ML16343A357
| ML16343A357 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 02/21/1996 |
| From: | Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D221 | List: |
| References | |
| 50-275-95-18, 50-323-95-18, NUDOCS 9602270118 | |
| Download: ML16343A357 (42) | |
See also: IR 05000275/1995018
Text
ENCLOSURE
2
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection
Report;
50-275/95-18
50-323/95-18
Licenses:
DPR-82
Licensee:
Pacific
Gas
and Electric Company
77 Beale Street,
Room
1451
P.O.
Box 770000
San Francisco,
Facility Name:
Diablo Canyon Nuclear
Power Plant,
Units
1 and
2
Inspection At:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
December
10,
1995,
through January
20,
1996
Inspectors:
M. Tschiltz, Senior Resident
Inspector
J. Dixon-Herrity, Acting Senior Resident
Inspector
S.
Boynton, Resident
Inspector
B. Olson, Project Inspector
G. Johnston,
Senior Project Inspector
'.
M
mon,
cto
I
pecto
Approved:
org,
e
, Reactor
roJec
s
rane
ate
Ins ection
Summar
Areas
Ins ected
<Units
1 and
2
Routine,
announced
inspec~ion of operational
safety verification, maintenance
observations,
surveillance
observations,
onsite engineering,
and plant support activities.
Results
Units
1 and
2
O~erationa:
On-shift operations
management
failed to document
the basis for an
in response
to
a fluctuating Unit 2 reactor
cavity sump level instrument.
A violation was identified (Section 2.4).
Review of the history of problems with 'the reactor cavity sump level
instrument revealed that operators
failed to implement the corrective
actions previously developed
in response
to the erratic reactor cavity
sump indication (Section 2.4).
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Operators
responded
appropriately
by questioning
the v."lidity of alarms
and involving supervisory
personnel
following
- partiai r'ailure of the
Unit
2 solid state protection
system
(SSPS)
(Section 2.3).
~
An inadequate shift turnover resulted
in operators
being
unaware of
concerns
that could affect centrifugal charging
pump operability.
This
unnecessarily
delayed
the implementation of compensatory
measures
(Section 2.5).
Maintenance:
During testing of battery
room temperature
sensors,
a technical
maintenance
worker was observed
standing
on
a safety-related
battery
rack to access
a sensor
on the ceiling, creating
the potential for
personnel
injury and
damage to the safety-related .battery, if the
individual were to slip or fall.
This was identified as
a poor work
practice
(Section 3. 1).
Engineering
and technical
maintenance
personnel
demonstrated
a lack of
attention to detail while installing test equipment for a special test
on
a safety injection pump;
as
a result,
the test equipment
was
incorrectly installed at the start of the te'st which required
reperformance
of the first portion of the test
(Section
4. 1).
1
Operations
and engineering
personnel
involved with a test run of Safety
Injection
Pump (SIP) 2-1 failed to perform required monitoring due to
poor communications.
As
a result,
a noncited violation was identified
(Section 4.3).
~
The licensee
has
been
slow in resolving repeated
failures of the Unit 2
reactor cavity sump level instrument
(Section 5.1).
~
'The labeling
and built-in schematic
provided at the nuclear
steam supply
system
(NSSS)
sample sink were identified as
a strength
(Section
6. 1).
Summar
of Ins ection Findin s:
~
Violation 323/9518-02
was
opened
(Section 2.4).
~
A noncited violation was identified (Section 4.3).
~
Inspection
Followup Item 275/9518-01;
323/9518-01
(Section 2.3.4).
Attachments:
~
Persons
Contacted
and Exit Meeting
~
List of Acronyms
0
'1
DETAILS
1
PLANT STATUS
(71707)
1.1
Unit
1
Unit
1 was in Mode
1 at
50 percent
power at the beginning of the inspection
period.
A reduced
power level
was required
due to the recurrence
of a control
oil problem with main feedwater
pump
(MFP) 1-2.
Unit
1 returned to
100 percent
power on December
11,
1995.
On December
13,
1995, Unit
1 was
ramped to 50 percent
power
and then manually tripped due to
a severe
Pacific
Ocean
storm.
Following cleanup of kelp from the condenser
and the plant
intake structure,
Unit
1 reentered
Hode
1 on December
18,
1995.
The unit
returned to 100 percent
power on December
20,
1995;
however, recurring
problems with MFP 1-2 control oil required operators
to again
ramp power to
50 percent.
Unit
1 returned to
100 percent
power on December
22,
1995,
and
remained
there through the
end of the inspection period.
1,2
Unit 2
Unit 2 was in Mode
1 at
100 percent
power at the beginning of the inspection
period.
On December
13,
1995, Unit 2 entered
Mode
2 as
a result of a severe
Pacific Ocean
storm causing
heavy kelp loading
on the circulating water
pump
travelling screens.
The licensee
shut
down the reactor
and placed the unit in
Mode
3 on December
14,
1995, to minimize auxiliary feedwater
requirements
from
the condensate
storage
tank.
Unit 2 reentered
Mode
1
on December
17,
1995,
and returned to 100 percent
on December
19,
1995,
where it remained
through
the
end of the inspection period.
2
OPERATIONAL SAFETY VERIFICATION
(71707)
The inspectors
performed this inspection to ensure that the licensee
operated
the facility safely
and in conformance with license,and
regulatory
requirements.
The methods
used to perform this inspection
included direct
observation of activities
and *equipment, observation of control
room
operations,
tours of the facility, interviews
and discussions
with licensee
personnel,
independent verification of safety
system status
and Technical
Specifications
(TS) limiting conditions for operation, verification of
corrective actions,
and review of facility records.
2. 1
Unit
1 Manual
Reactor Tri
and Unit 2 Shutdown
On December
13,
1995, plant operators
manually tripped Unit
1 from 50 percent
power after debris
loaded the circulating water
(CW) system traveling screens
located at the intake structure.
The debris,
consisting primarily of kelp,
loaded
the traveling screens
from high ocean
swells
due to
a major Pacific
Ocean
storm.
Approximately
7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> prior to the reactor trip, operators
had
reduced
power to 50 percent
as
a result of conditions experienced
at the
intake structure.
