ML16341E256
| ML16341E256 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 05/12/1987 |
| From: | Johnston K, Mendonca M, Narbut P, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E254 | List: |
| References | |
| 50-275-87-13, 50-323-87-12, IEIN-86-096, IEIN-86-96, IEIN-87-001, IEIN-87-1, NUDOCS 8706080092 | |
| Download: ML16341E256 (32) | |
See also: IR 05000275/1987013
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION
V
Report Nos:
50-275/87-13
and 50-323/87-12
Docket Nos:
50-275
and 50-323
License
Nos:
and
Licensee:
Pacific Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
Facility Name:
Diablo Canyon Units
1 and
2
Inspection at:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
March
15 through April 25,
1987
p
Approved by:
L. M.
Pa ovan,
Res~dent
Inspector
K. E. Jo nston,
Resident
In
ector
P.
P.
Nar ut, Senior Resident
In pector
M. M. Mendonca,
C ief, Reactor
Prospects
Section
1
Date Signed
~+re/8'7
g
d
4
ev
<iS
C~
vp'ate
Signed
W/<a r'8 7
Summary:
Ins ection from March
15 throu
h
A ril 25,
1987
Re ort Nos.
50-275 87-13
and
50-323
8 -1
Areas Ins ected:
The inspection
included routine inspections of plant
operations,
fo
ow-up of on-site events,
maintenance
and surveillance
activities,
and licensee
event reports
(LERs), as well as selected
independent
inspection activities.
Inspection
Procedures
30703,
57050,
61726,
62703,
71707,
71710,
73051,
90712,
92700,
92701,
and 93702 were applied during this
inspection.
Results of Ins ection:
Three violations were identified.
The first is for
fai ure to ta
e prompt corrective action for an identified deficiency.
The
second
is for a violation of facility Technical Specification 3.3.1.
This is
a violation of procedure for control
room activities.
8706080092
870512
ADOCK 05000275
8
PDR"
DETAILS
1.
Persons
Contacted
J.
D. Shiffer, Vice President
Nuclear Power Generation
"R.
C. Thornberry, Plant Manager
J.
A. Sexton, Assistant Plant Manager,
Plant Superintendent
"J.
M. Gisclon, Assistant Plant Manager for Technical
Services
J.
D. Townsend,
Assistant Plant Manager for Support Services
- R.
G. Todaro, Security Supervisor
- D. B.
Miklush, Maintenance
Manager
J.
E. Molden, Operations Training Supervisor
W.
G. Crockett,
Instrumentation
and Control Maintenance
Manager
M. J.
Angus,
Work Planning Manager
L.
F.
Womack, Operations
Manager
- T. L. Grebel,
Regulatory Compliance Supervisor
S.
R. Fridley, Senior Operations
Supervisor
R.
S. Weinberg,
News Service Representative
"M.
W. Stephens,
I&C Administration General
Foreman
D.
A. Malone, Senior
I&C Supervisor
B.
L. Peterson,
Instrument Maintenance
General
Foreman
D.
L. Bauer,
Senior
Power Production Engineer, Electrical Maintenance
M.
M. Mendonca,
Chief, Reactor Projects
Section 1, from US
NRC Region
V
was also in attendance
at the resident's exit meeting.
The inspectors
interviewed several
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.
2.
0 erational
Safet
Verification
General
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's
facility.
The observations
and examinations of those activities
were conducted
on
a daily, weekly or monthly basis.
On a daily basis,
the inspectors
observed control
room activities to
verify compliance with selected
LCOs as prescribed
in the facility
Technical Specifications.
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.
While touring a Unit 2 containment penetration
area,
the inspector
observed
an acetylene
pressurized
gas (welding) bottle attached
to
an approximately
2 inch component cooling water
supply line for
support.
The welding, authorized
by Construction Entry Permit
15107,
was for replacement
of Post-LOCA Panel
80.
The inspector
discussed
the supporting of the gas bottle with the attendant
Bechtel welder.
The welder indicated
he
had not received
instruction about attaching pressurized
gas bottles to safety
related piping.
This situation
was brought to the attention of the
General
Construction Project Superintendent,
and
he was reminded
that similar problems
were encountered
during the Unit 1 refueling,
and that corrective actions
should
have
been previously instituted.
