pump
2-2 was not in the recurring task work order program and
consequently
did not have its oil changed
every 18 months
and had
not had an oil change
since August 8, 1985.
The other containment
spray
pumps (l-l, 1-2,
and 2-1) had been properly handled.
The primary cause of the lubrication problems
were:
1) for the
pumps,
the recurring task work orders specified
the wrong oil contrary to the licensee's
lubrication schedule.
A
total of four incorrect work orders
were found involving three
separate
work planners;
and 2) for the containment
spray
pump motor,
the problem appeared
to stem from the conversion
(from one system to
another) of the computer tracking of recurring tasks.
The licensee
prepared
two nonconformances
on the problems,
DC2"89
WP N029 for the auxiliary feedwater
pumps
and
NCR DCO-89
WP
N030 for the containment
spray
pumps.
The licensee
s initial
actions
were sufficient to thoroughly examine for other lubrication
problems.
The licensee's
actions to prevent recurrence
did not
initially appear to require
independent verification of work order
accuracy.
The licensee's
actions in this regard were couched in
language
such
as "Research
the possibility of gC verification of
correctness
of oil types."
Initial discussions
with the Assistant Plant Manager for Maintenance
indicated that the verification of work. order accuracy
was intended
to be the responsibility of the job foreman.
He stated this
responsibility would be reemphasized
in a maintenance bulletin.
The
inspectors will follow-up the licensee's
actions regarding
verification activities in the work planning center
(Follow-up item
50-275/89-09-01).
Fire Water Valves not in Sealed
Valve Pro
ram
On March 20, 1989,
a licensee guality Assurance
audit identified two
valves that were not sealed to verify position as required
by
Technical Specifications (TS) 4.7.9. l.c.
The valves were fire
protection valves
and FP-2-1294.
The valves
wer e in their
required
open position.
The valves
had been
added to the fire
protection
system in December
1988 as part of a design
change .to
provide an alternate
source of cooling water to the charging
pump
seal
and oil coolers.
The licensee
prepared
a nonconformance
report (DCP-89-SS-N033)
and
an event report
(LER 1-89-003).
The details of the event
and the
licensee's
corrective action were reviewed
and determined to be
acceptable
by the inspector.
LER 1-89-003 is closed.
Leakin
Pressurizer
Code Safet
Valve and Resultin
Un lanned Outa
e
On March 21,
1989, Unit 2 Pressurizer
Code Safety Relief Valve 8010A
was identified to be leaking at approximately 0.2
gpm.
The valve
exhibited
an unexpected
leakage characteristic
in that the leakage
was not constant
and would periodically appear
in the form of relief
discharge line sonic and temperature
alarms.
The resultant
leakage
rate over
2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> periods
averaged
about 0.2
gpm.
Sonic alarms
were
received
over
a period of days.
Alarms were received
from as few as
2 per day to as
many as
12 per day.
The duration of the alarms
were
generally several
seconds
and in a few cases
minutes in duration,
the longest being
6 minutes
and ll seconds
on April 3,
1989.
The
leakage
was in some
cases
accompanied by'ressurizer relief tank
pressure
incr eases,
and in a few cases,
a pressurizer
pressure
decrease.
Operations with the leaking valve continued until April
8,
1989 when the unit was shut
down to replace
the valve.
The
shutdown
was precipitated
by increased
short duration leakage of up
to 3 gpm.
Between
March 21, 1989,
and the plant shutdown,
the licensee's
safety evaluation (justification for continued operations)
was based
on the following:
Technical Specification 3.4.6.2,
(RCS)
Leakage Limits, identified
RCS leakage to 10 gpm.
This limit
was based
in part on the ability of the charging
system to make
up the leakage.
Therefore,
the leakage
did not violate
technical specification limits.
Discussions
with other utilities indicated that the leakage
characteristic
experienced
at Diablo Canyon
was similar to that
experienced
at other sites.