Operations
personnel
were stationed
at the intake structure
0
throughout the storm to monitor differential pressures
across
the traveling
screens
and to assess
the operating conditions of the intake structure
equipment.
At the time of the manual reactor trip, one of the two
CW pumps
was operating,
and the other
pump was shut
down to permit backflushing the condenser.
The
reactor
was tripped in accordance
with Operating
Procedure
AP-7,
"Degraded
Condenser,"
Revision
11A, to avoid excessive
damage
to the traveling screens
when screen differential pressures
increased significantly.
The reactor trip
was uncomplicated,
and the unit was stabilized in Mode 3 with reactor coolant
system temperature
being controlled
by the steam generator
10 percent
atmospheric
steam
dump valves.
Unit 2 was operating at
50 percent
power at the time of the Unit
1 trip and
was also afFected
by debris loading of the
CW system traveling screens.
Subsequently,
operators
reduced Unit 2 power,
separated
the main generator
from the grid,
and stabilized the unit in Mode 2.
Operators
had to manually
trip the main generator after it did not automatically trip 30 seconds after
the main turbine was tripped.
Later, after experiencing
high differential
pressures
across
the traveling screens,
operators
secured
the Unit 2
circulating water
pumps
and transferred
the reactor
heat load to the
steam
generator
10 percent
atmospheric
steam
dumps,
On December
14,
1995, Unit 2
was shut
down and stabilized
in Mode
3 to minimize the
amount of condensate
water being
steamed
to atmosphere.
The inspector
observed
the licensee's
recovery actions to restart
both units.
A significant portion of the licensee's
recovery efforts was devoted to
cleaning the systems
affected
by kelp.
The main condensers
were opened,
cleaned,
and inspected.
All circulating water system traveling screens
were
inspected,
and sections
where
damage
was noted were replaced,
The intake
refuse
sump,
which collects debris
from the traveling screens,
was found to be
full of kelp and required extensive
cleaning.
As
a result of the Unit 2 main generator
not automatically tripping, the
licensee
inspected
relays associated
with the main generator
antimotoring
devices.
The license
found that grease
had hardened
on one relay timer and
that another relay timer
had the wrong type of lubrication.
The licensee
corrected
the relay timer problems,
performed retests,
and inspected
the
corresponding
relays in Unit 1.
The licensee
also performed work on various
balance of plant components,
including
HFP and main turbine oil systems.
Unit
2 returned to Mode
1 operation
on December
17,
1995,
and Unit
1 returned to
Mode
1 operation
on December
18,
1995.
The inspector
observed
the startup of
both
units'he
inspector
found that the licensee
was thorough in efforts to inspect
components
affected
by kelp and to eliminate accumulated
kelp.
The inspector
also
found that the licensee
used
the shutdown period to perform inspections
and repairs to secondary
components
to ensure reliable future operation.
The
inspector
concluded that the licensee's
actions
were conservative
in not
planning to restart
the units until weather
and ocean conditions
improved.
2.2
Unit
1
Down ower Due to MFP 1-2 Control Oil Problems
On December
3,
10,
and 20,
1995, the licensee
lowered
power on Unit
1 in
response
to recurring control oil problems with MFP 1-2.
The control oil
pressure,
which is normally maintained
at approximately
140 psig,
dropped to
88 psig,
During troubleshooting
on the three different occasions,
the
licensee identified. four deficiencies
which contributed to the problem;
these
deficiencies
include:
a loose fitting at the Racine valve in the low pressure
steam stop valve,
a control oil leak near the actuator
seal
rings for the low
pressure
steam stop valve, the trip oil header to Lovejoy control oil
interface
check valve was not seating correctly,
and the 'low bearing oil
pressure trip piston
was not seating correctly.
The inspector
reviewed
guality Evaluation (0011802,
"Recurring Hain Feedwater
Pump Control Oil
Problems,"
and found that the licensee
determined that the last deficiency was
the major contributor to the low-trip header
pressure
problem that was
experienced.
These deficiencies
were corrected
by mechanical
maintenance.
In
addition to
a number of other corrective actions,
the licensee
plans to
establish
a preventive maintenance
program for the trip block, permanently
install gauges
at the trip header
and actuator
supply lines,
and revise
functional testing
on the control oil system to ensure
proper operation.
After the repairs
were complete, oil pressure
returned to approximately
140 psig.
The inspector
concluded that these
actions
were appropriate.
2.3
SSPS Annunciator Failure
2.3. 1
Operator
Response
On December
20,
1995, Unit 2 was in Mode
1 at
100 percent
power.
At
approximately 5:52 p.m., control
room operators
received multiple SSPS
bistable, alarms
accompanied
by
a "Reactor Trip Initiated" annunciator.
Contrary to these indications,
no automatic trip of the reactor
had occurred.
The alarms
were acknowledged
by the on-shift control
board operator
(CO)
and
observed
by the shift supervisor
(SS)
and
SSPS
system engineer
who were also
present
in the Unit 2 control
room.
The shift foreman
(SFH),
who was in the
back of the control
room,
was immediately paged
by the
CO.
The receipt of the
"Reactor Trip Initiated" annunciator is
an entry condition into annunciator
response
Procedure
AR PK04-12, Revision
1, Reactor Trip Initiated (Red),
and
Emergency Operating
Procedure
(EOP)
E-O, Revision 8, Reactor Trip or Safety
Injection.
Although both of these
procedures
directed operators
to manually
trip the reactor,
the
and
CO made the determination that the alarms
were
not valid and that
a reactor trip was not required;
therefore,
a manual reactor trip was not initiated.
The alarms cleared after approximately
18
seconds'he
inspector
responded
to the control
room and observed
the actions
taken
following the event.
The
SSPS
system engineer briefed the shift and the
inspector
on the event
and the troubleshooting
in process.
The inspector
noted that the engineer
was knowledgeable of the system
and
was approaching
the problem in
a logical manner.
The inspector
reviewed the computer
generated list of alarms that
had
come in and walked
down the control
boards
df
'I
cl
1
'
to verify that indications
were normal.