The Superintendent
indicated the topic would be discussed
with
Bechtel
supervision.
The inspector also noticed general
area lighting in the Unit 2
auxiliary building
had deteriorated.
For example,
some lighting
fixtures were not functioning around centrifugal charging
pumps 2-1
and 2-2, entry area to the residual
heat
removal
(R8R) heat
exchanger
2-2 and boron injection tank (BIT) room,
component cooling
water
pump
(CCW) 2-3, turbine driven auxiliary feedwater
pump, fuel,
handling building 100 foot elevation corridor by the
RWST,
and the
interspace
room (containing FI-85 and 88 for CCW to the
RHR heat
exchanger)
from the auxiliary building to the 100 foot containment
area.
These
items were brought to management's
attention for correction.
Units
1 and
2 Fuel Handlin
Bui ldin
Ventilation
S stem Walkdown
En ineered
Sa et
Features
S stem
Wa
downs
The inspector
performed
a walkdown of physically accessible
portions
of the
Fuel Handling Building Ventilation Systems of Units I and 2.
No equipment conditions or items that might degrade
system
performance
were identified.
Labelin
of Unit 2 Control
Room Annunciator Window
On Saturday, April 18,
1987,
unused control
room annunciator
window
PK 12-3 began flashing.
Operations
personnel
apparently attached
a
slip of paper to the window of the irrelevant annunciator.
However,'n
an act of levity, inappropriate
and unprofessional
wording was
written on the paper.
This wording was later transferred
to the
window through the use of a marking pen.
Specifically, the words
were
"EAT AT JOE'S."
Another shift subsequently
replaced
the
wording with a different, but similarly inapproriate
and
unprofessional
phrase utilizing a more formal lettering method.
The
words
on this occasion
were
"PATRONIZE BOB'S BEANERY."
At about
ll:30 a.m.
on April 19,
a
member of an Augmented Inspection
Team
(AIT) observed
the inappropriate
wording on the annunciator.
On
April 20,
1987 at approximately 8:00 a.m.,
a resident
inspector
and
the AIT member brought the fact of the annunciator
wording to the
attention of the plant superintendent
and other plant management.
However, just prior to the NRC's notification of plant management,
at 7:30 a.m.
on April 20th, the window lettering was identified by
the Operations
Manager
who immediatly directed that the lettering
be
removed.
Removal of the lettering was observed
by other plant
managers,
as well as representatives
of the
NRC.
The fact that several different shifts of plant operators
and their
supervisors
were aware of and condoned
the use of inappropriate
and
unprofessional
wording in the control
room, raises
a concern
regarding
the proper
exercise of professional
control
room
responsibi lities, and the proper job performance attitude,
by
operations
personnel.
The Operations
Manager
and Plant
Superintendent
met with the involved shift formen
(SFM) to discuss
their role in setting the leadership
tone for the entire facility.
The managers
emphasized
that actions of this nature
"never have
and
never will be acceptable
behavior."
Separately,
the Operations
Manager met with all
SFM and shift technical
advisors
(STAs) to
discuss
why the actions
taken
by the involved crews were not
acceptable.
No disagreements
were presented
by the
SFM and
STAs.
The managers
ascertained
that the actions
taken
by the operators
were an attempt to heighten
the fact that the flashing annunciator
was
a "nuisance
alarm" in need of repair.
Operators
did conclude
no
effect on plant safety or operations
would result prior to labeling
the window.
However, the
NRC is concerned
that this instance
represents
a failure of first line supervision,
or higher, to set
a
proper
and professional
tone in the conduct of control
room
operations
and that the enforcement
actions
contained
in this and
other reports
may have resulted
from such inattention to control
room responsibilities.
One
During'he next month, the Plant Nanager
and Plant Superintendent
plan to discuss
overall
management
expectations
with all operations
crews.
The use of inappropriate
wording on an annunciator is
a
potentially distracting activity in the control
room, contrary to
NPAP A-103, and is considered
a violation (Open Item
50-323/87-12-02).
violation and
no deviations
were identified.
3.
Onsite Event Follow-u
a ~
Unit 2 Safet
In ection
and Reactor Tri
The Unit 2 reactor
had
a safety injection, reactor trip and unit
trip on Narch 21,
1987 at 7:42 a.m..