In some cases,
other sites
had
operated for extended
periods of time.
h
5
IH
o
Discussions with other utilities and the vendor revealed that
this phenomena
had not resulted in valve failures
and did not
represent
a severely
degraded
valve.
o
The licensee
determined that leakage
past the seat of the valve
would not affect valve actuation if required to function.
The licensee
issued
a safety evaluation (justification for continued
operations)
on April 6, 1989.
During the week long outage,
the licensee
took Unit 2 to Mode 5
(cold shutdown),
removed the Pressurizer
Relief Valve 8010A and
replaced it with a spare
valve (originally, Unit 1 valve 8010B).
The licensee
found that the spare
valve had
a slightly larger inlet
flange (as cast)
and did not provide proper clearances
with the
seismic restraint installed for the-original valve.
The licensee
initiated a Design
Change
Package
(DCP) to provide the proper
clearances.
The inspector
reviewed the
DCP and witnessed portions
of the installation effort and found them acceptable.
The inspector also inquired to what extent pressurizer
relief valves
had been
"swapped"
and if it was possible
any had been inserted in
restraints with inadequately
clearance.
The maintenance
engineer
responsible
for pipe supports
and restraints
stated
the issue
had
been
reviewed
and that for Unit 1, the unit in operation at the
time, all valves
had been in place since original startup.
For the
Unit 1 valves,
hot functional tests
and,
on subsequent
startups,
walkdowns performed in conjunction with the snubber reduction
program provided assurance
that binding was not taking place.
In
addition,
none of the valves
had
shown any excessive
leakage
(a
possible result of binding).
Unit 2 valves
8010B and 8010C
had also
been in place since startup
and subject to hot functional testing.
The licensee
committed to revise the valve installation procedure
to
include steps to verify the gap between
the valve and the pipe
restraint.
The inspector
found these
proposed actions acceptable.
Plant Vent Radiation Monitor Ino erable
Due to Valve Misali nment
On March 27, 1989, operating personnel
discovered that one set of
the radiation monitors for monitoring the plant vent for noble gas
(RM-14A) and for particulate contamination
(RM-28A) was inoperable
due to a mispositioned switch.
The switch was in the "purge"
position rather
than the "sample" position causing the monitors to
sample air from the auxiliary building environment rather than from
the plant vent.
Licensee analysis
determined that the switch had been
most probably
mispositioned
by IKC personnel
on March 23, 1989,
subsequent
to
maintenance.
During the period of inoperability
a containment
purge
was conducted
on March 25,
1989.
However during this purge the
second set of pl.ant vent monitors
(RM-14B and
RM-28B) were operable,
as were the containment monitors (RM-ll and RM-12) which did not
indicate
a problem with the discharge.
The licensee
prepared
a nonconformance
report and an event report
LER 1-89-004 describing the event
and corrective actions.
The inspectors
reviewed the licensee corrective actions
and found
them to be acceptable.
The actions
included improvements
in
detailed verifications for the operating procedure
for containment
purging, the I8C procedure for returning the radiation monitoring
equipment to service
and, the operating procedure for swift
operability checks.
The licensee
actions also include the broader
action of revising all I8C procedures
to add specific item-by-item
steps
to be checked
and verified in returning equipment to service.
Not included in the
LER were broader actions
committed to in an
April 25,
1989,
enforcement
conference
(NRC report 50-275/89-15) in
which the licensee
committed to actions to improve personnel
accountability
and equipment lineup control.
LER 1-89-004 is considered
closed.
The activities discussed
in this section involved apparent
or
potential violation of NRC requirements
identified by the licensee
for which appropriate
licensee
actions
were taken or initiated.
Consistent with Section
V.A of the
enforcement action was .not initiated by Region
V.
Containment Ventilation Isolation
Due to Failed Fuses
on Plant Vent
Radiation Monitor
On March 31, 1989, at 8: 52 a.m.,
fuses for Unit 2 instrument
power
supplying plant ventilation radiation monitor RM-28 blew,
deenergizing
the radiation monitor and initiating a Containment
Ventilation Isolation (CVI).
