ML16341E604
| ML16341E604 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 03/16/1988 |
| From: | Johnston K, Mendonca M, Narbut P, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E603 | List: |
| References | |
| 50-275-88-03, 50-275-88-3, 50-323-88-04, 50-323-88-4, NUDOCS 8804130022 | |
| Download: ML16341E604 (42) | |
See also: IR 05000275/1988004
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
50-275/88-03
and 50-323/88-04
Docket Nos:
50-275
and 50-323
License
Nos:
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:
January
31 through March 5,
1988
Approved by:
L.
M. Padovan,
Resident Inspector
K.
E. Johnston,
Resident
Inspecto
~~+~
e c
P.
P. Narbut, Senior Resident
Inspecto
M.
M. Mendonca,
Chief
Reactor Projects
Section
1
Date Signed
~/~ugs
~
Date Signed
Date Signed
Date Signed
~Summaa
Ins ection from Januar
31 throu
h March 5
1988
Re ort Nos.
50-275/88-03
and
50-323/88"04
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,
35701,
37700,
61726,
62703,
71707,
71709,
71710,
71881,
90712,
92700,
92701,
92702,
93702,
and 94703 were applied during this inspection.
Results of Ins ection:
Two violations and
no deviations
were identified.
8804130022
880328
ADOCK 05000275
Q
DETAILS
Persons
Contacted
- J. D. Townsend,
Plant Manager
J. A. Sexton, Assistant Plant Manager,
Plant Superintendent
- J. M. Gisclon, Acting Assistant Plant Manager, .Support Services
- W. B. McLane, Acting Assistant Plant Manager, Technical
Services
- C. L. Eldridge, guality Control Manager
- M. E. Leppke, Onsite Project Engineer
- K. C. Doss, On-site Safety Review Group
- T. A. Bennett, Acting Maintenance
Manager
D. A. Taggert, Director guality Support
- M. J. Angus,
Work Planning
Manager
- W. G. Crockett, Instrumentation
and Control Maintenance
Manager
J.
V. Boots, Chemistry
and Radiation Protection
Manager
- L. F.
Womack, Operations
Manager
- T. L. Grebel, Regulatory Compliance Supervisor
S.
R. Fridley, Senior Operations
Supervisor
- G. M. Burgess,
Senior
Power Production Engineer
The inspectors
interviewed other licensee
employees
including shift
foreman
(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 March 11, 1988.
0 erational
Status of Diablo Can
on Units I and .2
Unit 1 began
the reporting period at full power and coasted
down during
the period to 64K power due to fuel burnup.
The Unit planned to begin
its second refueling outage
on March 4, 1988, but this was delayed
due to
the Unit 2 reactor trip on March 3, 1988.
Unit 2 operated
at
100% power during the reporting period except for
planned reductions
in power for testing,
an
OP delta
T turbine runback
and
a reactor trip on March 3, 1988, described later in the events
portion of this report.
The Acting Plant Manager for Diablo Canyon,
Mr. J.
D. Townsend,
was
formally selected
as the Plant Manager in February.
He had
been acting
in the capacity since July 1987.
The Region
V Director of Reactor Safety
and Projects,
Mr. D. F. Kirsch,
examined
the site for several
days during the report period
and held
discussions
with plant management.
Key points discussed
were the
need to
ensure plant design
bases
were clearly understood,
transmitted to the
site personnel,
and properly implemented
in the processes
of maintenance
and modifications.
He indicated the
need for management
to clearly
establish
goals,
determine
how to implement
them and
commence
a timely
implementation.
A second
key point discussed
was the need for plant
management
to become
more aware of plant conditions through first hand
observations
and entries into radiologically controlled areas.
The Region
V Reactor
Projects
Branch Chief, Mr. R.
P.
Zimmerman, also
examined the site
on
a different week of the reporting period
and
had
discussions
with plant management.
Key points discussed
were the
apparent
large
number of relatively old (late 1986, early 1987),
uncorrected
action requests
for maintenance
and the lack of approved
response
procedures
at the auxiliary operations
control
station.
0 erational
Safet
Verification
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's facility.
'Fhe 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)
Essential
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.
Ko violations or deviations
were identified.
~
~
~
4.
Onsite Event Follow-u
a 0
Centrifu al
Char in
.Pum
1-2
On February 23, 1988, during clearance activities associated
with
corrective maintenance
(shaft seal
replacement)
on
CCP 1-2, the
150
pound class suction piping to the
pump was subjected
to excessive
pressure.
During the
pump clearance
process,
in accordance
with clearance
number 10969,
an auxiliary operator
(AO) attempted to close charging
pump outlet valve CVCS-1-8389B.
The valve was difficult to close,
which the auxiliary operator characterized
as
normal for charging
pump discharge
valves with tight packing, but the
AO believed the
valve was shut.
He then'closed
other specified isolation valves
and
began closing
pump suction valve CVCS-1-8394B
as specified in
the clearance.
As the suction valve neared
the closed position,
water began spraying from I) the packing gland of the suction valve,
2)
a compression fitting on suction line pressure
indicator (PI)
192B,
and 3) the diaphragm of the PI isolation valve I-8484B.
The
pump casing drain valves to the miscellaneous
equipment drain
were
opened to further relieve the pressure
and abate
the spray.
An
auxiliary control operator, after alerting control
room personnel
to
the situation, returned to the
pump discharge
valve and
was able to
close the valve an additional half turn and stop the spray.