The unit was at 97K power and
ramping to lOOX following a routine power reduction for turbine
governor valve testing.
Because of the safety injection, the
licensee
declared
as unusual
event.
Proper notifications were
made
in a timely manner.
The cause
was determined to be the unplanned
closure of main steam isolation valve (NSIV) 2-FCY-41.
The closure
of this valve caused
the steam flow in the other
3 steam
leads to
increase.
The high steam flow resulted in low steam generator
pressures.
The coincidence of high steam flow and low steam
generator
pressure
caused
the safety injection signal.
The safety injection/trip recovery
was normal.
No offsite releases
occurred
as
a result of the event.
All equipment
operated
normally.
The cause
of the NSIV closure
was subsequently
determined to be
a
short in the NSIV position indication switch
(POS 821).
The
electrical control circuity is such that
a short across
the position
switch causes
an air solenoid valve
(SV 298) to open,
bleeding air
from the air operator of NSIV FCY-41, allowing the valve to begin to
drift shut.
Because
FCY-41 is
a reverse
mounted
power operated
as
soon
as the disk dropped
a few degrees
into the flow
stream,
the force of the steam flow caused it to slam shut,
as
designed.
The cause of the short in
POS 821 was later determined to be water
intrusion into the switch," presumably
from heavy rains that morning.
The switch is designed
to be weathertight but examination
showed the
sealing
gasket material
had leaked over an extensive
period of time.
The licensee's
investigative actions
included:
o
The determination of the cause of the closure of FCV-41
discussed
above.
o
An engineering
walkdown examination of piping affected
by the
sudden
closure of FCY-41.
The results
were satisfactory.
The
walkdown identified three suspect
piping snubbers
which
subsequently
tested satisfactorily.
o
An x-ray examination of valve FCV-41, for any damage to the
seat or disk.
The results
were satisfactory.
The last two
examinations
were not required
by federal regulations
but were
good prudent technical
actions
taken
by the licensee.
o
The corresponding position switches of the other Unit 2
environmentally
exposed
MSIVs were checked electrically with
high voltage
(meggered)
to verify no water intrusion and
satisfactory operation.
Other corrective actions
taken prior to restart,
in addition to the
above,
included replacement of the defective switch and its mounting
and cabling harness
(proper engineering
approvals
were obtained).
Functional testing of the environmentally
exposed
MSIVs in Unit 2
was performed.
The Unit returned to power on March 26,
1987.
The
resident
inspector attended
the plant Technical
Review Group
(TRG)
meeting held on the event.
The group categorized
the event
as
isolated,
but recognized
the possibility that the other Unit 2
switches in dry environments
and the Unit 1 switches might be
subject to similar failure.
The
TRG therefore
decided to recommend
replacement
of all such switches in the next refueling outages
of
Units 1 and 2.
They also scheduled
meggering of the exposed
Unit 1
switches at the next unscheduled
outage.
The licensee
had examined industry failure data
bases for equipment
and found no evidence of repeated failure for these
switches.
The
licensee
therefore
determined that Part 21 reportability is not
required for this switch.
The licensee
performed
a review of past problem reports
on these
switches
and determined that in September
1986
a similar electrical
problem was noted
on FCV-41 (ground indication - valve would not
stay open) but the condition cleared
and would not repeat.
The
concluded that the condition at that time was possibly caused
by the
switch.
Unit 1 was also found to have
a problem with burned out
contacts
on
a similar switch which may have
been
caused
by a similar
condition.
The Unit 1 situation
was corrected
by a design
change
allowing the
use of spare
contacts
in the switch.
These indicators
might have led to the discovery of deteriorated
in the
switch, but disassembly
of the switch was not performed
because
the
switch is not manufactured
in a way such that it can
be disassembled
for inspection (it is of riveted construction).
The inspector inquired as to whether the licensee
would conduct
a
study of other equipment which is environmentally qualified (Eg),
has sealing gaskets,
and
has
a similar situation where the gaskets
are not required to be replaced periodically.
The inspector
discussed
the fact that most
Eg equipment with gaskets
have the
replaced periodically (generally
2 years).