This event is described
in
LER
2-89-03,
issued April 28,
1989.
The licensee's
troubleshooting
and investigative activities were not
successful
in determining the root cause of the blown fuses.
There
have
been
no previous similar failures at Diablo Canyon,
and the
vendor (Westinghouse)
indicated that
no similar failures of
radiation monitor instrument power fuses
have
been reported.
The
subject fuses
have
been sent to a laboratory for analysis.
The inspector
reviewed the licensee's
troubleshooting
and
investigative activities and found them to be comprehensive.
LER
2"89"03 is closed.
I
Hi h Motor Stator
Tem eratures
Due to Hot Weather
On April 7, 1989, during a period of unusually hot weather at the
site the inspector
noted
a number of vital and
non vital pump motors
were alarmed
due to high stator
temperature.
The inspector
questioned
operators
as to what their procedures
required
them to do
and at what point they would question operability.
The results of
the conversations
were that the operators
had previous experience
with hot weather,
knew the alarm setpoints
were about
230 degrees
F
and considered
the situation unavoidable
but were alert to check
and
trend for temperatures
in excess
of those previously experienced.
The inspector discussed
the situation with operations
management
who
committed to have operability limits defined
and incorporated in
response
procedures.
Maintenance
engineering
personnel
subsequently
provided. information which indicated that motor
manufacturers
consider the motors in question rated for 40 year life
with stator temperatures
of 248 degrees
F of less.
The inspector also questioned
the
gC manager
as to what degree
the
gC personnel
involved in operations
were instructed to look for such
situations
and elevate
them to attention.
The
gC manager
explained
that
gC could surface
such questions
and raise
them to management
attention through several
means.
The licensee's
actions
regarding this matter appeared
to be
acceptable
with the exception of a lack of aggressive
problem
identification on the part of operations
and
gC in recognizing the
absence
of pertinent temperature limit information from engineering
personnel.
This will be followed on routine inspection.
Feedwater Isolation
Due to Hi Steam Generator
Level
On April 8, 1989, at 1:39 p.m., while Unit 2 was in Mode
3 (Hot
Standby) in the process .of a cooldown to cold shutdown for repairs
on the leaking pressurizer
safety valve,
2-4 water
level exceeded its high-high level setpoint, initiating feedwater
isolation and turbine trip signals.
The high-high level resulted
from Loop 4 main feedwater isolation valve testing.
Prior to the
test,
which is required
on a shutdown frequency,
the operators
verified that the main feedwater regulating
and bypass
valves were
closed.
However,
when the upstream
main feedwater isolation valve
was
opened for testing
level increased.
Since the
valve must fully open prior to closure,
and full cycle takes
approximately
2 minutes,
level increased
to its
high-high level setpoint before the valve could be closed.
The
inspector verified selected
portions of this event.
The licensee
will issue
an
LER describing the event.
The cause
and corrective
actions
discussed
in the
LER will be reviewed in a future inspection.
Unit 2 Reactor Tri
Followin
Generator
Loss of Load
On April 16,
1989 at 8:05 p.m., following the unexpected
opening of
the Unit 2 generator
output breakers,
a reactor trip resulted
from
low steam generator
level.
All safety
systems
responded
to the
reactor trip as designed.
However, the reactor trip was not
expected
since the plant is designed
to withstand
a 50K load
rejection without a reactor trip by the use of steam
dumps'.
Event Oescri tion
At 8:05 p.m., the generator
output breakers
(PCBs
542 and 642)
opened
as
a result of the actuation of Generator
Backup Relay 21G2.
'elay
21G2 is
a slow acting backup
system
designed to detect faults
from the generator
output through the transmission
lines.
At the
same time,
a transfer
from auxiliary power (normal alignment from
the main generator)
to startup
power was initiated by Generator
Relay 27G2.
In the transfer to startup
power, the
Circulating Water
Pump
(CWP) selected for auto transfer did not load
onto the star tup bus.