Several
hundred gallons of demineralized
CVCS water were routed to the
auxiliary building sump through floor drains before the leaking
piping was isolated.
The licensee's
investigation revealed that high pressure
(about
2400
psi) demineralized
RCS water from the discharge of operating
CCP 1-1
had passed
through the incompletely closed
CCP 1-2 discharge
valve,
and back flowed through
a leaking discharge
check valve (I-8478B)
which pressurized
the
pump suction piping once the suction valve was
closed.
The licensee
developed
an Action Plan to further investigate
the
incident and determine
necessary
corrective actions.
The plan
included procedure
revisions to ensure
the charging
pump suction
pressure
is observed
in future isolations of the charging
pump for
maintenance,
inspection
and repair of the check valve, replacement
of the charging
pump seals,
r epair of the diaphragm valve and other
leaking components,
and performance of engineering
evaluations of
overpressure
effects
on the
pump suction piping and
pump casing.
The engineering
evaluation
determined that the overpressure
condition was acceptable
for continued operation.
The licensee
estimated
the overpressure
achieved
was not greater
than
500 psi
(the design
pressure
is 210 psi).
The acceptance
was
based
on
discussions
with component
vendors, liquid penetrant
examination of
the highest stressed
welds, visual examination for distortion,
calculations
showing stress
levels
remained
below code allowable
limits, and in-service leak test
and
pump operability tests.
Additionally flange bolt torques
were checked for any relaxation
(none found relaxed).
After the completion of corrective actions
and testing the
pump was
declared
and returned to service.
The inspector considered
the following items related to the event
as
open:
o
Manuall
0 crated Casualt
Valves
The licensee's
action plan did not address
the charging
pump
discharge
valve.
The valve was difficult to operate
and was
not initially fully shut.
Subsequent
discussion
indicated that
the licensee
considered
that with check valve leakage,
the high
differential pressure
across
the discharge
valve (a manual
gate
valve)
made closure very difficult and this was satisfactory.
The valve was subsequently
cl'osed with force.
The inspector
asked
the licensee
to consider
the lessons
learned
from other
operating plants.
Specifically, that manual isolation valves
which are counted
on to be functional in casualty or emergency
procedures
ought to be capable of manual operation.
Inspector discussions
with operations
personnel
indicated that
simple design
changes
such
as packing changes
or a racheting
handwheel
might ease
operation of such high head high D/P
valves.
The licensee
committed to examine
manual
valves
used in
casualty situations
to ensure
they are operable
(follow-up item
50-275/88-03-01).
o
Meanin ful Acce tance Criteria for 0 erations
Personnel
The inspectors
spent
some time exploring the operability of
charging
pump 1-2.
This was addressed
carefully because
the
pump had
been
noted to have shaft leakage
on swing shift
February 22, 1988, at
a time when the diesel
generator
servicing the other charging
pump (1-1) was out of service.
The shift foreman
had decided
the
pump 1-2 was operable
but not
desirable
to be operated
because
the leakage,
about
200 ml/min,
would contribute to airborne activity.
Subsequent
discussions
showed that decision to be correct but
not an immediate
and obvious conclusion.
Charging
pump 1-2 was
capable of automatic start
and delivering emergency
flow to the
reactor coolant system if called upon.
Its operability in
a
post
LOCA environment during recirculation from the containment
was questionable
but,
based
on revised estimates
of
acceptable
leakage rates,
was subsequently
determined to be
acceptable.
The guidance available to the shift foreman in making the
proper decision
was lacking,
however.
The guidance available
was found in test procedure
STP P-2B,
"Routine Surveillance Test of Centrifugal
Charging
Pumps,"
which has
as acceptance
criteria:
"Seal
leakage
normal"
(Yes/No), "Ifthis had not been satisfied,
declare
pump
The inspectors
considered this criteria to be insufficient
qualitative or quantitative
acceptance
criteria.
The
contained
a limit of 10 cc/hr as
an assumed
seal
leakage for
post
LOCA habitability studies.
At the exit interview licensee
management
stated that
consideration
would be given to defining more reasonable
acceptance
criteria for this and other tests at least to the
point of invoking administrative limits which would trigger
future operability analysis.
The licensee's
actions will be followed up in the course of
future normal inspection functions.
For tracking purposes this
item is opened
and closed in this report (Follow-up item
50-275/88-03-02 - closed).
It should
be noted that this item is similar to the lack of
acceptance
criteria violation associated
with the containment
fan cooler unit drains,
item 50-323/87-38-01.
No violation is
considered
warranted in this case
since qualitative criteria
were provided.
b.
Nuclear
Instrument Inverter IY-13 Failure
On February 9, 1988, operators
discovered
the output of the Unit 1
120 Vac nuclear instrument inverter had degraded
to 60 Vac
Subsequent
investigations
found no breakers
tripped and the smell of
something burning.
The licensee
swapped
loads
and de-energized
the
inverter.
The licensee
subsequently
determined
the inverter transformer
had
failed and this type of failure had been described
in a 1984
(the transformer manufacturer)
Technical Bulletin.
This event will be described
in Licensee
Event Report
(LER)
50-275/88-06.
The inspector will review this event, its root cause
and proposed corrective actions,
during the course of routine
LER
review.
The Westinghouse Bulletin had provided two options to determine
adequacy.
Either high potential testing or six months of
satisfactory
performance.