The licensee
is
considering this action
(Open Item 50-323/87-12-01).
Unit 1 Reactor Tri
Due to 500
KV S stem Disturbance
On March 15,
1987 with Unit 1 in Mode 1,
a reactor trip occurred
when
an airplane crashed
into the Diablo Canyon-Gates
500
kV
transmission
line approximately
50 miles from the plant site.
When
the airplane collided with the 500
kV transmission line,
a three
phase to ground electrical fault occurred,
which caused
a large
500
kV system current
and Voltage transient.
The transient
created
a
low voltage condition on the plant auxiliary power system
and caused
a reactor trip due to reactor coolant
pump bus undervoltge relay
actuation.
The appropriate
emergency
procedures
were followed,
the
unit was stabilized in Mode 3,
and
a significant event
was declared.
All safety
systems
functioned properly.
At the time of the event,
the Unit 1 main generator
voltage
regulator
was in manual control, pending regulator adjustments
to
eliminate undesirable
system fluctuations observed
ear lier while in
automatic control.
The Unit 2 main generator
voltage regulator
was
in automatic control at the time of the event,
and was able to
adequately
compensate
for the voltage transient permitting continued
power operation of Unit 2.
The licensee
determined
the root cause of the reactor trip was the
inability of the unit to withstand the major 500
kV voltage
transient with the main generator
voltage regulator in manual
control.
With the regulator in manual control,
a low voltage
condition on the reactor coolant
pump bus could not be averted.
Subsequently,
adjustments
to the voltage regulator were completed
and the Unit 1 voltage regulator
was returned to automatic control.
RHR Crosstie
Valve Isolation
On March 17,
1987 at 0625
PST with Unit 2 at 100 percent
power,
crosstie
valve 8716B was closed
and
removed
from service for
installation of valve position indication.
Operations
personnel
later recognized this action placed the plant into a configuration
described
in IE Information Notice (IN) 87-01
"RHR Valve
Misalignment Causes
Closing valve
8716B was not consistent with the plant's
RHR system safety analysis
assumption that
RHR injection into all four Reactor Coolant System
(RCS) cold legs would be available,
assuming
a single active failure
of one of the
RHR pumps.
With the crosstie
valve closed,
and if
only one
injection flow would be provided to
only two of the
RCS cold legs.
However, during the time that valve
8716B was closed,
both
and together
were
capable of injecting into all four
RCS cold legs.
Upon
identification of the concern,
RHR crosstie
valve 8716B was opened
and
RHR system configuration was returned to normal.
As corrective action, additional
guidance
was provided to Operations
personnel
regarding the repositioning or removal
from service of
Emergency
Core Cooling System
(ECCS) valves that are
system related
rather than train related.
Plant Engineering
has
reviewed all
applicable test procedures
relative to this guidance.
Also,
was contacted to perform
a site specific analysis
regarding the acceptability of injection into only two
RCS cold
legs.
The inspector
forwarded information to Region
V
about
a
potential generic safety question
concerning
the
need for Technical
Specifications for the
RHR crosstie
valves.
Information possessed
by the licensee,
describing the impact of
closing
a crosstie
valve on
RHR system operability,
was not made
available to plant operators
and personnel
involved in equipment
clearance activities in a timely manner.
On October 30,
1986 the
Onsite Safety
Review Group
(OSRG) issued Action Request
A0042404,
which identified the consequences
of isolating an
RHR crosstie
valve,
and specifically indicated operations
personnel
should
be
made
aware of those
consequences.
Shortly thereafter,
OSRG
representatives
discussed
this situation with licensee
management.
Actions taken
by PG8E included 1) submitting proposed
inservice
testing program changes
to
NRC to change
the frequency of crosstie
valve stroke testing from quarterly to only during cold shutdown,
and 2) obtaining Westinghouse
evaluation of IN 87-01.
However, the
licensee failed to take timely corrective action for operations
personnel
and clearance
coordinators
to prevent the situation from
developing
on Unit 2.
In a related matter,
the Training Department
had obtained
information from the Institute of Nuclear
Power Operations
(INPO)
"Network" and
NRC Daily Plant Reports
about the
D.
C.
Cook plant
safety injection system
(SIS) crosstie
valve isolation which
occurred
on September
12,
1986.