The loss of the
CWP disabled the condenser'steam
dumps.
The opening
of the output breakers
resulted in a loss of load to the turbine.
Without the condenser
steam
dumps,
steam line pressure
and
pressure
elevated to.the
lOX atmospheric
steam
dump set point of
1035 psi
and the pressurizer
power operated relief valve
(PORV)
setpoint of 2335 psi, respectively,
actuating
both sets of valves.
In addition, the reduced
steam flow caused
level to
shrink.
Fourteen
seconds
following the opening of the output
breakers,
the reactor tripped on low steam generator level.
The
system
behaved
as designed, given the loss of condenser
steam
dumps.
All safety
systems
responded
as designed.
Following the event there were three
areas
not understood
by the
licensee:
o
The cause of the actuation of Generator
Backup Relay 21G2.
o
The cause of the actuation of Generator
Relay
27G2.
o
The cause of the
CWP failing to load onto the startup
bus.
Other minor problems experienced
following the event included:
o
15 minutes following the trip, the unit differential current
began to "chatter"
and created
a nuisance
alarm.
The differential current relay had not actuated
and there
was
no current in the system
when the annunciator
actuated.
o
The backup event recording
system did not actuate
and save data
as designed.
Likewise a temporary annunciator
alarm typewriter
did not function.
o
Reactor
Coolant
Pump 2-4 indicated excessive
vibration
following the event.
The licensee initiated an Event Investigation
Team (EIT) in
accordance
with plant procedures
on the morning following the event.
Generator
Backu
and Undervolta
e Rela
Actuations
The licensee
was unable to determine
the cause of the actuation of
Relays'1G2
and
27G2.
The investigation
focused
on all potential
causes
for the actuation including:
10
o
An inspection of the motor operated
disconnects
on the
generator;
o
An inspection of transmission
lines to the substation;
o
and subsequent
functional testing of relays
21G2,
27G2,
and time delay relay 62G2;
o
Continuity testing from the potential transformers
(PTs) which
supply generator voltages.to
the relays.
This included
turn-to-turn measurements
on the primary and secondary
sides of
the
PTs.
While the licensee's
investigation did not identify any
abnormalities, it was determined that
a momentary loss of the
B
phase
PT voltage would initiate the sequence
of events
as
experienced.
Prior to plant startup
on April 19 the licensee
instrumented all phases
of the
PT in question
and Relay 21G2.
The
inspectors
concluded this plan was acceptable.
~CWP Tri
On the transfer
from auxiliary to star tup power initiated by relay
27G2, the breaker for the
CWP 2-1 motor, which was selected for auto
transfer,
should
have tripped and then re-closed
when motor voltage
had. adequately
decayed.
The breaker tripped, but failed to
re-close.
On inspection of the breaker it was found that the
breaker
PT drawer
had been racked out.
This occurred
because
of
equipment lineup problems during the one week outage to repair
a
leaking pressurizer
code safety valve.
The
CWP breaker
PT provides motor voltages to the motor undervoltage
relay.
The relay is a permissive in the breaker
auto transfer logic
that will not allow the breaker to close until the motor voltage
has
decayed to 25K.
With the
PT drawer racked out, the undervoltage
permissive
was active
so that without any time delay following the
trip signal, the breaker received
a close signal.
The breaker's
anti-pumping relay, which actuates
when the breaker receives
conflicting instructions,
actuated to keep the breaker tripped.
This explanation
was subsequently
verified by testing.
The
PT drawer
was
opened during the seven
day pressurizer relief
valve maintenance
outage
and not reclosed prior to the restart of
the
CWP.
The
CWP motor breaker
had been cleared for cleaning of the
circulatinq water tunnels.
The clearance
request
issued for the
cleaning required the clearing of the
CWP motor breaker.
The
clearance
procedure
(NPAP C-6 Revision 6) required that
a switching
log be used
when clearing electrical
equipment.
