ML16341G537
| ML16341G537 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 04/17/1992 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341G538 | List: |
| References | |
| 50-275-92-05, 50-275-92-5, 50-323-92-05, 50-323-92-5, NUDOCS 9205050132 | |
| Download: ML16341G537 (32) | |
See also: IR 05000275/1992005
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION
V
Report Nos:
50-275/92-05
and 50-323/92-05
Docket Nos:
50-275
and 50-323
License
Nos:
and
Licensee:
Pacific
Gas
and Electric Company
77 Beale Street,
Room 1451
San Franci sco,
Californi a 94106
Facility Name: Diablo Canyon Units
1
and
2
Inspected at:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
February
4 through March 16, 1992-
Inspectors:
H. Wong, Senior Resident
Inspector
M. Miller, Resident
Inspector
Approved by:
P.
H. Jo
son, Chief, Reactor Projects
Section
0(I7fgz
Date Signed
Summary:
Ins ection from Februar
4 throu
h March
16
1992
Re ort Nos. 50-275/92-05
and 50-323 92-05
A~1: lt
i
i
i
1dd
i
i
i
f
operations,
maintenance
and surveillance activities, followup of onsite
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
61726,
62703,
71707,
71710,
92701,
and
92703 were
used
as guidance
during this inspection.
Safet
Issues
Mana ement
S stem
(SIMS
Items:
None
Results:
General
Conclusions
on Stren ths
and Weaknesses:
Strengths-
The licensee
organizations
quickly responded
to the unexpected
outage of
Unit 1 after the reactor trip of March 6,
1992.
The meetings
conducted
appeared
effective in determining the actions
necessary
to determine
the
cause of the feedwater
pump loss
and reactor trip and in prioritizing
work, activities.
9205050l32
V204l7
ADOCK 05000275
8
0
The licensee
response
to
a quadrant
power tilt alarm during
a power
reduction in Unit 2 on February
16,
1992 was timely and accurate.
Licensee
personnel
discussed
the matter with Westinghouse re~sartatives
and carefully monitored core flux parameters
to assure that the reason
for the alarm was understood
and that core flux behavior
was
as expected.
Weaknesses-
During investigation of the problems with containment
fan cooler units
(CFCUs), it was identified that installation errors
had occurred
which
had
gone undetected
and
had
caused
the
CFCUs to be inoperable for a
significant period of time.
In addition,
a problem with reverse rotation
of a
CFCU had
been identified, but had not been considered
abnormal
and,
therefore,
no actions
were taken to correct the problem.
This appears
to
indicate
a need for greater attention to those
work activities considered
relatively simple
and the
need for more thorough
and timely corrective
actions for deficient conditions.
This matter is still being reviewed
and will be discussed
in
a future
inspection report.
Si nificant Safet
Matters:
None
Summar
of Violations:
None
'
en Items
Summar
1 new item opened,
7 items closed,
and
2 items remain open.
DETAILS
Persons
Contacted
Pacific
Gas
and Electric
Com
an
!
- G. M. Rueger,
Senior Vice President
and General
Manager,
Nuclear
Power
Generation
Business
Unit
J.
D. Townsend,
Vice President
and Plant Manager,
Diablo Canyon
Operations
- W. H. Fujimoto, Vice President,
Nuclear Technical
Services
- D. B. Miklush, Manager,
Operations
Services
- M. J. Angus,
Manager,
Technical
Services
- B. W. Giffin, Manager,
Maintenance
Services
- W. G. Crockett,
Manager,
Support Services
J.
E. Molden, Instrumentation
and Controls Director
- W. D. Barkhuff, Quality Control Director
R. P.
Powers,
Mechanical
Maintenance Director
- D. A. Taggart, Quality Performance
and Assessment
Director
- T. L. Grebel,
Regulatory Compliance Supervisor
H. J. Phillips, Electrical Maintenance
Director
- R. C. Anderson,
Manager,
Nuclear Engineering
and Construction
Services
- M. R. Tresler,
Project Engineer,
Nuclear Engineering
and Construction
Services
J. A. Shoulders,
Onsite Project Engineering
Group Manager
S. R. Fridley, Operations
Director
R.
Gray, Radiation Protection Director
- J. J. Griffin, Senior Engineer,
Regulatory Compliance
J.