An instructor lesson
guide
was
prepared
by the Training Department,
and by February
1987
requalification training was provided to all five operating
crews
regarding isolating the SIS crosstie
valves.
However, the
applicability of the SI crosstie
valve information to the
RHR system
was not stressed
enough to prevent the condition from occurring at
Diablo Canyon.
As corrective action, the licensee's
Training
Department
agreed to devise
ways to identify critical training
information and
make it stand out during training classes.
The failure to take timely corrective action,
described
in this
section of this report, is an apparent violation of the requirements
of 10 CFR 50, Appendix
B (Item 50-275/87-13-01).
Unit 2 Loss of RHR
Pum
Durin
Col d Shutdown
On April 10,
1987 while Unit 2 was in cold shutdown with the hot
legs at mid-loop in preparation for the installation of the steam
generator
nozzle
dams,
both
RHR pumps were shut off for 86 minutes.
The
RHR pumps were shut off at 2125 hours0.0246 days <br />0.59 hours <br />0.00351 weeks <br />8.085625e-4 months <br />
due to cavitation.
The
cavitation occurred
due to a loss of hot leg water inventory which
initiated vortexing in the
RHR suction line.
The loss of inventory
resulted
from an increase
in
RHR letdown to makeup
volume control
tank (VCT) level which was being inadvertently drained.
An
engineer,
in preparation for a containment penetration
leak rate
test,
was draining the reactor coolant
pump seal
return line.
Two
leaking boundary valves
on this line provided the drain path from
the
VCT to the Reactor Coolant Drain Tank (RCDT).
The operators
terminated
the event when they opened
a gravity feed
path from the refueling water storage
tank
(RWST) to the
RCS after
receiving word that the steam generator
manways,
which had been
scheduled for removal,
were still in place.
The operators
were then
able to restart
an
RHR pump to re-establish
flow through the core.
The
RHR pump discharge
temperature
registered
220 degrees
F,
indicating that boiling had occurred.
In the process
of flooding
the
RCS,,
one steam generator
manway (which had been untorqued,
but
not removed)
leaked approximately
30 gallons.
In addition,
steam
was emitted when
a tygon hose running from the reactor vessel
head
vent to the top of the pressurizer
ruptured
due to high temperatures
and slight pressurization.
An NRC Augmented Inspection
Team (AIT) was dispatched
to the site
and began investigation April 14,
1987.
An analysis of this event
and an evaluation of the licensee's
preparedness
and response will
be contained in the AIT's Inspection
Report (50-323/87-18).
Unit 1
RCP Bus
E Underfre uenc
Rela
Between
1123 hours0.013 days <br />0.312 hours <br />0.00186 weeks <br />4.273015e-4 months <br />
on April 19,
and
0206 hours0.00238 days <br />0.0572 hours <br />3.406085e-4 weeks <br />7.8383e-5 months <br />
on April 20,
1987,
one Unit 1 reactor coolant
pump
(RCP) underfrequency
(U/F) trip
channel,
which had been discovered
inoperable at 0930 hours0.0108 days <br />0.258 hours <br />0.00154 weeks <br />3.53865e-4 months <br />
on April
19,
was inadvertently left in a bypassed
condition.
The facility
Technical Specifications
require that
an inoperable
channel
be
placed in a tripped condition within 6'ours.
On April 19, at approximately
0930 hours0.0108 days <br />0.258 hours <br />0.00154 weeks <br />3.53865e-4 months <br />,
I&C shift control
technicians
(SCTs) performing
STP I-9A, "Trip Actuating Device
Operational
Test,
12
KV Undervoltage,
Underfrequency,"
discovered
that U/F relay 81VER3 would not trip when frequency
was lowered
below its minimum setpoint of 53.9
Hz.
U/F relay 81VER3 is one of
three relays which provides
an input to the reactor protection
system
(RPS)
two out of three underfrequency
As
required
by Surveillance
Test Procedure
(STP) I-9A, an
SCT attempted
to notify the Shift Foreman
(SFM) that
81VER3 was inoperable.
However, miscommunications
between the
SCT and
SFN resulted in the
Unit 1 SFN interpreting that the
SCT was having problems with the
relay and was going to notify his foreman to have the problem
resolved.