Since the licensee's
inverters
had been
in operation greater
than six months,
they were believed to be
acceptable.
is currently pursuing
reportability implications of the event.
Unit 2
OP Delta
T Actuation and Turbine Runback
On January
31,
1988, at 4:06 a.m.
PST with Unit 2 at
100 percent
power, the licensee
declared
an unusual
event
as
a result of an
OP'elta
T reactor protection actuation which caused
a turbine runback
to 87 percent
power.
A reactor trip properly did not occur,
as the
OP de'Ita
T reactor trip setpoint
was not reached.
The
OP delta
T control actuation
(C-4) was caused
by inadvertent
steam
loads
induced in the moisture separator
reheaters
(MSRs)
on
the secondary
side of the plant.
A senior reactor operator
(SCO),
performing troubleshooting activities
on
a
MSR shell water level
control valve, shorted
the
120 vdc power supply'o the valve
solenoid which opened
a
120 vdc power supply breaker.
Twelve high
level spill valves from the
MSR high pressure
drain tanks
and
low pressure
drain tanks
opened
on the loss of power, causing part
of the main steam
and reheat
steam to be bypassed
to the condenser.
The turbine Control system
responded
to the reduced turbine first
stage
pressure
and increased
steam
demand
by opening the turbine
governor valves further.
Tavg decreased
and
as rod control
was in
manual,
the resultant
RCS cooldown resulted
in reactor
power
increasing
to 103.6 percent.
Operators
began to manually reduce
turbine load,
and
120 vdc power was reestablis'hed
to the high level
spill valves closing the valves
(power was reestablished
within
three minutes of the breaker opening).
Steam flow immediately
decreased,
causing
RCS Tavg to increase
to the
OP delta
T rod
stop/turbine
runback setpoint.
Reactor
power was
above
100 percent
for about
two minutes.
The cause of the event
was the
12
opening
as
a result of the
SCO's troubleshooting activities.
The
SCO had
a voltmeter in the ammeter
mode when
he touched the leads
across
the solenoid valve relay.
This caused
a short of the
120 vdc
to ground.
He had been troubleshooting
the
MSR 2-1B shell level
control
and
had successfully
done
a few voltage
and fuse continuity
checks prior to the event.
The
SCO was not specifically authorized to do the troubleshooting
activities,
and
had
no written instructions.
Additionally, an
Instrumentations
and Controls
(ISC) shift technician
was available
for this purpose.
The problem
had
been previously defined,
and
an Action Request
(AR)
existed
on the
MSR level control valve but had not been acted
on for
several
weeks.
However, the
AR had not been given
a component
code
(Identification
( ID) and Functional
Equipment
Group
(FEG) numbers)
when
it was entered
into the computer
and therefore
was not readily
identifiable and would have required
a search of all Unit 2 main
steam
system
ARs.
Additionally, no caution tags, info tags,
or AR
stickers
were in place to indicate the problem had
been identified.
Following the event,
the licensee
established
an Action Plan.
The
emphasis
of the Action Plan was to properly address
not only the
root cause
but also all other problems identified during the event.
Corrective actions included involvement of the
SCO who personally
took part in addressing
Action Plan items.
The operations
department
established
a written policy on operations
troubleshooting activities, in which the following was stated:
"l.
Operators
shall rely on installed plant instrumentation
and
components
to accomplish troubleshooting activities.
2.
Operators'se
of test equipment for troubleshooting
on
energized/in
service plant equipment shall
be limited to using
hand-held temperature
probes or similar devices.
Use of
volt/ohm meters is limited to checking fuses which have
been
removed from the circuit.
3.
All troubleshooting activities shall
be preplanned,
the
preplanning
session
should include an Action Request
search
on
the component
ID and
FEG for the component in question.
4.
The results of any troubleshooting shall
be documented
on the
AR for the problem in sufficient detail
so that the steps
need
not be repeated."
A number of Action Plan items were established
to evaluate
the
tagging system,
the
AR priority system,
and backshift support for
corrective maintenance activities, specifically in the I8C area.
At
the time of this report these evaluations
had not been
completed but
will be followed by the inspector during routine inspection.
Also,
a number of Action Plan items were initiated to perform long
term evaluations
of the secondary plant systems
involved in the
event,
such
as main turbine
and
MSR control.
Finally, a number of corrective actions
were taken to reevaluate
the
reportability of the event.
The licensee's
Emergency
Plan stated
that an
Op delta
T "actuation" is an Unusual Event.. However,
upon
reevaluation
the licensee
is considering
the turbine runback
initiation as
a control function and not a protective actuation
as
a
reactor trip would be.
The licensee
had not concluded this
evaluation at the time of this report.
'This will be followed up
during routine inspection.
In summary,
the corrective actions
taken appear to be appropriate.
However, this appears
to be another
example of'n event resulting
from plant personnel
going outside or without written procedures.
Other
examples
include the CVI actuation described
in section 4.d.,
the
RHR pipe heating event (inspection report 50-323/87-39),
and
events during the Unit 2 first refueling outage including the
inadvertent diesel
generator start,
the loss of RHR event,
and the
8'avity
drain
down event.
It appears
that the licensee
should focus
greater attention
on this issue.
Unit 1 Containment Ventilation Isolation
Due to the Inadvertent
Groundin
of a Vital Inverter
On February
17, 1988, the licensee
made
a four hour non-emergency
report as
a result of an
ESF actuation,
a Containment Ventilation
Isolation (CVI) on Unit 1.