The inspector
noted the alarms that
came in could easily
be verified for accuracy,
both by control
board
indications
and
by the lack of alarm printouts
from the plant computer portion
of SSPS.
The inspector
interviewed the
SS,
CO,
SSPS
system engineer,
and operations
director.
The inspector also reviewed the applicable
procedures
and
CO logs.
Through licensee
personnel
interviews,
the inspector determined
the following:
both, the
CO and
SS recognized that Procedure
PK04-12 required
them to manually
trip the reactor
and enter Procedure
E-0; however, within a few seconds of
receiving the multiple alarms,
the
CO noted that the
SSPS
alarms
were
inconsistent with other control
room alarms
and indications,
Contrary to
a
valid SSPS required trip, no alarms
were generated
by the plant process
computer
(PPC).
The
CO noted that
no
"PPC Failure" or
"PPC Trouble" alarms
were received that would bring into question
the operability of the
PPC.
The
CO observed
the control board indications for reactor
power, pressurizer
pressure,
pressurizer
level,
and
water levels.
The
CO noted
that parameters
were within their normal operating
range with no visible
trends'he
CO and
SS noted that,
although the
SSPS bistable
alarms indicated
that all four main turbine stop valves
were closed,
the turbine was latched
and operating at full electrical
output.
After approximately
18 seconds,
the
SSPS
alarms cleared.
Based
upon these
indications
and in consultation with
the
SSPS
system engineer,
the
SS ~concluded that the
SSPS bistable
alarms
were
not valid and that
a reactor trip was not required.
The
SS directed the
CO
not to trip the reactor.
Recognizing that failure to manually trip the
reactor deviated
from Proc'" .re PK04-12,
the
SS contacted
the operations
director to apprise
him of the situation.
The operations director concurred
in the SS's decision not to trip the reactor.
As part of the followup review, the inspectors
also reviewed the event
on the
plant-specific simulator.
The simulator demonstration
verified that the
failure was isolated
to the
SSPS
system's
control
board demultiplexers
since
no alarms
were annunciated
on the plant process
computer.
Additionally, other
actual plant instrument indications
such
as pressurizer
pressure
and
steam
generator
level were within their normal
ranges.
With these indications,
as
well as the main turbine operating
when the
SSPS
system indicated, all main
steam
stop valves
were closed, it was readily apparent
to the operators
that
a
plant trip condition did not exist.
Based
upon this post-event
simulator
reenactment,
the operators
actions to stop,
inform the shift foreman,
review
plant indications,
and decide not to trip the reactor
were considered
by the
inspector to be prudent
and avoided
an unnecessary
challenge
to the plant's
safety
systems.
?.3.2
Procedural
Adherence
The inspector
reviewed several
operations
department
administrative
procedures
to determine if operators
had acted appropriately
in deviating
from the
requirements
of Procedure
PK04-12.
The inspector
noted that
Procedure
OP1.DC10,
"General Authorities and Responsibilities
of Operating
Shift Personnel,"
Revision lA, delineates
the responsibilities of all plant
~e
0
operators.
Specifically, it states
that each operator
should believe
and
respond conservatively to instrument indications unless
they are proven
incorrect.
Through discussions
with the
CO, the inspector determined that
there
was sufficient information available to the
CO to question
the validity
of the
SSPS
alarms.
The inspector also noted that both Procedures
OPl.DC12,
"Conduct of Routine Operations,"
Revision 2,
and OPI.DC11,
"Conduct of Control
Operations-Abnormal
Plant Conditions," Revision 2, direct operators
to
immediately inform the
SFM,
as
a minimum,
when abnormal
or unexpected
plant
conditions arise.
In accordance
with Procedure
OP1.0C12,
the
SFM shall also
be notified for situations
where plant conditions differ from what is assumed
in a procedure
and equipment affected
by the procedure
shall
be maintained
in
a safe
and stable condition.
The inspector
noted that the
CO informed the
SFM
of the situation in
a timely manner
and that the
SS was present
to provide
immediate guidance
and direction.
Further,
Procedure
OPl.DCll, Step 5.5,3,
provides guidance
such that, "If an
.
.
.
. ... is in use
and it is
determined that entry conditions exist for a higher priority procedure,
use of
the existing procedure
should
be implemented,"
unless,
"b. The unit shift
foreman directs that the transition not be made."
2.3.3
Annunciator Response
Procedure
(ARP) Development
The inspectors
reviewed the licensee's
controls established
for the
development,
maintenance,
and revision of ARPs.
These controls were
delineated
in Procedure
ADl.DC17, "Writer's Guide for Operating
Procedures
and
Annunciator Response
Guidelines," Revision
1.
The procedure
provided adequate
instructions for the writing and biennial reviews of ARPs.
It was noted that
while the procedural
controls for ARPs
and
EOPs were sufficiently detailed
and
were similar to the procedural
controls for the
EOPs,
the maintenance .of the
and the operating
procedures
was more difficult than for the
EOPs.
This
condition existed
because
the licensee
had
implemented
an
EOP software
maintenance
program,
"VPROMS," but had"not done
so for other
EOP related
procedures.
As
a result,
when revisions
were
made which affected multiple
ARPs or operating
procedures,
a manual
search
and replacement activity was
conducted.
In addition to the above,
the inspector
conducted plant walkthroughs to review
control
room ARPs
and
ARPs posted at local operator panels (e.g., diesel
generator
local control station).
The inspector
noted that the procedural
guidance
and structure
was adequate
for the
ARPs sampled.
2.3.4
Corrective Actions
The inspectors
also conducted
interviews
and discussions
with key plant
managers
related to the event's corrective actions.
While the specific
corrective actions
taken were adequate (i.e., revising the specific
ARPs,
evaluations
using the plant-specific simulator,
and discussions
with operating
crews,
and others),
the licensee
had not yet formulated broader
scope
corrective actions
in response
to this event,
such
as training changes,
procedural
reviews,
and verifications of other similar circuit cards.
Discussions
with the operations director indicated that these
actions
had not
0
yet been initiated, but would include
some
form of training incorporated
into
the licensed requalification program
and
some additional
reviews of other
ARPs.