At that time the
RPS bistable related to relay 81VER3 was
tripped since the relay test transfer switch was in the "Test"
position and the Technical Specification
Equipment Operability
Status
Sheet
(AP C-6S4), in possession
of the
SFM, correctly listed
the relay as tripped.
Following the discussions
with operations,
the mids shift
Instrumentation
and Control (I8C) technicians
conducted
a turnover
with the day shift.
The off going shift informed the on coming
shift that the
SFN had been notified of the failure of U/F relay
81VER3 and requested
the oncoming shift verify the inoperability of
relay 81VER3.
At approximately
1030 hours0.0119 days <br />0.286 hours <br />0.0017 weeks <br />3.91915e-4 months <br /> the day shift SCTs went
to the control
room to have
a turnover briefing with the
SFM.
However, the operability of 81VER3 was not discussed.
The
SCTs then
proceeded
to 12
KV Bus
E and verified all the test equipment
was
setup
as the mids shift had left it.
They then tested relay 81VER3
and confirmed that it was inoperable.
0
One of the
SCTs proceeded
to the control
room and requested
permission to continue with undervoltage
relay testing,
the next
step in STP I-9A.
To continue with the undervoltage
relay portion
of STP I-9A, the procedure
requires that the
RCP underfrequency
relay test switch is returned to the
"NORMAL" position.
Since the
test switch had been turned to "NORMAL" when the
SCT approached
the
control operator
(CO), the
CO, observing that the underfrequency
status light was not lit, and assuming that since it was not lit and
the
SCT was requesting
permission to proceed,
the problems
on relay
81VER3 had been taken care of and the relay was available for
service.
Based
on this, the
CO dated
and timed the Equipment
Declared Operable 'portion of the Technical Specification
Equipment
Operability sheet for 81VER3.
This was
done at 1123 hours0.013 days <br />0.312 hours <br />0.00186 weeks <br />4.273015e-4 months <br />.
At this
time,
U/F relay 81VER3 was not tripped and represented
a channel
bypass
to the logic of the
RPS, i.e.
a channel
which,would not trip
on
a genuine
U/F condition.
Therefore,
a
2 out of 2 logic was
required for an U/F trip on Bus
E.
Once granted permission,
the
SCTs continued with the undervoltage
relay testing.
However,
upon completion of the relay testing,
the
SCTs did not perform the "return to service" portion of the
STP.
This was
done since relay
81VER3 was inoperable
and required repair
by electrical
maintenance.
Although it provided
a tracking system
for the inoperable relay, it was not timely enough to have the
bistable tripped, within the requirements
of the technical
specifications.
At approximately
0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />
on April 20, 1987, the mids shift SCTs
who had originally discovered
the inoperability of relay 81VER3
entered
the control
room and noticed that the status light for relay
81VER3 was not lit.
Upon further review they discovered that the
returned to service portion of STP I-9A had not been performed
and
there
was
no indication in I8C's logs that relay 81VER3 had been
repaired.
When asked,
the
SFM informed the
SCTs that
as far as
he
knew, relay 81VER3 was operable
and in service
and requested
the
SCTs test the relay to determine its operability.
At 0206 hours0.00238 days <br />0.0572 hours <br />3.406085e-4 weeks <br />7.8383e-5 months <br />,
the
RCP U/F relay test switch was placed in "TEST", essentially
tripping the channel.
At 0220 hours0.00255 days <br />0.0611 hours <br />3.637566e-4 weeks <br />8.371e-5 months <br />,
the
SCTs determined that relay
81VER3 was still inoperable.
Therefore,
relay 81VER3 was in a
non-tripped condition between
1123 hours0.013 days <br />0.312 hours <br />0.00186 weeks <br />4.273015e-4 months <br />
and 0206 hours0.00238 days <br />0.0572 hours <br />3.406085e-4 weeks <br />7.8383e-5 months <br />,
a total of
15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />
and 43 minutes,
following a surveillance
where it had been
determined
Technical Specification 3.3. 1, Table 3.3-1,
Item 16, specifies that
the minimum number of operable
channels for the reactor trip on
underfrequency
is two per bus, with the provisions of Action
Statement
6 applicable.