V. Boots,
Chemistry Director
- 0. B. Hoch, Manager,
Nuclear Safety
and Regulatory Affairs
- T. A. Moulia, Assistant to Vice President
Diablo Canyon Operations
- C. A. Dougherty, Quality Assurance
Senior Supervisor
- J. E. Tompkins, Nuclear Safety
and Regulatory Affairs Director
- R. C. Russell,
Nuclear Safety
and Regulatory Affairs
- B. A. Dettman, Director Nuclear Operations
and Support,
and Assistant to
Senior Vice President
Nuclear
Re ulator
Commission
- S. A. Richards,
Chief, Reactor Projects
Branch,
Region
V
- Denotes those attending the exit interview.
The inspectors
interviewed several
other licensee
employees
including
shift supervisors,
shift foremen
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
and quality
assurance
personnel.
2.
0 erational
Status of Diablo Can
on Units
1
and
2
During the inspection period, Unit 1 operated
at
lOOX power, except
between
March
6 and 10,
1992
when
a plant trip occurred
due to the loss of
a main feedwater
pump.
This event is discussed
in paragraph
4.a belo'w.
Unit 2 operated essentially
at 100K power,
except for February
16-17
,
and March 14-15,
1992.
On February 16-17, Unit 2 reduced
power to
approximately
50K for condenser
cleaning.
On March 14-15, Unit 2 reduced
power to 55K to install
a wiring change to the power supply eir cd'ts to
speed
sensors
of both main feedwater
pumps.
On February
16,
1992, at 10:30 p.m.
when Unit 2 reduced
power to 50K,,
a
quadrant
power tilt ratio alarm was received.
The power tilt ratio
increased
to 1.048 at about 1:30 a.m.
on February
17
and then steadily
decreased.
The licensee,
in consultation with Westinghouse,
determined
that the power tilt was
a result of slightly different efficiencies of
the secondary
loops, resulting in uneven
power distribution in the core.
This causes
about
a 0.5X power tilt during normal
100% power operation,
which is within the requirements
of Technical Specifications.
The
decrease
in power resulted
in an uneven
which exaggerated
the power tilt.
The licensee
decreased
power below 505
as required
by Technical Specifications
and the power tilt decreased
during power ascension
and stayed within Technical Specification limits.
On March 14,
1992, Unit 2 again reduced
power
and
a similar power tilt
occurred
and
exceeded
the Technical Specifications limit of 1.02 at 11:30
p.m.
The tilt decreased
to less
than 1.02 at 1:05 p.m.
on March 15.
During this time, the licensee
reduced
the high flux trip points to 94K
as required
by Technical Specifications.
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
to evaluate
trends.
This operational
information was then evaluated
to determine if regulatory requirements
were satisfied.
Shift
turnovers
were observed
on
a sample basis to verify that all
pertinent information on plant status
was relayed to the oncoming
crew.
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)
Conduct of selected
activities for compliance with the
licensee's
administrative controls
and approved
procedures
(d)
Interiors of electrical
and control panels
(e)
Plant housekeeping
and cleanliness
(f)
Engineered
safety feature
equipment
alignment
and conditions
(g)
Storage of pressurized
gas bottles
0
b.
The inspectors
talked with operators
in the control
room and other
plant personnel.
The discussions
centered
on pertinent '-TVpfcs of
general
plant conditions,
procedures,
security, training,
and other
aspects
of the work activities.
Radiolo ical Protection
c ~
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 aware of
significant plant activities, particularly those related to
radiological conditions
and/or challenges.
ALARA considerations
were
found 'to be
an integral part of each
RWP (Radiation
Work Permit).
Ph sical Securit
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 protective
and vital area integrity.
Exterior lighting was checked
during backshift inspections.
No violations or deviations
were identified.
4.
Onsite Event Followu
93702
a ~
Unit
1 Loss of Main Feedwater
Pum
and Reactor Tri
On March 6,
1992 at approximately 10:30
am, with Unit 1 operating at
lOOX power,
main feedwater
pump l-l tripped
on overspeed
due to the
failure of the power supply to the speed
sensors
of the
pump.
At
the time of the event,
licensee
personnel
were working on
a lube oil
cooler for the
pump which was adjacent to the
speed
sensor
power
supply cabinet.
On the loss of the power supply to the speed
sensors
of feedwater
pump 1-1
and the failure of the transfer to the
power supply of the other feedwater
pump, the sensed
speed of pump
l-l went to zero
and the
pump control
system
attempted
to increase
pump speed.
This led to feedwater
pump 1-1 reaching
the overspeed
trip setpoint of approximately
6400 rpm.