Followup of the broader
scope corrective actions will be reviewed under
Inspection
Followup Item 275/9518-01;
323/9518-01.
2.3.5
Conclusions
The, inspector
concluded that operator
response
to the event
was appropriate.
Operators correctly evaluated
redundant
alarms
and indications to determine
the validity of the
SSPS
alarms,
and supervisory
involvement in the decision
to deviate
from Procedure
PK04.12
was evident.
The inspector considered
the
decision
not to trip the reactor to be appropriate
in that it precluded
an
unnecessary
being placed
on the plant
and the challenge of safety
systems,
when annunciators
were degraded.
2.4
Reactor Cavit
Sum
Level Indication and Recorder
2.4.1
Instrument Failure
As
a result of the erratic indication
on the Unit 2 reactor cavity sump level
recorder
(LR-62)
on December
29,
1995, Action Request
(AR) A0389792
was
initiated.
On January
5,
1996, during
a review of operator logs
and ARs, the
inspector
noted that operators
had observed
sump level indication anomalies.
The records
indicated that operators first noted the erratic indication at
approximately
11 p.m,
on January
4,
1996, while performing Surveillance
Test
Procedure
(STP) I-lA, "Routine Shift Checks
Required
by Licenses,"
Revision 54.
The instrument
was noted to be drifting between
5 and
7 inches.
Earlier in the day.; the level
was steady at
2 inches.
Later in the shift, the
SFH along with the
SS determined that,
although the instrument
was indicating
erratically, the instruments
were considered
The inspector
noted that
a week earlier,
on December
29,
1995, operators
had
observed
a similar erratic indication
on the Unit 2 reactor cavity sump level
which resulted
in an automatic start of both reactor cavity sump
pump~.
Based
upon both the erratic indication
and the satisfactory results
from the
performance of STP R-10C,
System Water Inventory Balance,"
Revision
13A, operators
determined that the indication was erroneous
and
declared
the reactor cavity sump level indication inoperable,.
Later that day,
technical
maintenance
purged the bubbler tube for the instrument
and tested it
to verify that it was functioning properly,
and operations
declared it
A description of the instrument
and its erratic indication are
further discussed
in Section
5. 1.
2.4.2
Inspector
Followup
The inspectors
interviewed the involved
and
SFN, the operations director,
and technical
maintenance
engineers,
The operators
had questioned
the
operability of the reactor cavity sump level instrument
and
had followed the
status of the instrument throughout the shift, but took no action to verify
its operability.
They noted that the instrument
was still indicating
on scale
P
II
l
h
and that it was only indicating
3 to
7 inches
(toward the end of the shift)
above the suspected
level.
They also noted that the
AR initiated on
December
29,
1995,
had
been written after the high level indication caused
an
automatic start of the reactor cavity sump pumps.
In addition,
the operators
noted that the corrective action taken in response
to the December
29,
1995,
failure was to purge the bubbler.
Using this information, operators
determined
the instrument
was operable.
No justification for this
determination
was provided in the
AR.
The control
room did not contact the on-shift technical
maintenance
personnel
to inform them that there
was
a concern
over the instrument.
When the erratic
indication was noted,
the licensee
was in the
TS Action Statement for
(associated
with reactor coolant system leakage detection)
as
a
result of both particulate radiation monitors
(RM-11 and
RM-12) being out of
service.
The radiation monitors
had
been out of service since
December
31,
1995, for calibration.
With the combination of these, inoperable monitors
and
an inoperable reactor cavity level monitoring system,
the Action Statement
required that the unit be placed in HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Based
upon
the impact of having two systems for reactor coolant
system
leakage detection
the operator's
technical
basis for concluding that the instrument
was operable
was more safety significant.
The inspector
noted that Administrative Procedure
OM7. 108, Revision
1B,
"Operability Evaluation," required that
any systems,
structures,
or components
found to be in
a degraded
condition
be expeditiously evaluated for the
consequences
of the degraded
condition,
The procedure
also required
a
documented
basis for the conclusion of operability.
This basis
was required
to provide sufficient detail
such that
an independent qualified reviewer would
bo. able to review the basis without relying on additional explanation.
In
reviewing the Prompt Operability Assessment
(POA), the inspector
noted that
there
was
no documented
basis for the conclusion of operability in the AR.
The
AR noted the change
in the indicated
sump level
between
the previous
reading of 2 inches
and the fact that at the time the level
was drifting
between
5 and
7 inches.
AR A0389792 concluded that "although LI/LR-62 are
indicating erratically,
ops continues
to consider
them operabie."
No basis
for this conclusion
was noted in the AR.
The instrument
had
been declared
and the
TS Action
Statement'ntered
a week before for similar instrument behavior.
The control
room staff
did not address
recurrence
or the possibility of another
cause for failure in
their operability determination.
The inspector discussed
this concern with
the operations director.
The director had already
reviewed the issue
and
determined that the actions initiated upon discovery of the level
anomaly
had
not met management
expectations.
The. operations director noted that,
under
the circumstances,
further actions
should
have
been promptly initiated to
investigate
instrument operability.
In addition, the operations director
expected
that management
would be informed of the issue
due to the possible
consequences
of the
TS Action Statement.
gt
"e I
-10-
The corrective action taken following shift turnover
on the mcrning of
January
5,
1996,
was to add
11 inches of water to the
sump.
Airier about
5 minutes,
the reactor cavity level indication dropped rapidly to
approximately
3 inches
and
began to show
a slow increase
in level that
corresponded
to the decrease
in level in the reactor coolant drain tank level.
The apparent
reason for the erratic indication was buildup of boric acid
crystals
in the level sensing line (3/8 inch stainless
steel
tubing).
The
sump level is measured
based
upon the back pressure
on the slight amount of
air flowing through the line.
Filling of the
sump apparently dissolved
the
boric acid crystals
which blocked the end of the line.
The inspector
noted
that
an operability evaluation
had
been
performed in 1991.
Although this
evaluation
was completed
and actions
developed to blow down or flush the lines
in response
to erratic indication of the reactor cavity sump level indicator,
.it was not used.