Switching of 12kV
breakers
was controlled by operations" procedure
OP J-5: IV Revision
5, "Operating Procedure
12
KV Breaker
Code Order," which included
generic switching logs for 12kV breakers.
Step
Number
9 of the
removal
from service switching log states
for the
PT drawers
"Rack"out and hang
MOL LMan On Linej tag (if applicable)."
Although the clearance
request did not include
a step to rack out
the
PT drawer, operating procedure
OP E-4: III, "Circulating Mater
System - Shutdown
and Clearing" required that the
be racked out
when clearing the motor.
The operator filling out the switching log crossed
out "hang
MOL tag
(if applicable)"
and racked out the
PT drawer.
Three
days later,
another operator
returning the motor to service,
using
a return to
service switching log and the clearance
request,
marked the step to
rack the
PT drawer in as "N/A" and did not rack in the breaker.
The
PT drawer is located in back of the breaker cubicle.
Since the
drawer only inputs to the auto transfer logic, the
pump was able to
startup.
The inspector identified the following weaknesses;
o
The procedures
applicable to the switching of electrical
equipment conflicted and
as
a result were not adequate
to
ensure that the task was accomplished correctly.
1)
The return to service switching log did not require the
use of the remove from service switching log as
a
reference.
2)
The procedure did not reference
switching procedure
OP
J-5: IV to require the use of the switching log.
3)
The clearance
procedure
NPAP C-6 required the use. of the
switching log, but did not specify
how the two are to
interface.
~
o
The operator
removing the breaker
from service did not modify
the clearance
to indicate that the
PT drawer was racked out.
o
The operator
returning the breaker to service did not verify
that the
PT was not racked out prior to marking the step to
rack it in "N/A."
The inspector discussed
these findings with the Assistant Plant
Manager for Operation
who agreed with the findings and stated that
corrective actions
such
as breaker specific switching logs, revised
procedures,
and operator training had been initiated.
Equipment lineup errors,
such
as this,
have
been
an issue in
previous reports (Inspection Reports
89-05 and 89-13)
and the
subject of the Enforcement
Conference
on April 25,
1989 (Inspection
Report 89-15).
In this instance,
procedures
for equipment lineup
were not adequate
to ensure that switching was satisfactorily
accomplished.
As a result, following a load rejection which the
plant was designed to accommodate
without a reactor trip, the
reactor
nonetheless
tripped and unnecessarily
challenged
safety
systems.
This is an apparent violation identified by the licensee
for which appropriate
licensee
actions
were initiated.
Consistent
with Section
V.A of the 10 CFR Part 2, Appendix C, enforcement
discretion
was exercised
by Region
V.
The corrective actions
12
discussed
in the April 25,
1989 meeting will be the subject of
follow-up inspection.
Wron
Sized Part
Used
on Fan Motors
On April 19, 1989, the licensee
became
aware of a problem with
replacement
parts
used
on Auxiliary Building Fan S-32.
The fan is
belt driven by an electric motor.
The motors belt sheave
had been
replaced,
due to wear,
on April ll and was declared
on
April 14,
1989.
The belt sheave
was oversize
and resulted in higher
fan speed
and greater
motor current draw.
The problem was
discovered
on April 17, 1989, duringdelayed post maintenance
testing
and
came to managements
attention
on April 19,
1989.
The occurrence
involved several
weaknesses
and errors in the
execution of the licensee's
maintenance
program
and parts dedication
program.
The wrong part was installed
due to poor understanding
of
part number meaning,
improper tagging of the part,
mechanics
improperly verifying size,
and poorly laid out work orders which did
not require the acquisition of fan operating data before declaration
of operability.
Licensee
management
recognized
the seriousness
of the error and the
multiple mistakes
made.
They investigated
the effects ot the
mistake including breaker settings,
diesel
fuel oil consumption,
diesel
loadings, air flow disturbances,
and fan and motor effects.
Overall, the licensee. concluded that the involved systems
were not
impaired.
The licensee
prepared
a nonconformance
report on the problem.
The
inspectors will follow-up the licensee's
actions to prevent
recurrence.