The CVI occurred
as
a result of the
momentary grounding of'20 Vac Vital Inverter
PY llA.
The ground
occurred
as
a result of a ground wire not being removed during the
the accomplishment of a design
change
on three
chemical
and volume
control
system flow transmitters.
When the associated
120 Vac
breaker
was closed,
to return the transmitters
to service for
testing,
the inverter was momentarily grounded.
This resulted in an
condition which caused
a number of bistables
to trip,
including a CVI.
Prior to the event,
Design
Change Notice (DCN) DCI-SE-39078
was
issued to install fuses for the sensing
head
and the transmitter,
for flow transmitter
(FT) 113 and flow meter
(FM) 113 (emergency
boration flow), FT ill/FM 111 (primary water to the boric acid
blender),
and
FT 110/FM 110 (boric acid blender inlet).
FM 113
provides Technical Specification
emergency boration flow monitoring
which has
a seven
day action statement.,
FM 110 and
FM 111 are part
of the reactor
makeup control system.
During a meeting between
General
Construction
(GCg electrical
and the clearance
coordinator
it was decided that two hours would be sufficient time to perform
the work and that the work should
be performed expeditiously
so that
the reactor
makeup control
system indication would not be out of
service for more time than necessary
to complete the job.
On February 17,
1988, at 8:40 a.m.,
the
GC field engineer
and the
work planning coordinator discussed
the job with the shift foreman.
The
GC field engineer
had not been
aware of the earlier discussions
with the clearance
coordinator which established
that two hours
would be sufficient time to complete the work.
This agreement
was
established
as guidance
on the clearance
request.
During the 8:40
a.m.
meeting,
the shift foreman requested
that the
GC field engineer
have the craft work through lunch, if necessary,
to complete the
job.
During the performance of the
DCN, the lugs
on the power supply
wires from the fuse for FM/FT 113 to FT 113 were judged to require
replacement
and the electrician cut them off and relugged
them.
However, in this condition the replaced wires could not be landed
on
the side of the terminal block specified in the
DCN.
In addition,
after relugging the wires, the circuit could not be restored to its
original configuration.
The step in the work order which required the rewiring also included
a
gC inspection point to verify correct installation.
The
GC field
engineer
discussed
the situation with the
gC inspector
and properly
informed him that to complete the job, the wire would have to be
spliced, requiring splice requests,
jumper requests,
and work order
revisions.
The gC inspector properly informed the
GC field engineer
that
he could not perform his inspection until the
DCN was complete
and left the area.
The
GC field engineer
concluded that by relocating
a terminal
board
by approximately
one inch, the circuit could be terminated
on the
side opposite that identified by the
DCN which he judged would be
different than the
OCN but functionally equivalent.
At ll:30 a.m.,
the field engineer called the shift foreman to inform him that it
would take several
hours to complete the job per the
DCN.
The shift
foreman
responded that he wanted the system
back to provide
indication.
The field engineer
proceeded
to have the terminal block
moved.
At about ll:50 a.m., the field engineer verified as left condition.
He failed to notice
a previously existing ground wire from a
terminal block to
FM 110.
The rewiring had landed
a power lead to
the
same terminal
as this ground.
The
DCN drawing had
shown
no
ground lead to that terminal;
however,
since the ground lead
had not
been noticed, it was not removed,
as it should
have been,
in
-accordance
with the
OCN.
The
GC field engineer
described
the configuration using the
OCN
diagram of connections
to the shift foreman
and shift supervisor.
All parties
agreed that the system would perform as designed in the
described configuration.
The
GC clearance for implementing the
DCN
was reported "off" followed by a report "off for test" to test the
instruments
to verify that they functioned
as left.
These actions
were not made to declare the system indication formally operable
but
to make available primary water and boric acid flow indication.
At 12:23 p.m., operations
energized
the breaker to the flow
transmitters
which, because
of the wiring error, momentarily
grounded the inverter before tripping on overload.
The resultant
undervoltage initiated a containment ventilation isolation.
The root cause of this event can
be attributed to the
GC field
engineer initiating steps to return the system to service prior to
completion of the design
change.
as specified in the
DCN.
Two
contributory causes
were (1) the two hour schedule
which added
unnecessary
pressure
to the field engineer
and (2) that the shift
foreman concurred with the field engineer that the "functional" .
condition was acceptable.
In a Technical
Review Group
(TRG) meeting held on February
26,
1988,
to discuss
the Nonconformance
Report generated
by this event,
similar conclusions
were reached.
The
TRG sighted specific
procedures
governing work order and design
change
implementation.
Specifically, the
GC field engineer
should
have not proceeded
past
the step to rewire the internal wiring, bypassing
a gC inspection
point.
He should
have
had his work order revised to accomplish
those tasks
necessary
to complete the design
change
as prescribed.
10
The licensee
took three corrective actions:
(1)
Verification of satisfactory procedural
guidelines to restrict
activities such
as those of this event.
(2)
Counseling of responsible
individuals (i.e. the
GC field
engineer
and the shift foreman).
(3)
Issuance
of a memorandum stating that systems
are not to be
returned to service in other than the original design
configuration
on the final design configuration unless
a
partial
DCN closure
has
been
documented
and approved
by the
appropriate
supervision.
The memorandum also stated that
a
system is not to be returned to service
unless all modification
quality checks. that are required
have
been completed.
The
memo
was issued to all organizations
affected
by the policy.