This information was available through
a review of AR
history, but was not easily available to either operators
or technical
maintenance
personnel.
1
2.4.3
Conclusion
The inspector
concluded that the
SFH and
SS did not have
an adequate
technical
basis for the operability determination.
The inspectors
determined that the
failure to document
the basis for the operability evaluation of the
containment
sump level indicator in accordance
with licensee Administrative
Procedure
ON7. I08, is
a violation of 10 CFR Part 50, Appendix B, Criterion
V
(Violation 323/9518-02).
2.5
Char in
Pum
0 erabilit
On January
12,
1996,
the inspector
noted that the ~ngineering staff had
identified possible
concerns with centrifugal charging
pump operability on the
January
11,
1996.
The licensee's initial concern
was that, if the
recirculation valves,
which when
open allow a minimum flow from the discharge
of the
pumps
back to the
pump suction,
were closed while the
pumps were
running
and
system pressurization
event occurred,
the
charging
pumps could overheat
and
become
The recirculation valves
(normally open)
are shut during surveillance testing of the
pump,
This
concern
was identified in the
SS turnover sheet for day shift on January ll,
1996.
The sheet
indicated that
a compensatory
measure
was, in place to prevent
the closure of the valves until the analysis
was complete.
The inspector
discussed
the concern with a CO, both senior control operators,
and the
SFN on
day shift on January
12,
1996.
None of the individuals were
aware of the
concern or could explain the basis.
The shift supervisor
was
aware of the
concern,
but could not explain it.
The inspector discussed
the concern with
the operations director.
He explained the basis
and went
on to explain that
the individual responsible
for preparing
input for the shift orders
had
been
out sick the day the concern
was identified.
The input was to be
prepared'ater
that day.
The inspector
concluded that the operators
had not received
adequate
turnover
and that implementation of the administrative controls
had
been unnecessarily
delayed.
The inspector
noted that instructions
had
been
T
(
IR
0
-11-
issued
tc
,
event closure of the recirculation valves duriag surveillance
testing
and the operations director cou1d
now issue shift orders to assure
timely communications
to operators.
3
MAINTENANCE OBSERVATIONS
(62703)
I
During the inspection period,
the inspector
observed
and reviewed selected
documentation
associated
with the maintenance
and problem investigation
activities listed below to verify compliance with regulatory requirements,
compliance with administrative
and maintenance
procedures,
required quality
assurance
department
involvement,
proper use of safety tags,
proper equipment
alignment
and
use of jumpers,
personnel
qualifications,
and proper retesting.
Specifically, the inspector
reviewed the work documentation
or"witnessed
portions of the following maintenance activities:
Unit I
~
Pump l-l governor
and bearing oil sample
and change;
exercise of overspeed, trip mechanism.
~
Battery Charger
2-2 capacitor
replacement;
clean,
inspect,
and test.
Unit 2
~
Battery 2-3 room area
temperature
monitoring channels calibration.
I
Selected
observations
from the activities witnessed
are discussed
below.
3. 1
Batter
Room
Tem erature Monitorin
Channels Calibration
On December
19, l995, the inspector
observed
technical
maintenance
technicians
test the
room temperature
sensors
in Battery 2-3 room.
The test
was performed
in accordance
with Procedure
MPI-23-T. 1, "Electrical
and
ESF Equipment
Room
Area Temperature
Monitoring Channels Calibration," Revision" 4.
During the
performance of the test,
the inspector
noted that the technician
climbed
on
the battery rack to get closer to the sensor
on the ceiling in order to freeze
spray the sensor
to bring down the temperature
to the lower setpoint.
The
inspector
was concerned
that,
should the individual slip or fall, he could be
injured or damage
the safety-related battery.'he
inspector discussed
the
practice of standing
on the battery rack, with the Unit 2
SFM and later with
the technical
maintenance
foreman responsible for the job.
Neither foreman
concluded that
a poor work practice
had
been
used or that the operability of
the batteries
could have
been affected.
The inspector discussed
the work practice
concern with the electrical
and
instrument maintenance director.
The inspector
noted that in this case
no
damage
had
been
done,
but stressed
that the battery posts
could break or the
individual could
be injured if the individual fell or slipped.
The director
agreed
that
a poor work practice
had
been
used.
The technical
maintenance
e
-12-
group planned to purchase
a S-foot fiberglass
ladder that could
be used in the
battery
rooms to perform the task in the future.
In addition,
due to the
close proximity of the electrical
and engineered
safety feature
(ESF)
room
sensors
to each other, technical
maintenance
technicians
plan to discuss
the
possibility of the
"ESF Equip
Rooms
Temp Honitor" alarm annunciating during
the test
due to the close proximity of the sensors.
The inspector
was concerned
of the failure of the
SFH to be sensitive to
potential operability issues.
The inspector discussed
this concern with the
operations director
and the operations
service
manager.
The manager
acknowledged
and
was
aware of the concern
and explained that this was
one of
the areas
on which the licensee
was working to improve.
The inspector
concluded that climbing on the safety-related
battery rack was
a
poor work practice.
The management
actions
taken
by the licensee
in response
to the concerns
were appropriate.
4
SURVEILLANCE OBSERVATIONS
(61726)
Selected
surveillance tests
required to be performed
by the
TS were reviewed
on
a sampling basis
to verify that:
(1) the surveillance tests
were correctly
included
on the facility schedule;
(2)
a technically adequate
procedure
existed for performance of the surveillance tests;
(3) the surveillance tests
had
been
performed at
a frequency specified in the TS;
and
(4) test results
satisfied
acceptance
criteria or were properly dispositioned.
Specifically, portions of the following surveillance
were observed
by the
inspector during this inspection period:
Unit
1,
Special
Test
Run of Safety Injection
Pump
(SIP)
1-1 (Special
Test
Procedure)
~
STP H-16A, "Slave Relay Test of Trains
A and
B K603 (Safety Injection),"
Revision
22
Unit 2
~
STP H-llA, "Heasurement
of Station Battery Pilot Cell Voltage
and
Specific Gravity," Revision
11
I-S3EPT, "Protection Set III Eagle
21 Partial Trip Board Actuation
Test," Revision
0
~
Special
Test
Run of SIP 2-1
I
The following are selected
observations
from the activities witnessed,
'
Ll '
-13-
4.1
S ecial Test
Run of SIP 1-1
On December
20,
1995,
the inspector
observed
portions of a special test
performed
on SIP 1-1.