Action Statement
6 specifies that with the
number of operable
channels
one less
than the total
number of
channels,
power operation
may proceed provided the inoperable
channel
is placed in the tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
and the
minimum channels
requirement is met.
Since relay 81VER3
was discovered
inoperable at 0930 hours0.0108 days <br />0.258 hours <br />0.00154 weeks <br />3.53865e-4 months <br />, it was required to be
tripped at 1530 hours0.0177 days <br />0.425 hours <br />0.00253 weeks <br />5.82165e-4 months <br />.
Therefore,
the licensee
operated
in a
10
condition not provided for in their Technical Specifications for 10
hours
and
36 minutes.
STP I-9A requires that for a channel
out of tolerance
due to an
apparent
module fai lure, the
I8C supervisor
and
SFM are to be
notified immediately that the channel
is inoperable.
In addition,
STP I-9A restates
the requirements
of Technical Specification 3.3. 1,
specifically that an inoperable
channel
is placed in a tripped
condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Had either conditions of this procedure
been successfully
executed,
the licensee
would not have violated
their Technical
Specifications'he
provision in STP I-9A that requires
the notification of the
SFM
was attempted
by the
SCTs.
However, apparent
miscommunications
and
the resulting assumptions
led operations
and
I8C to reach
separate
conclusions with regards
to the operability of relay 81VER3.
This
example of miscommunication
appears
to be related to other examples
of informal or secondhand
communications
adversely affecting quality
of work or operations
(Inspection
Report Nos.
50-275/87-04
and
50-323/87-04,
50-275/86-29
and 50-323/86-27,
and 50-275/87-10
and
50-323/87-09).
In this example,
the verbal
communication path,
as
opposed to a formal signed transfer,
existed
when the
CO and
SFM
were permitted to declare
the equipment operable
through verbal
communications with the
SCTs.
The licensee
should consider this
apparent
avenue
where
a miscommunication
can result in the return to
service of inoperable
equipment.
The "Precautions"
section of STP I-9A reiterates
the requirements
of
Technical Specification 3.3. 1, specifically that an inoperable
U/F
channel
is to be placed in a tripped condition within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
A
tripped channel
is indicated
by a status light in the control
room.
Steps
2. h. i and 2. h. 2 of STP I-9A require the
SCTs to initial that
the
RCP U/F test switch was placed in "NORMAL" and the
Bus
E U/F
status light is out.
Although the body of the procedure
does not
provide steps
to be taken for an inoperable
channel, it should
have
been apparent
to the
SCTs
upon completion of these
steps that they
were leaving relay 81VER3 in a bypassed
condition and were setting
up for a Technical Specification violation as described
in the
precautions
section of STP I-9A.
The licensee
should address
the
familiarity of personnel
with the precautions
section
and other
sections of surveillance test procedures
which precede
the procedure
section,
The inspector
noted that the licensee
promptly initiated an
investigation into this event.
This investigation included
statements
from both shifts of SCTs involved on April 20 and both
operations shifts involved on April 22,
1987.
A Technical
Review
Group was convened
on April 23.
Proposed corrective actions include
(1) an incident report which will detail the miscommunication to be
read by all operations shifts
and discussed
with all I8C shifts and
(2) a revision to STP I-9A which will separate it into ten
procedures,
one for each relay,
and provide guidance
in the body of
the procedure
regarding actions to be taken
when
an inoperable
channel
is discovered.
However,
these actions
do not completely
mitigate the significance of this event in that this is an example
of a reoccurring problem of communications
compounded
by I8C
maintenance
personnel
not fully understanding
the. precautions listed
in their procedure.
Therefore, this is an apparent violation (Open
Item 50-275/87-13-02).
4.
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.
Furthermore,
the inspectors verified maintenance activities were
performed
by qualified personnel,
in accordance
with fire protection
and
housekeeping
controls,
and replacement
parts
were appropriately
cer tified.
a.
Diesel Generator
Coolin
Water Shutdown Switch
The inspector
observed portions of calibration of temperature
switch
95 which activates
the jacket water temperature
relay on Unit 2
diesel-generator
2-2.
With the diesel in local control,
and the
mode control switch (on the diesel
generator
local panel) in the
test
mode,
the diesel
engine,
generator field, and generator air
circuit breaker
are tripped through shutdown relay SDR-22 if the
high jacket water temperature
relay picks
up.