10 CFR 50.59 Evaluations
Justifications for Continued
0 eration
a.
NPS Industries
10 CFR Part 21 Notification Re ardin
Potentiall
Defective Struts
and Snubbers
On March 7, 1989,
NPS Industries transmitted
notification to the licensee
advising that certain
model struts
and
were potentially defective.
The licensee
had purchased
255
of the potentially defective struts
and
no effected snubbers.
The licensee
designed piping systems
such that given the combination
of all potential
movement,
including thermal
and seismic
movement,
struts
and snubbers
would be required to swing less
than
a five
degree
angle.
Their acceptance
criteria on the installation of
'truts
and snubbers
has
been that they accommodate
a greater
than
five degree
swing.
In summary,
the
10 CFR Part 21 report stated
that, given the combination of unfavorable tolerances,
certain
struts'ould
have
a less
than five degree
swing angle.
13
The licensee
performed
a 10.CFR 50.59 evaluation (Justification For
Continued Operation).
In summary,
continued operation
was based
on
the following:
o
The safety evaluation
by NPSI, which in essence
states that
a
strut will still accept rated load following deformation except
in situations
where repeated yielding could occur.
o
~
Initial hot functional
and post refueling walkdowns
have not
indicated failures of a nature described in the vendor's
10 CFR Part 21 analysis.
o
A walk down of all accessible
struts with potential for
inadequate
swing allowances will be performed prior to the next
refueling outages.
By the completion of the next refueling
outages,
all affected struts will have
been identified and
corrected.
The inspector
found this evaluation
and corrective action
acceptable.
b.
Tube Plu
s
On January
17, 1989, Westinghouse
informed several
licensees
that
a
few utilities had observed dripping or wetness
around tube ends
plugged with Westinghouse
mechanical
plugs
and that upon further
examination
the plugs were failing due to inter-granular
stress
corrosion cracking
(IGSCC).
further identified two
heats of plugs which appeared
to be susceptible
to
IGSCC due to
inadequate
heat treating.
Subsequently,
North Anna Unit 1
experienced
a failure of a steam generator
tube plug which had been
identified as susceptible
to IGSCC.
The failed plug was forced
through the dry steam generator
tube
and punctured the tube at the
U-bend, resulting in a 70
gpm primary to secondary
leak.
notified Diablo Canyon of 23 steam generator
tube plugs
installed in Unit 2 from the affected heats.
In response
to this
notification and
on April ll, 1988,
the licensee
performed
a 50.59 evaluation.
In summary,
the licensee
based its evaluation
on the following
factors;
o
19 of the 23 tube plugs were "sentinel" plugs installed in the
1988 refueling outage.
These plugs,
which are only installed
in tubes that have not developed
leakage,
are designed with a
small
opening in the plug to serve
as
a warning if the tube
subsequently fails't was determined
by the licensee
and
that since these
tubes plugs
have water
on both
sides of the tube plug,
a broken tube plug could not establish
enough force to rupture the tube wall.
o
Of the remaining four tubes plugs, all of which were installed
in 1987,
two were located in a tube with a small hole.
As a
0
14
result the tube was completely filled and, similar to the
sentinel
plugs, the plugs would not be capable of acquiring the
force to rupture
a tube.
o
It was determined that two remaining plugs in one dry tube
could potentially fail and cause
a tube rupture.
o
The North Anna hot leg temperature
is 618 degrees
F whereas
the
Diablo Canyon hot leg temperature
is 606 degrees
'F.
Since the
rate of IGSCC is temperature
dependent,
this provides
some
degree of margin.
o
determined that primary to secondary
leakage
would
be limited to 77
gpm since flow would be restricted
by the
intact portion of the plug.
In addition, it was determined
that the propelled portion of the plug, after exiting the tube,
would not have
enough
energy to rupture
a second
tube.
o
The plant design basis
assumes
a much larger steam generator
tube rupture than
77
gpm.