The test
was performed
as
a partial test of
STP P-SIP-ll,
"Routine Surveillance
Test of Safety Injection
Pump 1-1,"
Revision
2, for the purpose of obtaining baseline
information from the
differential pressure
transmitters
used to monitor pump performance.
The
collected data
from SIP 1-1,
a
pump with historically stable
performance
characteristics,
would then
be used to compare trends relative to the
performance
data
from surveillance tests of SIP 2-2.
Performance
data
from
previous surveillance tests of SIP 2-2 had
shown
an apparent
degradation
in
pump performance
since its installation in March 1995.
The test
was not being
perFormed to meet Technical
Specification periodic surveillance
requirements.
The inspector
observed
that the test
was generally well performed with two
exceptions.
First, the technician
who installed the instrumentation failed to
properly tighten
an instrument line fitting between
the
pump suction
and the
differential pressure
transmitters.
This resulted
in
a small spill of
contaminated liquid outside of the posted
surface
contamination
area
around
the
pump.
When the inspector brought the spill to the radiation protection
technician's
attention,
the technician
took appropriate
measures
to stop
and
assess
the spill.
As
a result of his survey,
the technician
Found that
no
contamination
had
been
spread.
Second,
the inspector also noted that the technician installing the
instrumentation
had inadvertently reversed
the suction
and discharge test
connections
to the differential pressure
transmitters.
However, this was not
identified until after SIP 1-1 was started.
This resulted
in a second
pump
start of SIP 1-1 once the problem was corrected.
The inspector
reviewed
Procedure
STP P-SIP-11
and noted that Steps
11.2.2
and 11.2.4 direct the
installation of four separate
differential pressure
instruments
across
the
suction
and discharge test connections
of SIP l-l.
The procedure
provided
no
specific guidance
on test connection configuration at the instruments
and,
thus, skill of the craft was relied upon for proper
alignment.
The inspector
questioned
the system
en'gineer
on the effect that this error may have
had
on
test results.
The system engineer
explained that posttest calibration results
would indicate whether
there
was
any adverse effect on the
instruments'erformance.
The inspector
noted that one of the instruments later failed
posttest calibration.
The inspector also noted that with the other three
differential pressure
instruments
there
was
no adverse
impact
on the test with
the failure of one of the instruments.
The inspector
concluded that both the loose fitting and the improper
installation of the test
demonstrated
a lack of attention to detail
on
the part of the technician
and the system engineer.
The failure to properly
install the test instrumentation
also resulted
in
a second,
unnecessary
start
of SIP 1-1.
4.2
SSPS Partial Tri
Actuation Test
On December
20,
1995,
the inspector
observed
as technical
maintenance
technicians
performed Surveillance
Test Procedure
STP I-36-S3EPT,, "Protection
Set III Eagle
21 Partial Trip Board Actuation Test," Revision 0.. This test
verified that signals
input into the
SSPS translated into'rips
on the control
board annunciators.
If completed successfully,
the test would verify that
SSPS
alarms
received earlier in the shift were due to
a problem in the control
board demultiplexer cabinet that provides input to the control
board
The test
was performed successfully
in accordance
with the
procedure.
The only problem the inspector
noted
was poor communication
between technical
maintenance
supervision
and the technicians
involved.
The
SS explained that
the test would include
a review of the plant computer alarm printout to ensure
that the signals
fed into the
SSPS
were recorded
on both the control
board
indicators
and
on the plant computer,
The procedure
did not require
verification of the plant computer alarm printout and the technicians
were not
aware of the requirement
when the inspector questioned
how this verification
would take place.
The technicians later informed the inspector that they were
not aware of the requirement
and would be verifying the plant computer
printout.
The inspector
concluded that the technicians
were knowledgeable of
surveillance
requirements
and the equipment
being tested
and that the poor
communication that occurred did not affect the results of the test.
4.3
S ecial Test
Run of SIP 2-1
On January
4,
1996,
the inspector
observed
a special test run of SIP 2-1.
The
sole purpose of the test
was to obtain baseline
acoustic data for the start
and stop of the
pump in preparation for the test run of SIP 2-2 the following
week.
During recent
runs of SIP 2-2,
a unexpected
loud noise
was heard
when
the
pump was started.
The installation of acoustic
sensors
would provide the
ability to localize
and identify the source of the noise if it were to recur.
The data collected
from the SIP 2-1 start would give the engineering staff
a
baseline for the analysis.
The
pump was run using
a "formal communication
sheet"
which provided
directions for the applicable portions of Section 6.5,in Operating
Procedure
OP 8-38: I, "Accumulators - fill and Pressurize,"
Revision 6.
The
inspector
noted that the steps
to start
and stop the
pump were appropriately
identified.
The inspector attended
the briefing before the test.
The Unit 2
SFH led the discussion.
All personnel
involved with the test attended.
The
briefing addressed
the requirement
to start
and stop the
pump,
the
need for a
delay between
pump starts,
and the assignment
of an auxiliary operator to
observe
the run and to communicate with the control
room.
The inspector
noted that
much of the instrumentation
on the
pump was in a
contaminated
area.
The inspector
noted that the engineers
working inside the
contaminated
area
used
good radiation protection practices.
The operator
't
S>
f
-15-
assigned
to assist
during the test exhibited
good attention to detail in
ensuring
personnel
working in the room were aware of radiation protection
hazards.
The inspector
observed
the first pump run and the collection of data.
No
concerns
were noted.
However,
communication
problems
developed
between
the
engineering
personnel
and the control
room prior to the
second
run.
After the
engineers
informed the operator that they were ready for the
second start,
the
operator
stepped
out of the room to discuss
contacting another individual
prior to starting the
pump.
Before the operator returned to inform the
engineers
that the control
room was going to start the
pump, the
pump started.