The other feedwater
pump
decreased
its speed
due to the increased
speed of feedwater
pump
l-l.
Control
room operators initially reduced turbine load in
response
to an expected
main feedwater
pump loss.
During the load
reduction,
pump 1-1 tripped.
On the loss of feedwater
pump 1-1, control
room operators initiated
a rapid reduction of turbine load
and had lowered load to
approximately
50K, with the '40% steam
dump valves (to cdmhhser)
modulating
open
as designed.
However, this
was not enough to
prevent
a reactor trip on low-low steam generator
water level
approximately
one
and one-half minutes after the trip of feedwater
pump 1-1.
Contributing to the difficulty in recovering
steam
generator
water level
was the fact that the operating feedwater
pump
(1-2)
had reduced its speed
due to the increased
speed
and flow from
'he
overspeeding
pump 1-1.
Plant response
to the reactor trip was for the most part
uncomplicated
and there
was
no initiation of safety injection.
The
issues
requiring resolution were:
(1) the identification of the
cause of the
speed
sensor
power supply failure to feedwater
pump
1-1; (2) determination of the cause of three
10K steam
dump valves
(to atmosphere)
opening after the reactor trip; and (3)
determination of the cause of the start of diesel
generator
1-1
approximately
32 seconds
after the reactor trip.
These
issues
are
discussed
below.
1)
The cause of the power supply failure of the
speed
sensors
to
pump l-l was identified to be the opening of
a
fusible link in an inverter.
The cause of the link opening
was
not determined,
but was possibly due to vibration when
a
portion of platform grating adjacent to the power supply
cabinet
was dropped into position, or due to overheating
due to
the high ambient temperature.
The opening of the fusible link
caused
excessive
current to be drawn
and the input fuses
were
blown resulting in the failure of the power supply.
A single
power supply provides
power to both speed
sensors
of a
pump.
A transfer
scheme
from the other feedwater
pump power supply was intended to provide redundancy.
The failure to transfer to the power supply of feedwater
pump
1-2 was found by the licensee
to be due to
a small plastic
shaving discovered
between relay contacts.
This shaving
appeared
to be from the terminal insulation
on the relay and
appears
to have fallen into the contact
area during
installation of the wiring.
A new inverter was installed for feedwater
pump 1-1
and relays
and fusible links were inspected
in feedwater
pumps
1-1
and
1-2.
The primary corrective action to prevent another
loss of
power supply, possibly resulting in a similar event,
was
a
wiring change to provide independent
power supplies for the two
speed
sensors
on each feedwater
pump.
This change
provided for
one
speed
sensor
on each
pump to be powered from an inverter,
with a transfer
scheme to the other feedwater
pump power supply
if necessary
(same
as in the past configuration).
In addition,
the other
speed
sensor
on each
pump would be powered
by other
AC sources.
This change
in power supply configuration
was
installed
on the Unit
pumps prior to the restart of
Unit 1
and
was also completed
on the Unit 2 feedwater
pumps
during
a power reduction
on March 14-15,
1992.
The opening of three of the four lOX steam
dump valves
was
found to be due to the sensitivity of the steam
dump valve
control
system.
Volume boosters
had
been
added to the
pneumatic portion of the control
system during the last outage,
but the boosters
had not been tested to assure
that adverse
effects were not present
during transient conditions.
During the March 6,
1992 event,
the steam
dump control system
switched from the load reject
mode of control (during the
manual
load reduction) to the steam pressure
mode of control,
(after the reactor trip).
In the load reject
mode of control
the
no-demand
pressure
in the actuator lines is 0.5 psig
and in
the steam pressure
control
mode the no-demand
pressure
in the
actuator lines is 3.0 psig.
In the switch from load reject to
steam pressure
mode of control,
a pressure
perturbation
was
started
(on the change
from 0.5 to 3.0 psig) in the actuator
lines which was amplified by the recently
added
volume
boosters.
Because
the
steam
dump valves will begin to open at
approximately 3.5 psig, this caused
the slight opening of the
10K steam
dump valves during the event.
This was demonstrated
in subsequent
testing of the steam
dump valve control system.
The opening of three
10K steam
dump valves rather than four was
because
one valve
(PCV-22, the one which had not opened
during
the event)
was found to be set at
a lower no-demand
pressure
(1.0 psi g) rather than at the intended 3.0 psig.