\\
The activities discussed
in this section involved apparent
or
potential violations of NRC requirements
identified by the licensee
for which aggressive
and self-critical licensee
actions
were taken.
Consistent with Section IV.A of the
enforcement action was not initiated by Region
V.
e.
Unit 2 Shift of Fuel Handlin
Buildin Ventilation to Iodine Removal
Mode
On .February 25, 1988, with Unit 2 at 100K power, the Fuel Handling
Building Ventilation System shifted to Iodine Removal
Mode due to a
high alarm
on new fuel area radiation monitor RM-59.
Initial
investigations
indicated that the high alarm was
due to a noise
spike
on RM-59 resulting from resistance
testing
on spent fuel area
radiation monitor RM-58.
Radiation Protection personnel
were in the
area at the time performing
a radiation survey and reported
no
change
in local radiation levels indicating that the alarm was
spurious.
The event
was reportable
under
and the licensee's
determination of root cause
and corrective actions will be evaluated
in a review of the
LER.
f.
Unit 2 Reactor Tri
Due to Seismic Tri
In ut
On March 3, 1988, at 1:44 p.m.
PDT while at 100K power, the reactor
tripped due to a seismic trip signal.
There
was
no seismic
ev'ent
however.
The seismic trip is initiated by a
2 out of 3 coincidence
in any 2
out of 3 directional detectors,
i.e. x-x or y-y or z-z.
technicians
were performing seismic trip surveillance testing
on one
channel.
They were
unaware of a failed "x" contact,
not annunciated
by design,
on another
channel.
When they placed the planned "x"
contact in test,
coincidence
was achieved
and the reactor trip
signal
was generated.
0
All safety system
responded
properly.
Two steam
dump valves
had
anomalies
which the licensee
investigated
and corrected.
Operators
response
to the trip was observed
and was satisfactory.
Licensee
management
conducted
an
accurately
captured all relevant
an action plan.
The action plan
the actions required for restart
extensive post trip review,
and
problems identified in the event in
accurately
and clearly, specified
and long term actions.
'k
Licensee
upper plant management
was in attendance
at the post trip
review and corporate
management
delivered
a message
to those in
attendance
which indicated that thorough actions took priority over
a return to service.
The 1'icensee
return-to-service
actions
included repair of a failed
coil in the seismic trip system,
steam
dump system repair and
grooming,
and other repairs
which the unplanned
outage
made
possible.
The licensee
longer range actions
included
a determination of the
need for a design
change to annunciate failed seismic trip channels
and
a review of other control
systems for similar "blind spots."
The licensee's
action plan methodology provided
a clear listing of
problem or investigative areas,
assigned
clear responsibility for
resolution,
required signoff for completion by those responsible
parties
and required documentation of corrective action.
This methodology appeared
to provide
a structured
approach to
actions
and afforded
an opportunity for on-shift management
review,
and upper
management
overview.
The inspector
noted that
new problems
(such
as water intrusion into
steam
dump electrical conduits) which were identified on Friday
night and Saturday
morning were not treated in the
same formal
precise action plan manner.
This situation
was identified to the
plant manager
and was immediately corrected.
Control
Room Ventilation Isolation
Actuations
on March 4 and
5
1988
Unit 2
On March 4 and 5, 1988, three separate
CVI actuations
occurred which
were
10 CFR 50.72 reportable
events
since they represent
Essential
Safety Feature
(ESF) actuations.
o
The first CVI occurred
on March 4, 1988, at 3:20 p.m.
PDT.
I8C
technicians
were troubleshooting
steam
dump problems which had
occurred during the reactor trip.
When they removed the cover
from an associated
pressure
switch, water drained
from the
switch (which should
have
been
a dry electrical
box).
The
water (or debris
on the water) caused
the switch to burn out
and trip the power supply breaker to it.
The short caused
a
'12
voltage transient
on the affected
120 Vac instrument
bus which
caused
an actuation of'VI and
a Fuel Handling Building
Ventilation System transfer to the Iodine removal
mode.
o
The second
CVI occurred at 9:06 p.m.
on March 4, 1988,
when an
operator performing a clearance
to allow work on the shorted
switch, closed rather than verified open the output breaker
from vital inverter IY-21A.
This action reenergized
the
shor ted switch,
caused
a voltage perturbation which caused
radiation monitor signals to actuate
the
CVI as well as
Fuel
Handling Building Ventilation System transfer to Iodine Removal
Mode and Control
Room Ventilation System transfer.
o
The third CVI occurred at 12:23 p.m.
on March 5, 1988,
due to a
voltage transient
on a 120 Vac instrument
bus (23A).
Train
B
of the
CVI occurred but Train A did not.
Licensee
investigation
showed that the cause of the voltage transient
was troubleshooting/repair
of an excore monitoring channel
(a
wide range
channel installed for
RG 1.97 reading at the Post
Accident Monitoring panel).
When lifting a lead
an arc was
drawn despite
the fact that the technicians
believed they had
depowered
the cabinet.
The arc and resultant voltage perturbation
were of sufficient
duration to cause
a CVI signal but only Train
B actuated.
Two
errors are indicated initially:
Depowering the cabinet using the power breaker in the
upper cabinet should
have
depowered
the wiring being
worked, but did not.
Licensee investigation indicates
that although
power wiring was properly installed per
vendor drawings,
the vendor drawing is in error and
requires
a design
change
DCN to correct it.