The engineers
did not have the opportunity to turn on their monitoring
equipment
and
no one
was monitoring SIP 2-2 to ensure that there
was
no'everse
rotation.
The operator
assigned
to assist
in the test appropriately
obtained
a portable
phone to ensure that remaining communications
were
effective.
The
pump was started
a third time to allow the engineers
to record
the information they needed,
The inspector
reviewed the "formal communication
sheet"
used to run the
pump.
It directed that the steps
used to start
and stop the
pump during Modes
1, 2,
or 3 be used
and that the steps
used to fill and pressurize
the accumulator
be
omitted.
The inspector
noted that the omitted step
numbers
had
been crossed
out and that Step 6,5.3,
which required that SIP 2-2 be observed for reverse
rotation while starting
SIP 2-1
had
been
added to the procedure.
The addition
of this step
was
one of the actions
taken in response
to indication of
degradation of SIP 2-2 performance.
The actual
procedure
used
was not easy to
follow because
of the crossed
out steps
and the renumbering of -the steps after
the addition of Step 6.5'.
The installation of the acoustic
instrumentation
was performed separately
using
a temporary modification/jumper log.
There
were
no steps
in the procedure that addressed
the instrumentation.
The inspector discussed
the poor communications with the
SFM, the operator
involved,
and the operations director.
The operator
had thought that,
when
the engineers
said they were ready,
the
pump could
be started
at any time.
The engineers
had understood
that there would be further delays
due to the
need to contact other individuals
and
assumed
that the control
room operator
would contact
them before the start to allow them to switch on their
monitoring equipment.
The operator
in the control
room started
the
pump when
told to do so by the operator
in the field.
The engineers
had taken the
responsibility to observe
SIP 2-2 during each start,
but, were not in place to
do so because
they were not expecting
the start.
As
a result of these
misunderstandings,
SIP 2-2 was not observed
during the
second start
as
required
by Step 6.5.3 of Procedure
OP 8-3B: I.
The
SFM discussed
several
concerns
he identified to operations
management.
The major concerns
were the
poor communication that resulted
in
a third pump run
and the poorly developed
procedure.
These
concerns
were provided to the engineering staff to improve
the procedure.
The inspector
concluded that poor communications
during the
second
pump run
caused
a step in the procedure
to be missed.
The significance of this error
4'
-16-
was that
a
pump with questionable
performance,
SIP 2-2,
was not observed for
reverse rotation to ensure that the start of SIP 2-1 did not potentially
further degrade its condition.
The overall significance of the incident is
low because
SIP 2-2 was observed
during the first and third start of SIP 2-1
with no reverse rotation noted.
This failure constitutes
a violation of minor
significance
and is being treated
as
a noncited violation, consistent
with
Section
IV of the
5
ONSITE ENGINEERING
(37551)
The inspectors
reviewed
and evaluated
engineering
performance
as discussed
below.
5. 1
Reactor Cavit
Sum
Level Instrument Failures
As
a result of the concerns
raised
in regard to the operability of the reactor
cavity sump level instrument
(Section 2.4), the inspector interviewed licensee
personnel
and reviewed applicable
records
concerning
past failures of this
instrument.
5. 1. 1
Instrument
and Problem Description
The reactor cavity sump monitoring system is used to provide indication of the
sump level in the control
room.
The system consists of 3/8 inch, field run,
stainless
steel
tubing, the
end of which is cut at
a 45 degree
angle
and is
approximately
1 inch above the bottom of the reactor cavity sump.
A slight,
constant air flow is maintained
through the tube
so that bubbles
are released
through the end.of,.the
tube.
As sump level rises,
a higher air pressure
is
required to maintain
a constant air flow through the bubbler.
The change in
air pressure
in the tube is sensed
by a pressure
transmitter.
Level
Instrument LI-62 then translates
the pressure
signal into
a
sump level,
measured
in inches.
Level Recorder
LR-62 records
the
sump level indication
over time.
Oue to the low amount of water leakage
into the reactor cavity sump in Unit 2,
the level in the
sump remains
low as evaporation
removes
the water.
Consequently,
solid and dissolved
contaminants
(e.g., boric acid) concentrate
in the
sump over time.
The licensee
has determined that at low sump levels
these
contaminants
tend to build up around the
end of the bubbler tube,
causing partial or complete
blockage of the tube.
This blockage translates
to
a higher pressure
being
sensed
by level Instrument LI-62 producing
a higher
than expected
level indication.
When blockage
becomes
severe,
the level
instrument reading
may tend to spike high and could potentially initiate an
automatic start of the reactor cavity sump
pumps,
as
was the case
on
December
29,
1995.
i
-17-
5. 1.2
Failure History
In reviewing the ARs for the instrument,
the inspectors
noted that there
had
been three periods
since
1991 during which the instrument
had failed'a
number
of times.
In 1991,
two ARs, A0232711
and A0234156,
were written to address
Instrument LI-62 operating erratically.
The first time, technical
maintenance
purged the bubbler line with air and the indication on the instrument returned
to normal,
This process
was repeated
the second
time and
an operability
evaluation of the problem was performed.
The evaluation
found that the
instrument could
be considered
when it started
acting erratically as
long as it was
on scale.
However, the spiking level
was to be addressed
promptly by blowing down the bubbler tube with air or flushing with water.
In
addition, the evaluation
noted that blowing down the bubbler tube only
temporarily fixed the problem.
The bubbler tube would then have to be
cleaned.
If the bubbler tube were to become fully plugged,
the indicator
would go to full scale
and remain there.
In addition to the immediate
corrective actions,
AR A0233008 was initiated to have the
sump cleaned
at the
next opportunity.
As
a result,
the
was cleaned
during Refueling
Outage
2R5.
In 1994, three
ARs, A0333893,
A0347026,
and A0349615,
documented erratic
reactor cavity sump level indication.
In each
case,
upon noting erratic
indication, operations
declared
the instrument
and entered
TS 3.4.6. 1.
The corrective action in each
case
was to purge the bubbler tube,
As
a result of AR A0333893, operations
requested
that the
be cleaned
again.