If necessary,
control
room operators
could have
opened or
closed
the
10K steam
dump valves using manual
switches
in the
control room.
By March 19,
1992,
adjustments
had
been
made to
all of the
steam
dump valves in Units
1 and
2 to tune out the
pressure
perturbation.
The start of diesel
generator l-l was
due to the relatively
light loading of its associated
bus
(Bus
H) and the fact that
its voltage drops slower than the other two safety-related
4160
V buses.
This causes
the other
buses
to load first onto
the startup
bus which momentarily brings
down the voltage of
the startup
bus.
The drop
and recovery of startup
bus voltage
was sufficiently long to initiate the start of diesel
generator
1-1 without loading it onto Bus
H.
Bus
H successfully
transferred
from the auxiliary transformer to the startup
bus
in this event.
This condition had
been
seen
before at Diablo
Canyon
and
was evaluated
in
NCR DC2-88-EM-N095.
The licensee
concluded
in this
NCR that
an unnecessary
diesel
generator
start
was considered
an acceptable
occurrence
when considering
the ineffectiveness
and cost of
a possible
design
change.
Because
a design
change
could possibly prevent
a necessary
diesel
generator start,
licensee
management
considers
the start
of a diesel
generator
when it may not be needed
to be less of
a
concern
than the failure of a diesel
generator to start
when
required.
Other activities accomplished
during the unit outage
included
inspectio~
and repair of the backdraft
associated
with the
Unit 1 containment fan cooler units
(CFCUs).
The
CFCU work included post-maintenance
testing after completion of
all work to assure
there
was
no reverse rotation of the fans
when
shut down.
The licensee
also identified
a cracked
packing gland
on
a manual drain valve (513)
on the pressurizer
spray line.
The manual drain valve had wedges installed
as
a temporary measure
to retain pressure
on the packing by transmitting force through the
packing follower ring.
The valve is also normally closed with
system pressure
under the valve disc.
The plant resumed
operation
on March 9, 1992, after repairs
and work
activities were completed,
and
lOOX power was reached
on March 10,
1992.
The reactor trip event is described
in
NCR DC1-92-EM-N010,
and
a Licensee
Event Report will be submitted to the
NRC.
Inspector Findings-
1.
The inspector
observed
the response
to this event several
minutes after the indication of feedwater
pump problems.
Control
room operators
responded
appropriately
and utilized
proper procedures.
Control
room instructions
and guidance
were
clear
and concise.
Sufficient management
and licensed
personnel
were present
to provide assistance
during the event.
2.
The inspector
observed
several
management
meetings
which were
conducted following the event.
These
meetings
were to evaluate
the cause
of the feedwater
pump trip and reactor trip and
determine corrective actions.
Meetings
were also conducted
to
determine
the scope
and priority of work to be accomplished
during this unexpected
outage.
These meetings
were successful
in making licensee
management
aware of the root cause
determinations,
obtaining, agreement
on necessary
corrective
actions,
and in coordinating
and prioritizing work activities.
3.
The inspector
reviewed the past history of feedwater
pump
-inverter failures.
This review indicated that there
have
been
several
inverter failures in the past which appear to be
indicative of
a long standing
problem.
The inspector will
continue to review the inverter history during the next
inspection period.
b.
Diesel
Generator
1-3 Test with Cardox
S stem Initiation
On March ll, 1992, during routine surveillance
testing of diesel
generator
1-3, the carbon dioxide fire suppression
(Cardox)
system
actuated
shortly after the diesel
generator
started.
Because
the
actuation of the carbon dioxide system
causes
roll-down doors to
shut
and thus deprive the generator
of cooling, operators
immediately shut
down the diesel,
opened
the roll-down doors,
and
started
troubleshooting
the failure.
The licensee
also tested
the
other diesel
generators
in both units within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to confirm
operability as required
by Technical Specifications.
The licensee
0
was unable to confirm the cause of the failure and has sent
a
circuit card from the carbon dioxide system to the vendor for root
cause
analysis.
The licensee's
determination of the ca~67 this
failure and whether it is considered
a valid failure of the diesel
generator will be reviewed in
a subsequent
inspection
(Followup Item
50-275/92-05-01).
No violations or deviations
were identified.
5.
Maintenance
62703)
The inspectors
observed
portions of, and reviewed records
on, selected
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.