The licensee's
field.wiring diagram of connections
also
had
an error which, when wires were lifted to remove
a
faulty power supply,
caused
a defeat of protection set
A
inputs.
This was the reason
the Train A CVI did not
actuate.
The
same
problem was subsequently
found in Unit 1 and was
traced to an improperly performed design
change in 1984 on
both units.
The licensee is preparing
LERs and
NCRs on the above
CVIs.
Licensee
corrective action will be followed through these vehicles.
No violations or deviations
were identified.
5.
Maintenance
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.
13
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.
Dia hra
m Re lacement
on Unit I Valve 8484B
On February 23,
1988,
due to events
described
in Section 4.a of this
report, Unit 1. Charging
Pump 1-2 suction pressure
gauge isolation
valve 8484B developed
leakage
past the diaphragm.
On February 24,
work was initiated to replace
the diaphragm.
The inspector entered
the chargin'g
pump room following the completion of the work and
found
a Quality Control
(QC) inspector signing off QC inspection
points in the work order package.
The resident
inspector
reviewed
the work order and the
QC inspection plan.
One inspection point
required the
QC inspector to verify the torque application
and
another required
him to "visually examine
the valve internals for
cleanliness
prior to close-up of the system."
The valve, which was
located directly above the pump,
was in a surface contamination
area
(SCA) which extended
approximately six feet from the valve.
The resident inspector determined
from the
QC inspector that
he had
not gone into the
SCA to perform the inspection.
To verify the
torque application
he had 'the maintenance
mechanics
show him the
final reading
on the torque wrench which the resident
inspector
found to be acceptable
although not
a good practice.
To satisfy the
other inspection po'ints,. the
QC inspector
had examined the valve
and bonnet prior to installation but did not look at the
valve internals.
The
QC inspector
had verified with the maintenance
mechanic that the valve body was "clean".
The
QC inspector stated
that the job had required
him to wear
a respirator for which he was
not qualified.
He was sent to perform the inspection with the
information that it would not require
a respirator.
The resident
inspector
asked if the
QC inspector
thought the
inspection required
someone
to physically look into the valve body
and that perhaps
he should
have notified his management.
The
inspector
agreed that in hind sight that would have
been prudent.
Subsequent
to the interview, the
QC inspector
informed his
supervisor
and following a reassessment
by radiation protection
was
allowed to perform the inspection without a respirator.
The resident
inspector
discussed
this incident with the
inspector's
supervisor
and the
QC manager
who both stated that the
inspection point required the
QC inspector
to physically look into
the valve body,
as well as
examine
the valve bonnet
and diaphragm
for cleanliness.
The
QC department
has
reviewed this problem with
all
QC inspectors,
and the licensee
has established
an
NCR to assure
thorough resolution of the problem.
Further, disciplinary action
was taken against
the specific
QC inspector.
Finally, the
NRC
inspector determined that the component in question
was not of.a
high safety significance,
because
of the limited size of the opening
and the function of the valve (gauge isolation).
The
QC inspector's failure to perform his inspection
as described
in
his instructions is an apparent violation (Enforcement
Item
50-275/88-03-03).
14
b.
Unit 1 Turbine Driven Auxiliar
Pum l-l Gasket
Re lacement
The inspector. observed
the replacement of a gasket
on the Unit 1
turbine driven Auxiliary Feedwater
(AFW) pump l-l.
An oil leak had
developed
through the gasket
on the bottom of the turbine governor
gear box.
A corrective maintenance activity was generated
to
replace
the gasket.
The inspector
observed that the mechanical
maintenance
jou'rneyman
was qualified and followed his instruction.
During the removal of
the oil, the journeyman
had noted that the oil removed did not match
the oil prescribed
in his instruction.
He brought this to the
attention of a maintenance
engineer.
The engineer
reviewed
Administrative Procedure
(AP) D-753 "Control of Plant Lubricants,"
and determined that it did not specify oil for the turbine driven
AFW pump governor gearbox.
The work planner
had mistakenly
specified the oil listed in AP D-753 for the governor which is
separated
from its gearbox
by a seal.
The engineer
reviewed the
vendor technical
manual
which specified oil for the gearbox
and
made
a change to the work package.
The engineer will follow this
up by
revising
AP 0-753 to specify gearbox oil.
The inspector also observed
the torquing of the drain plate bolts
and observed
the torque wrench calibration check following the
maintenance activities.
C.
Other Maintenance Activities
Maintenance activities associated
with event follow-up were also
examined for this reporting period.
These
included centrifugal
charging
pump seal
replacement,
corrective maintenance
associated
with overpressurizing
the suction piping of the charging
pump, flow
transmitter modifications associated
with the Unit 1 CVI on February
19, 1988,
and corrective maintenance
associated
with the Seismic
Reactor trip of March 3, 1988.
One violation and
no deviations
were identified.
6.
Surveillance
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.
a.
Auxiliar
Pum
Surveillance Test
The inspector
observed
the performance of Surveillance Test
Procedure
(STP)
P-3B, "Routine Surveillance
Test of Motor-Driven
Pumps" for Unit 2 Auxiliary Feedwater
(AFW) Pump
'-2.
This test fulfills the
ASME Section
XI requirements
to
periodically test the
AFW pumps.
The inspector
reviewed the
0
procedure
against the
ASME Section
XI criteria and found it
acceptable.
The inspector
found that the auxiliary operator performing the test
was familiar with the test
and the system.