Plant design
and emergency
operating
procedures
are based
on primary to secondary
leaks
much greater
than this.
The licensee
determined that based
o'n the above, Unit 2 could safely
operate to its next refueling outage at the beginning of 1990.
Long
t'erm corrective actions
had not been identified at the time of this
report, but were to be the subject of generic discussions
between
the
NRC, and all affected licensees.
The inspector
found the licensee's
evaluation acceptable.
No violations or deviations
were identified.
6.
Maintenance
62703
a o
Maintenance Activit Observation
The inspectors
observed portions of, and reviewed records
on, the
following maintenance activities to assure
compliance with approved
procedures,
Technical Specifications,
and appropriate
industry codes
and standards.
Furthermore,
the inspectors verified maintenance
activities were performed
by qualified personnel,
in accordance
with
fire protection
and housekeeping
controls,
and replacement
parts
were appropriately certified.
o
Diesel generator air start motor air regulator
replacement
o
Leak repair of Main Steam
Line Drain Valve MS-2-909
o
10K Steam
Dump Valve PCV-2-22 positioner adjustment
o
Centrifugal Charging
Pump 1-1 lube oil pump removal
o
Unit 2 pressurizer
code safety valve 8010A replacement.
15
b.
Maintenance of Manual Valves Called
On In Emer
enc
and Abnormal
Procedures
An NRC team inspection,
conducted
in February
1987 (Inspection
Report 87-01) identified that the licensee
did not have
a
maintenance
program for manual
valves.
During the inspection,
the
licensee
stated that the development of a program was
underway
and
it would address
the maintenance
of manual
valves that need to be
operated
during accident
and recovery periods.
In a June
15,
1987.
letter, the licensee
stated that Operations
would implement
a manual
valve exercising
and lubrication program for manual
valves that
may
be needed for the mitigation of significant transient
events.
The licensee
completed this commitment in June
1988,
by adding steps
to the sealed
valve verification procedure requiring all sealed
valves to be lubricated
and stroked.
One of the discrepancies
identified by Engineering in the
development of a design basis
document for the Auxiliary Feedwater
system
was that the cross"tie valves
between outlets of the two
motor driven pumps,
which are cal.led
upon in emergency
procedures,
were not in any maintenance
program.
The inspector discussed
this
finding with the Operations
Manager,
noting that there potentially
was
a large
number of valves
needed for "the mitigation of
significant transient events,"
which were not in, the sealed
valve
program.
The Operations
Manager concurred
and committed to have
a
comprehensive
review of emergency
and abnormal
procedures
to
identify those valves not covered
by the sealed
valve program.
Although the
new commitment is acceptable,
this is the action which
the inspector
expected
to have
been conducted initially.
While the
addition of a step to the sealed
valve program
was
a quick and easy
initial step, it is readily apparent that it alone did not fully
address
the commitment.
No violations or deviations
were identified.
Sur vei 1 lance
61726
By direct observation
and record review of selected
surveillance testing,
the inspectors
assured
compliance with TS requirements
and plant
procedures.
The inspectors verified that test equipment
was calibrated,
and acceptance
criteria were met or appropriately dispositioned.
The
inspectors
observed
selected
portions of Surveillance Test Procedure I-lA
and found it acceptable.
No violations or deviations
wer e identified.
En ineerin
Safet
Feature Verification
71710
The inspector walked
down the Unit 1 high head
and intermediate
head
safety injection systems
in accordance
with Inspection
Procedure
71710.
No findings were identified.
No violations or deviations
were identified.
9.
Radi ol o ical Protecti on
71707
'l
The inspectors periodically observed radiological protection practices to
determine whether the licensee's
program was being implemented in
conformance with facility policies
and procedures
and in compliance with
regulatory requirements.
The inspectors verified that health physics
supervisors
and professionals
conducted frequent plant tours to observe
activities in progress
and were generally
aware of significant plant
activities, particularly those related to radiological conditions and/or
challenges.
ALARA consideration
was found to be an integral part of each
radiation work permit.