These activities included:
Work Order R0091799,
Unit 2
RHR Pump 2-2 Motor Oil Sampling
Work Order C0096975,
Unit
1
CFCU 1-2 Backdraft
Oamper Repair
Work Order C0096844,
Unit 2 Inspection
and Repair of FCV-372
(AFW
Work Order C0096503,
Unit
1 Investigation
and Repair of
DG 1-2
Engine Temperature
Indicator
Work Order C0097368,
Unit 2 Inspection
and Cleaning of Main
Condenser
On February
25,
1992, the inspector
observed oil sampling of the
Unit 2 residual
heat
removal
(RHR)
pump motor 2-2.
The associated
work order
(WO R0091799)
specified that the sampling
be performed in
accordance
with maintenance
procedure
MP M-56.7, Steps 7.l.a through
7.1.g.
Included in these
steps
was
a note that the "oil samples
should
be taken while the equipment is operating or shortly after
the equipment is shutdown."
The person taking the oil sample
was
unsure of how the note
was to be interpreted
because
there were
no
specific steps
in the work order calling for the operation of the
RHR pump.
The
RHR pump had not been recently run prior to drawing
the oil samples.
The inspector
discussed
the intent of the work order
and maintenance
procedure with an electrical
maintenance
manager
and the sponsor of
the procedure.
The conclusion
was that the intent was to obtain
an
oil sample after
a pump run, but it was recognized that the
procedure,and
work order were inconsistent
and that appropriate
scheduling
guidance
had not been
communicated
to properly coordinate
the
pump run
and drawing of the oil samples.
Licensee
management
stated that the procedure
would be clarified, particularly Appendix
8.2,
and that scheduling
guidance
would be provided to properly
coordinate
the oil sampling.
In addition,
guidance
would be
provided to maintenance
personnel
to assure
that work orders
and
procedures
are understood prior to continuing work activities.
'o
violations or deviations
were identified.
6.
Surveillance
61726)
a ~
Observations
By direct observation
and record review of selected
surveillance
testing,
the inspectors
checked
compliance with TS requirements
and
plant procedures.
The inspectors verified that test equipment
was
calibrated,
and that test results
met acceptance
criteria or were
appropriately dispositioned.
These tests
included:
M-9A
Unit 1 Monthly DG Test
(DG 1-2)
M-8A2 Unit 1 Emergency Air Lock Leak Test
V-3R5 Unit
1 Stroke Test of FCV-95
(AFW Steam Admission
Valve)
N-16C Unit 2 Train
A Slave Relay Test
M-8A1 Unit
1 Personnel
Air Lock Leak Test
b.
During the testing of the steam
admission
valve (FCV-95) to the Unit
1 turbine-driven auxiliary feedwater
pump
on March 10,
1992,
licensee
personnel
identified that on the closure of valve FCV-95
there
was
a larger than expected
amount of stem bending.
Stem
bending in the past
had
been
viewed
as
one indicator that
a higher
force would be required to open the valve the next time.
Licensee
engineering
personnel
concluded that
FCV-95 should
be restroked
and
monitored with the expectation that the bending stress
would be
reduced.
The valve opened successfully
(11.89
amps for pullout);
however,
on closing,
licensee
personnel
noted
even higher bending
stresses
than previously seen
and also
a deeper
seating position
than previously.
This valve position
was also considered
undesirable
in that both conditions indicated
a higher force would
be required to open the valve.
The valve was cycled
open again, with 15.65
amps
measured
to open
the valve.
On closure of the valve, while an even deeper
seat
position
was noted,
only slight stem bending occurred.
This was
considered
acceptable
by licensee
engineering
personnel.
The next
test of FCV-95 occurred
on March 17,
1992
and resulted
in successful
opening of the valve
and approximately
15.5
amps
on pullout.
The licensee's
engineering
organization
(NECS)
has
been evaluating
the data obtained during the testing of FCV-95.
In
a memorandum
dated
March 5, 1992,
NECS has
proposed that the weekly testing of
FCV-95 in Unit
1 be extended to every two weeks for March
and April
0
and then to monthly beginning in Nay 1992,
due to the identification
of a reliable indicator of the potential for high pullout force
(stem position),
and to a lesser
degree
the reliability'Ut'tem
bending
as
an indicator.
These indicators
have
been correlated,
with stem position being more consistent.
An additional
reason for
reducing the testing frequency is the gearing
changeout
done after
the
December
24,
1991, failure of FCV-95 to open.
This change
has
increased
the opening capability of the operator
such that there is
added
assurance
that the valve will open
when intended.