After determining the task would not be minor maintenance,
the task
was cancelled.
On two of the ARs, the author stressed
the importance of
addressing
the problem because
of the possible
consequences
of a coincidental
failure of Radiation Monitor RM-11
(known to be unreliable)
and,
as
a" result,
the
TS requirement
to place the plant in HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
After
the third AR,
a quality evaluation '(gE (0011479)
was initiated.
As
a result,
engineering
developed
a modification to replace
the 3/8 inch stainless
steel
tube with a 1/2 inch stainless
steel
tube.
Although p'ians were
made to
complete the work during Refueling Outage
2R6, the modification package
was
not completed until after the outage
had started.
Due to the
amount of
planning that
had to be done
based
on the number of groups involved, the late
stage of the outage,
the dose rate in the
sump,
and the fact that the
instrument
was operable after it was flushed,
licensee
management
determined
the modification would be installed at
a later date.
It was
added to the
forced outage list and
added to the scope for Refueling Outage
2R7.
The inspector
noted that operations
generated
a request
to clean the reactor
sump in response
to AR A0333893.
This was cancelled after the licensee
determined that it was not minor maintenance
on April 22,
1994.
This request
was generated
well in advance of Refueling Outage
2R6, which would have
allowed the activity to be planned
and to occur during the outage.
On November
11
and
28,
1995,
Instrument LI-62 was again identified as
indicating erratically.
ARs A0385966
and A0387351
were generated,
the
'
1
p
-18-
instrument
was declared
and
TS 3.4.6. 1 was entered.
The bubbler
tube
was flushed in both cases
and returned to service.
5. 1.3
Conclusions
The inspector
concluded that the licensee
missed
an opportunity to repeat
the
corrective action identified in 1991, cleaning the reactor cavity sump,
when
a
request to clean the
was cancelled
in April 1994.
This request
was
generated
well in advance of Refueling Outage
2R6.
In addition,
the licensee
was slow to implement long-term corrective actions,
such
as the bubbler tube
modification or maintaining water in the
sump,
to =preclude
the recurrence of
failures of the reactor cavity sump level instrument,
6
PLANT SUPPORT ACTIVITIES
(71750)
The inspectors
evaluated
plant support activities
based
on observation of work
activities, review of records,
and facility tours.
The inspectors
noted the
following during these evaluations.
6. 1
S stem
Sam le
On January
12,
1996,
the inspector
observed
as
a chemical
and volume control
system pressurized
sample
was collected.
The chemistry technician collected
the sample
in accordance
with Chemistry Procedure
CAP E-l, Revision
11A,
"Sampling of Primary Systems."
The sample
was taken at the
Sample Sink,
which is in a contaminated
area.
The technician
used
good radiation
protection practices.
Both the
room containing the
sample sink and the
chemistry lab were well maintained
and clean.
The sample sink valves
were
appropriately labeled
and
a schematic
was provided
on the valve rack to assist
with valve lineups.
The inspector
concluded that the work was performed in
accordance
with the procedure
and that the
human factors designed"into
the
sample sink area
were
a strength.
f,
'
A
ATTACHMENT 1
1
PERSONS
CONTACTED
1. 1
Licens~e
Personnel
G.
M.
Gene
W.
H.
L. F.
G. L.
H. J.
- T. R.
- J.
R.,
D. H.
- D. K.
W.
G.
R.
N.
- T. F.
Engi
- J
O
J.
H.
T. L.
C.
D.
- J.
R.
- D. B.
J.
E.
J.
P.
- p
- D, H.
- R. P.
H. J.
D. A.
R.
A.
- J.
C.
1
~ 2
NRC Personnel
Rueger,
Senior Vice President
and General
Manager,
Nuclear
Power
ration Business
Unit
Fujimoto, Vice President
and Plant Hanager,
Diablo Canyon Operations
Womack,
Vice President,
Nuclear Technical
Services
Anderson, Shift Supervisor,
Operations
Services
Angus,
Hanager,
Regulatory
and Design Services
Baldwin, Senior Engineer,
NSSS Engineering
Becker, Director, Operations
1
Behnke,
Senior Engineer,
Regulatory Services
Cosgrove,
Supervisor,
Safety
and Fire Protection
Crockett,
Manager, guality Services
Curb,
Manager,
Outage Services
Fetterman,
Director, Electrical
and Instrumentation
and Control
Systems
neering
Fuhriman,
Engineer, guality Assurance
Galle,
Engineer,
NSSS Engineering
Grebel, Director, Regulatory Support
Harbor,
Engineer,
Regulatory Support
Hinds, Director, guality Control
Hiklush, Manager,
Engineering
Services
Holden,
Manager,
Maintenance
Services
Northness,
Shift Foreman,
Operations
Services
Nugent,
Senior Engineer,
Regulatory Support
Oatley, Director, Mechanical
Maintenance
Powers,
Manager,
Operations
Services
Phillips, Director, Technical
Maintenance
Vosburg, Director,
NSSS Engineering
Waltos, Director, Balance of Plant Engineering
Young, Director, guality Assurance
- M. Tschiltz, Senior Resident
Inspector
J. Dixon-Herrity, Acting Senior Resident
Inspector
- S. Boynton, Resident
Inspector
B. Olson, Project Inspector
G. Johnston,
Senior Project Inspector
T. HcKernon,
Reactor
Inspector
- Denotes those
attending
the exit meeting
on January
19,
1996.
2
EXIT MEETING
An exit meeting
was conducted
on January
19,
1996.
During this meeting,
the
inspectors
reviewed the scope
and findings of the report.
The licensee
4
acknnwledged
the inspection findings documented
in this'eport.
The licensee
did not identify as proprietary
any information provided to, or reviewed by,
the inspectors.
t"
ATTACHMENT 2
CO
POA
SFM
SSPS
TS
action request
response
procedure
control operator
circulating water
, emergency
operating
procedure
engineered
safety feature
main feedwater
pump
nuclear
steam supply system
Prompt Operability Assessment
public document
room
plant process
computer
shift foreman
safety injection
pump
shift supervisor
solid state protection
system
surveillance test procedure
Technical Specification
71