The inspector
reviewed
the test results against the associated
action limits and found them
acceptable.
b.
Other Surveillance Activit
Additional surveillance activities were examined in conjunction with
operational
events
described
in paragraph
4.
These
included
centrifugal
charging
pump surveillance testing
and criteria,
and
testing of seismic trips pursuant to the March
3 Unit 2 reactor
trip.
No violations or deviations
were identified.
7.
Radiolo ical Protection
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
RWP (Radiation Work Permit).
a.
Unauthorized Entr
to the Radiolo ical Controls Area
On February
19, 1988, the inspector
observed
an employee of the
licensee
cross
a roped
and posted
boundary into the Radiological
Controls Area
(RCA) without authorization.
The boundary
was
a temporary. barrier at the south
end of the outside
115'tank farm" area.
The temporary barrier was set
up to aid
construction efforts and to ease
access
for vehicles in preparation
of the Unit 1 refueling outage.
The boundary
was delineated.
by
yellow-magenta
rope,
supported
by stanchions,
and marked by postings
reading "Caution, Radiological
Controls Area,
Personnel
Monitoring
Devices
Required
Beyond this Point" and "Radioactive Materials
Area."
This posting was in accordance
with Radiation Control
Procedure
(RCP) D-240, "Posting of Radiologically Controlled Areas."
The inspector
observed
the individual who had current General
Employee Training for access
to the
RCA, read the postings
and then
cross
the barrier.
The inspector notified a Senior
Chemistry and
Radiation Protection
(C8RP) Engineer
who notified
RCA access
control.
The radiation protection control personnel
identified and
escorted
the individual to the normal
access
control at the
85'evel
of the Auxiliary Building.
The individual was wearing
a TLD
the entire time, did not enter any surface
contamination
areas,
and
did not receive
any measurable
exposure.
The inspector
discussed this event with the individual.
The
individual had been touring the perimeter of the plant when
he
came
to the posted barrier.
He interpreted
the posted
requirement for
personnel
monitor ing devices to be fulfilled by his TLD.
He was
also
under
the mistaken
impression that this portion of the
RCA had
recently been returned to general
access.
However, the individual
should have recalled
from General
Employee Training that entry into
the
RCA required the use of a Radiation Work Permit
(RWP),
a Special
Work Permit
(SWP), or other written authorization.
The inspector
observed that for the most part the
RCA boundary
was
posted
as required.
However, the barrier sagged to two feet off the
ground and was not as
imposing as it could have been.
In addition,
a side entry in a fence to the
same area
was posted only with a
"Caution, Radioactive Materials."
Finally, observing
from inside
the
RCA, their were
no postings to state that the barrier was
an
exit of the
RCA.
These findings were discussed
with the
CHIRP
manager
and the senior
CHIRP engineer.
Following these discussions,
the postings at the
RCA barrier were added to read,
"No Entry at
this point."
On the other side the barrier read ."No Exit."
In
addition the barrier was supported
by an extra stanchion.
The individual crossed
the barrier in violation of Radiation Control
Standard
4, "Control of Access" which in section 3.3, "Entry Into
the Controlled Area," states
in paragraph
3.3. 1:
"Except as
exempted
by the Diablo Canyon Technical Specifications written
authorization (usually an
SWP or RWP) is required for all entries
into the controlled area
"and in paragraph 3.3.3." Entry into the
Controlled Area shall
be made only through the normal established
access
control points.
Entry by way of other points
may be
made
only in cases
of emergency
or by authorization of radiation
protection supervision."
This is a potential violation (Enforcement
Item 50-323/88-04-01).
One violation and
no deviations
were identified.
8.
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 protected
and vital area integrity.
Exterior lighting was
checked during backshift inspections.
No violations or deviations
were identified.
17
9.
Licensee
Event
Re ort Follow-u
a 0
Status of LERs
Based
on an in-office review, the following LERs were closed out by
the resident inspector:
Unit 1:
86-16
Unit 2:
86-27, 87-03, 87-05,
87-25
The
LERs were reviewed for event description,
root cause,
corrective
actions taken,
generic applicability and timeliness of reporting.
b.
Red Tele
hone vs
LER Trackin
The licensee
has evaluated
the following 10 CFR 50.72 events for
reportability under 50.73
and has determined that 50.73 report is
not required.
The resident
inspectors
have
examined the licensee's
rationale
and determined that regulatory requirements
have
been met.
50.72 Report
Date/Unit
Event
Reference
etc.
January 31/Unit 2
OP delta
T runback
NCR DC1"88"OP N010
No violations or deviations
were identified.
10 ~
0 en Item Follow-u
a.
Late
Re ortin
of an
En ineered Safet
Feature
Actuation
0 en
Item 50-323/87-20-03
and 50-323/87-26-03
Closed
In inspection reports
50-323/87-20
and 50-323/87-26,
Notices of
Violation were issued against Unit 2 for the late reporting of ESF
actuations.
The second
Notice of Violation was issued prior to the
complete
implementation of corrective actions
taken in response
to
the first Notice of Violation.
The inspector
reviewed the corrective actions
described
in the
licensee's
responses
of July 22, 1987,
and October 2, 1987, which
appear to be acceptable.
The corrective
actions
were also discussed
in subsequent
management
meetings.
The inspector will continue to
monitor the licensee's
performance
in the area
and reopen this issue
if conditions warrant.
Accordingly, these
open items are closed.
b.