NECS has
recommended
that thermography
and certain diagnostic
equipment
no
longer
be required during valve testing
as the information gathered
by these
instruments
is no longer of use.
Further,
NECS indicates that the valve has
begun to show
evidence of wear during the weekly testing.
There
has
been
a
gradual
increase
in the pullout current to open the valve and
a
decrease
in the seating thrust in closing the valve.
This is
attributed to greater
stem friction as the valve is cycled
and is
postulated
by NECS to be due to the gradual
reduction of lubrication
on the stem threads.
No
7.
En
The March 5,
1992
memorandum
also
recommends
that
FCV-95 in Unit 2
be instrumented
to monitor only stem position rather than the full
set of instrumentation
now provided
on the Unit
1 valve.
Based
on
a review of the licensee's
data correlating
stem position
and pullout current,
the gearing
changeout
made,
and the fact that
Unit 2 opening current data
are relatively consistent
(6.2 - 12.5
amps),
the licensee's
proposal
appears
appropriate.
violations or deviations
were identified.
ineered
Safet
Feature Verification
71710)
During the inspection period, selected
portions of the auxiliary
system for Units
1 and
2 were inspected
to verify that system
configuration,
equipment condition, valve
and electrical
lineups,
and
local breaker positions
were in accordance
with plant drawings
and
Technical Specifications.
violations or deviations
were identified.
8.
0 en Item Followu
92703
ao
Unresolved
Item 50-275/91-01-01:
Licensee
A
endix
R Audit
Open)
In December
1990,
the Nuclear Operations
Support
(NOS) group
performed
an audit of safe
shutdown
systems
and procedures.
This
audit was described
in
a memorandum to the plant manager
dated
January
29, 1991.
Followup by the
NRC inspector is described
below.
Licensee corrective actions to date
and planned corrective actions
are included with each
issue.
10
After completion of design
basis
documentation
in the areas
of
electrical circuitry and safe
shutdown methodology,
which are
estimated
to be completed
around
June
1992,
the license~Tans
to
start the second
phase of the Appendix
R validation budgeted
under
BLI No. 453.
This will include validation of the safe
shutdown time
line; emergency lighting locations,
including availability of
emergency lighting during outages
(formerly NRC Open Item 91-03-03,
closed
in this report);
equipment repair procedures;
and
use of
auxiliary equipment.
As
a result of the
1990
NOS audit, the licensee identified improper
implementation of configuration control in the following areas:
o
Emergency
Procedures
- Procedures
are currently being reviewed
for agreement
with design basis
documentation.
o
Combustible
Loading - The licensee is evaluating the need for
control over small (less
than
one percent)
changes
in the
combustible loading.
o
Safe
Shutdown Circuit Analysis - The licensee
is completing
validation of the original safe
shutdown circuit analysis.
Several
issues
regarding circuit separation
have
been
identified, including the inadequate
separation
in the Unit 2
reactor trip switchgear
room
( Inspection
Report 50-275/92-01,
paragraph 5.b.),
inadequate
protection of cables
in the
Unit 2 diesel
generator
room corridor,
and inadequate
separation
of circuits in containment,
which the licensee
plans.
to report in a future LER.
Additional specific concerns
being followed by the
NRC are listed
below:
o
Remote
Shutdown
Panel - The licensee
stated that surveillance
testing of hot shutdown
panel
mechanical
components
would be in
place
by December
31,
1991.
Most of this testing is in place;
however, testing for some valves
has not been
implemented..
The
licensee
stated that testing would be implemented
by July 15,
1992.
For the testing which has
been
implemented,
no failures
have
been
noted to date.
o
Operator Training - The licensee
documented
that the training
for procedure
M-10, "Fire Protection of Safe
Shutdown
Equipment,"
has occurred
and
has
now been included in biennial
review for operator requalification training.
Therefore, this
specific concern is closed.
o
Heat Trace - Heat tracing circuity for the Appendix
R emergency
boration flow path
was not reviewed to validate appropriate
circuit separation.
The circuity runs through various
areas
of
the auxiliary building,
and
may not be properly separated.
The
licensee
agreed to address
this issue.
The licensee
stated
that boration
can
be accomplished
using the
RWST for all fire
areas.
Therefore,
redundant capability is available.
11
o
Failure Trending of Emergency Lighting Units - Although the
licensee
now has the capability to trend failures of individual
lighting units, there
has
been
no assigned
responsibi I'ity for
this function.
o
Equipment Operability Evaluations - Revision
6 of Justification
for Continued Operation
(JCO) 90-17 addressed
inoperability of
the positive displacement
charging
pump, which would be used
for a safe
shutdown during
a fire in the centrifugal charging
pump room.