No violations or deviations
were identified.
10.
Ph sical Securit
71707
Security activities were observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative procedures
including vehicle and personnel
access
screening,
personnel
badging, site security force manning,
compensatory
measures,
and protected
and vital area integrity.
Exterior lighting was
checked during backshift inspections.
II
No violations or deviations
were identified.
~
~
ll.
Licensee
Event
Re ort Follow-u
92700
Status of LERs
The
LERs identified below were also closed out after in-office review and
follow-up inspections
were performed
by the inspectors
to verify licensee
corrective actions:
Unit 1:
87-06 (Rev.l), 88"17, 88-21, 88-23, 88-24, 88-24
(Rev.l), 89-01, 89-04, 84-40,
87-23 (Rev. 1), 88-04,
88-26, 88-26 (Rev. 1), 88-28 (Rev. 1), 89-02, 89-03, 88-32
and Special
Report 89-01.
Unit 2:
88-06, 88-09, 88-21, 88-21 (Rev.
1) 88-22,
88-22 (Rev. 1),
89-03, 87-21, 88-10,
88-13 (Rev. 1), 88-12, 89-01, 89"Ol
(Rev.
1) and 88-25.
No violations or deviations
were identified.
12.
0 en Item Follow-u
92703
92702
a.
Ade uac
of Root Cause
Evaluation for Ino erable
Over ower
Differential
Tem erature
OPDT
Channel
Unresolved
Item
50-275/88-21-01
Closed
As noted in the cover letter of Inspection
Report 50-275/88-21,
the
statement that "no corrective actions to procedures
or training were
17
recommended"
in
LER 1-88-21 was not acceptable.
The inspection
report documented
the licensee's
commitment to submit
a revision to
the
LER to provide clarification of root cause
and corrective
actions.
On November 14,
1988, the licensee
submitted
a revision to
LER 1-88"24.
The revised
LER provided acceptable clarifications to the root cause
evaluation
and the analysis of the event.
Corrective actions
described
were more detailed than Revision
0 of the
LER, specifying
functional testing
and training requirements
ss well as procedure
changes.
These
wer e found to be acceptable.
The item was determined to be unresolved
in Inspection
Report
50-275/88-21
based
on the lack of corrective actions
taken in
response
to a Technical Specification violation. It was
subsequently
determined that the licensee's
nonconformance
process
had not been completed
and the
NCR review chairman stated that
appropriate corrective actions
were being actively considered
at the
time of issuance
of the
LER.
The inspector discussed
with plant
management
that, in situations
such at this one,
a note is needed
in
the
LER that the review of an event
has not been
completed
and
a
revision is forthcoming.
Based
on the corrective actions described
in the
LER this item is closed.
This also completes
the review of
revisions
0 and
1 of LER 50-275/88-24.
b.
Line Seismic Restraint'no
erable
Due to Inade uate
Confi uration
Mana ement
Follow-u
Item 50-323/ 87-43"Ol
Closed
This follow-up item incident concerned
a main steam line seismic
restraint that was modified and left inoperable in an operational
mode in which the line was required to be operable.
The primary
issue of the event was that work had
been
approved which affected
the op'erabi lity of equipment
by affecting its seismic qualification.
The inspector
reviewed the licensee's
corrective actions
and found
that they acceptably
addressed
the issues
of the incident.
However,
continued
instances
where work affects
equipment seismic
qualification in modes
where the equipment is required to be
continued to be an issue.
An example of this was the work
performed
on plant vent ducting as described
in the January
1989
team inspection report 50-275/89-01.
In addition, the configuration
management
program,
which the licensee
maintained will address
the
issues of maintaining the design basis in its initial stages.
Therefore, while Follow-up Item 50-323/87-43-01 is closed,
the
inspector will review these
issues
in future inspections
as
follow-up to the open items contained in Inspection
Report
50-275/89"01.
30703
On May 5, 1989,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.
Licensee
acknowledged
the concerns
and findings in the inspection report.