Control of the Installation
and
Removal of Tem orar
Gau
es
0 en
Items 50-323/87-43-02
and 87-43-03
Closed
In a letter dated February
19,
1988, the licensee
responded
to two
notices of violation and
a request for information.
The first
notice of violati'on involved the control of the installation of
18
temporary
(50-323/87-43-02).
The second notice of violation
concerned
the failure to remove
an installed
gauge in accordance
with procedure.
The information request
concerned
the control of
the installation of a temporary nitrogen manifold to the steam
generator
blowdown line on Unit 2.
The inspector
has reviewed the above letter
and finds the corrective
actions
described
to be acceptable.
Specifically, that test
procedures will .provide additional
assurance
that test equipment
installation and removal
and,
when this is not the case,
that the
test equipment will be controlled using Administrative Procedure
C-4Sl, "Jumpers."
The letter also committed to discuss
these
practices with Operations
and Instrumentation
and Controls
personnel.
In addition, consideration will be given for a design
change to install permanent test equipment
when a high use frequency
warrants it.
The inspector will review the proposed
procedural
revisions
and other commitments during the course of routine
inspection.
These
items are closed.
Line Noise Follow-u
Inspection
Report 50-323/87-45
discussed
main steam line noise
and
the licensee's
efforts to identify its source.
The inspector
questioned
the apparent tardiness
to establish
a comprehensive
program to identify the source of the noise.
A review of the history of the main steam line noise
showed that
following its identification in 1987, attention
was focused
by
different groups,
including plant maintenance
and engineering.
The
reviews included discussions
with the main steam isolation valve
vendor representative
and Unit 2 valve inspection.
The action
request
issued
as
a result of the 1987 investigation identified
three sources
of noise:
(1)
MSIV disc fluttering on the valve stop tubes.
.(2)
Condensation
from an unknown source,
possibly from the main
steam relief valve header,
flashing through the MSIV.
(3)
Noise from in-line calorimeters
abandoned
in place
downstream
of the MSIVs.
The most recent investigation into the noise established
the
same
causes.
In addition, the licensee
concluded that these conditions
did not jeopardize
the integrity of the valves or the system.
The
investigation
however was more detailed
and involved the
coordination of various engineering
and plant groups.
As a result
the information generated
was available to all groups.
A study of
the difficulties in obtaining the whole story from the first
investigation,
including what specifically was looked at and what
was found,
appears
to be
a good argument for the Action Plan/Task
Force method
used in the second investigation
and being implemented
by the licensee
in a number of recent events.
19
d.
Challen
es to the Onsite Fire Bri ade
0 en Item 50-275/87-27-01,
ose
In response
to the NRC's regional fire specialist
inspection report
findings, the licensee
described
the actions
taken to improve the
Onsite Fire Brigade.
These actions
were identified to the regional
specialist
who determined that this item could be closed.
The
actions
included
a procedure revision to limit brigade
response
to
the site boundary,
a replacement fire truck and
a description of
manning options available in the event of a major county fire.
This
item is considered
closed.
e.
Res
onse to
A Audit Findin
s
0 en Item 87-38-05,
Closed
As
a follow-up to previous concerns,
the
RV Enforcement Officer met
seperately
with four individuals employed in the licensee's
quality
control group to discuss their freedom to carryout their assigned
responsibilities.
Without exception, all of the individuals
indicated they had the necessary
freedom to identify problems
and
assure
that adequate
corrective action is initiated.
All of the
individuals said that they had the necessary
management
support to
assure
that their activities are appropriately
performed without
undue interference
from others.
This item is closed.
ll.
Inde endent
Ins ection
During this reporting period it was identified that operators
at the
auxiliary control station were using annunciator
response
procedures
which were not formally controlled procedures
and were in fact authorized
to make
pen
and in changes
to those
procedures
without further approvals.
Discussion with the Operations
manager
indicated that the licensee
had
undertaken
a program to improve annunciator
response
procedures
approximately three years
ago.
At that time control
room annunciator
response
procedures
were approved
by the Operations
Manager, it was then
decided to upgrade
those to
PSRC approval,
and this was done.
At that
time the auxiliary control station did not have annunciator
response
procedures
and
a decision
was
made to have the auxiliary operations staff
develop the procedures
through use,
and to formalize them at
some point
in time.
The operation
manager
committed to formalize the auxiliary
control
board annunciator
response
procedures.
The schedule for this is
to be determined.
This item will be followed-up in future inspection
(Item
50-275/88-03-04).
12.
~Ei
N
On March 11,
1988,
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.
Additional topics were discussed
including:
20
o
A rising level of concern
regarding
the tardiness
of implementing
corrective. actions notably in the
I&C area.
These
concerns
were
focused
by a stop work issued against
I&C by
PG&E gA for failure to
update
Measuring
& Test Equipment
(M&TE) procedures
identified 1987.
Likewise, upgrades
of I&C loop tests first identified as
a concern
in 1987
have not been
accomplish
and only a writers guide for loop
tests
has
been
scheduled for completion in July 1988.
Likewise,
a
steam
dump grooming procedure for restart after
a trip identified as
needed
during the Unit 2 return to power in July 1987
was not yet
available after the March 3, 1988, Unit 2 reactor trip.
o
The proposed
commission rule regarding plant employee warning
systems
on backshift regarding
NRC or site management visits.
The
need to ensure that such
systems
do not develop
was discussed.
C
1(