The
JCO did not specifically identify the safe
shutdown
method nor its associated
circuit analysis to be used
as
compensatory
measures.
The licensee
agreed that the
JCO
could have
been written more clearly.
The licensee
plans to
rewrite the
JCO by mid-April 1992
and will discuss
the issues
at that time.
Since the licensee
stated that fire protection
compensatory
measures
are in place in the centrifugal charging
pump room, including suppression,
detection,
and hourly fire
watches,
the safety significance of this issue is low.
o
Root Cause - The preliminary 1991 audit conclusion for these
discrepancies
involved
a disconnect
between
NECS
and the actual
plant configuration
and procedures.
The licensee
stated
during
this report period that that root cause still appeared
to be
valid.
b.
Followu
Item 50-275/92-01-01:
Removal of Conduit Bracket Durin
Unit
Refuelin
Outa
e
C ose
This issue
involved the discovery
by the
NRC inspector of a pair of
conduit brackets
which had
been
removed during the Unit 1 refueling
outage
in 1991
and
had not been reinstalled.
The licensee initiated
QE Q0009474 to document the corrective actions taken.
These actions
included reinstallation of the brackets,
discussions
with the
personnel
involved in the incident,
and the initiation of a training
improvement plan specific to this event which will be included in
the quarterly maintenance
training.
Based
on these actions, this
item is closed.
c ~
Followu
Item 50-275/92-01-02:
Timin
of Inde endent Verification
Durin
Surveillance Testin
C osed
This issue
involved the inspector's
observation that personnel
did
not clearly understand
the appropriate
timing of the performance of
independent verification during surveillance testing.
The licensee
initiated
QE Q0009487 to document the issue
and the required
corrective actions.
These
actions
include the revision of selected
surveillance
procedures;
revision of procedure
NPAP C-104,
Independent
Verification of Operating Activities, to clarify the
intent of the independent verification during surveillance testing;
development of
a checklist to be used during interdepartmental
reviews of surveillance testing procedures;
and revision of the
Operations
Policy documents
to place guidance
regarding
independent
verification in the proper location.
Based
on these actions, this
. item is closed.
0
12
Unresolved
Item 50-275/91-24-01:
Floodin
of Com onent Coolin
Water
Heat
Exchan er
Room
C ose
On August 2, 1991, during preparations for a routine cleaning of the
CCW heat exchanger,
maintenance
workers failed to properly follow
the work order clearance
instructions.
This resulted in flooding of
the Unit
1
CCW heat exchanger
room.
The work order required
that the auxiliary saltwater
system inlet valve to the heat
exchanger
be gagged before'he
heat exchanger
manway was opened.
Instead,
with the inlet valve shut but not gagged,
workers
opened
the manway,
entered
and exited the heat exchanger,
and then
attempted to gag the valve shut.
The workers thought the work order
steps
were in the wrong sequence.
The manway
was left open.
During
the attempt to gag the valve, the valve opened,
flooding the heat
exchanger
area.
This could have
caused
a significant personnel
safety hazard
had
an individual been in the heat exchanger
when the
inlet valve opened.
The licensee
determined that there
was only minor significance to
plant safety,
since the redundant
safety train was available.
The licensee
determined that the root cause
of the problem was
personal
error, in that the instructions in the work order were not
followed in sequence.
Corrective actions
taken include issuance
of
two maintenance
bulletins; mandatory discussion
with all foremen
and
appropriate
journeymen
on the importance of reviewing clearances
to
ensure isolation of energy sources
from the work area,
and
on the
importance of constructive
and timely feedback to Work Planning
when
a work order is not correct;
and counseling of the specific
individuals involved.
The licensee
has also identified other
prudent,
peripheral
actions.
Based
on the corrective actions, this item is closed.
Followu
Item 50-275/91-09-03:
Normal Li htin
and Public Address
S stem
Power
Su
Closed
During the March 7, 1991, loss of offsite power event,
the Unit 1
normal lighting and
PA systems
became
In addition,
emergency lighting in containment
was unavailable
due to
maintenance.
The
NRC Augmented Inspection
Team (AIT) identified
a
need for the licensee to investigate
the adequacy of lighting and
communications.
The licensee
had earlier identified (in December
1989) that emergency
lighting for safe
shutdown
may not be adequate
in all areas
of the
plant.
Additional walkdowns were performed after the March
7 event.
Investigation
and corrective action is being implemented
under
a
budget line item for fire protection safe
shutdown,
discussed
in
this report.
As interim compensatory
measures,
portable lighting
has
been provided to operators.
Further followup of the lighting
issue will be followed under Followup Item 50-275/91-01-01.
13
The AIT concern for the failure of the
PA system
was reviewed,
including the containment
evacuation
alarm function.
The licensee
determined that the
PA system,
by design, is not safety-Ptlated,
and
that placing the
PA system
on vital power or on
an uninterruptable
power supply was not
a warranted
expenditure
in comparison with
other projects providing more safety benefit.
Based
on the
above
discussion
and inclusion of the lighting issue in Followup Item
50-275/91-01-01,
this item is closed.
Unresolved
Item 50-275/91-27-01:
Containment Air Lock Leak Tester-
Unct
C ose
The issues
remaining
open regarding this followup item were:
(1)
whether the non-quality classification of the automatic
leak tester
was appropriate
even though it is used to satisfy Technical
Specifications
requirements,
and (2) whether
a revision to the current
training program
was needed.
The non-quality classification of the tester
appears
appropriate
in
that the licensee's g-list document specifies that testing devices
are not classified,
but are covered in the
gA program to maintain
accuracy within necessary
limits.
This is consistent
with 10 CFR Part 50, Appendix B, Criterion XII, Control of Measuring
and Test
Equipment.
A revision to the training program regarding the air lock had
been
issued just prior to the event.
It had
been considered
that the
recently revised training was sufficient to cover the event.
Based
on further questions
by the inspector,
the licensee
issued Training
Improvement
Proposal
k'2300 to emphasize
the
need to perform
a
manual test if the automatic tester fails.
This training will be
included in upcoming licensed
and non-licensed
operator training
and
also will be included in the next revision of the training lesson
guides.
Based
on this, this unresolved
item is closed.
Unresolved
Item 50-275/91-20-02:
Missed Surveillance Test
Closed
This issue
was described
in Licensee
Event Report 50-275/91-012-00
and
was reviewed
and closed in Inspection
Report 50- 275/91-40.
Therefore, this unresolved
item is closed.
Followu
Item 50-275/92-17-02:
Site Strate
for Personnel
rrors
0 en
This issue
involved the inspector's
observation that between
August
and October
1991 there
appeared
to be
a high number of noteworthy
personnel
error events.
The licensee initiated
a human error
reduction plan which includes letters
and meetings to express
management's
expectations for human performance,
review training
regarding
independent verification and provide recommendations,
develop
a training video, provide
a policy on pre-job briefings,
and
develop
a tracking mechanism for human errors contained
in HCRs .and
gEs for review with department directors.
This plan is described
in
Diablo Canyon Objective 3000.01/017.1.
0
14
Most items are currently on schedule,
with the only item behind
schedule
being the development
of an independent verification
training video tape.
This tape is scheduled
to be comPB;ed
by the
end of March 1992.
9.
Exit
One March 18,
1992,
several
personnel
errors occurred in Unit 2 which
resulted
in the isolation of the number
1 seal leakoff line of
pump 2-4 for approximately
63 minutes.
This event
was initiated during troubleshooting of the leakoff line flow
transmitter.
While the licensee
is reviewing this event,
preliminary information indicates
the following errors occurred:
Inadequate tai lboard discussion for the involved parties to
understand
the scope of the work being performed.
Assumption of shared responsibilities for the troubleshooting
activities;
however, there
was
no communication of who was
responsible for what aspects
of the job.
Communications
with control
room personnel
during the work did
not develop
an understanding
of the actions actually being
performed.
An alarm for high number
2 seal leakoff received
in the control
room should
have alerted control
room operators
of the
incorrect valve alignment.
It appears
that
pump performance
parameters
(seal leakoff
temperatures,
seal differential pressure,
and
pump vibration
measurements)
returned to normal after the event
and Westinghouse
is
being consulted to determine
whether
any significant
pump
degradation
occurred.
These
personnel
errors
are significant in that
a number of barriers
failed to detect the incorrect valve alignment.
Based
on errors
evident during this event
and pending the licensee's
evaluation of
the root causes
and whether additional corrective actions
are
appropriate,
this followup item will remain open.
On March 19,
1992,
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.
g