Work was performed in
'ccordance
with Work Order R-0018690.
The as found switch setpoint
was
195 degrees
F, which did not fall within the acceptance
band of
205 degrees
F plus or minus
4 degrees
F.
Accordingly, the switch
setpoint
was adjusted to 204.8 degrees
F.
However, completion of
the work was not possible,
as electrical
power to the diesel
generator
local control panel
was not available.
Without electrical
power at the panel,
temperature
switch activation of the shutdown
relay could not be observed.
b.
Unit 2 Emer enc
Diesel Air Com ressor
The inspector
observed portions of preventative
maintenance
performed
on the Unit 2 emergency
diesel
generator
(D/G) 2-2 air
compressor
2-2.
The maintenance
included changing the air
compressor
belts
and filters.
The inspector
observed that the belts
were replaced with an appropriate
replacement
and installed within
acceptable
tightness
tolerances.
The inspector
noted that one step,
with one sign-off, in the work order included the installation of
three different sets of parts.
The maintenance
personnel
involved
at the time of the inspection
had been
issued only two sets of
parts.
The package
had been worked on by previous
crews
and
following crews were to complete the job.
The inspector
noted that
with one sign-off for three parts there
was the potential for
confusion.
The inspector
discussed
this issue with the maintenance
manager
who
found the level of control of parts for the air compressors
adequate
for the quality of work performed
based
on the following:
12
o
The Plant Information Management
System
(PIMS) computer
tracking of parts
issued to the field is referenced
by work
order
number and is therefore
a verification of what parts
are
installed,
and
o
The air compressors
are not class
lE equipment
and the filters
are not quality related.
The inspector also discussed
this concern with work planning
personnel
who noted that the appropriate
method for maintenance
personnel
to document the implementation of two parts out of three
would be to add
a note in the comments section of the package.
The
inspector
reviewed the completed work package
and noted that this
was done.
Based
on the above,
the inspector
found the level of
control of parts for this maintenance activity was adequate.
Unit 2 Emer enc
Diesel
Generator
2-2 Undervolta
e Auxiliar
Rela
s
The inspector
observed portions of Maintenance
Procedure
E-55,
"Routine Preventive
Maintenance of +SG'uxiliary Relays,"
performed
on the
4KV breaker undervoltage auxiliary relays
27XHHB2,
27YHHB2, and
27ZHHB2 associated
with emergency
diesel
generator
2-2.
The maintenance
procedure
requires that the relay is cleaned
thoroughly and then checked for appropriate
pickup and dropout
voltages.
The inspector
observed that the maintenance
was performed
with an appropriate
clearance
and that calibrated
instruments
were
used to record pickup and dropout voltages.
No violations or deviations
were identified.
5.
Survei 1 1 ance
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.
Diesel
En ine Generator
1-3 Manual Start
The inspector
observed portions of STP M-9A-3, "Diesel
Engine
Generator
1-3 Routine Surveillance Test."
The test
was performed in
preparation of returning
D/G 1-3 to service following a maintenance
outage.
As required
by procedure,
the diesel
was started
manually
from the Unit 2 control
room.
Prior to the inspector's
observation
of the test,
the operators
attempted to parallel the diesel
generator
to its bus,
but the breaker failed to close.
It was
determined that the contactor coupling had not fully made
up due to
the breaker
not having been
racked in completely.
Since these
are
the types of problems the surveillance is designed to uncover prior
to placing the diesel
generators
back in service,
the corrective
action taken
was to correctly rack in the breaker.
Once the breaker
was closed
and the diesel
was slowly loaded to 2.6
MW the inspector
observed
an auxiliary operator collect field data.
The inspector
0
'3
verified testing
was accomplished
in accordance
with an approved
test procedure
and that test data
was accurate
and complete.
b.
Waste
Gas
S stem
Ox
en Anal zer
The inspector
observed portions of functional testing of the Unit 2
waste
gas
oxygen monitoring system in accordance
with STP I-79A
"Functional Test of Waste
Gas
System
Oxygen Analyzer 75."
Special
Radiation
Work Permit 86-020 was approved
and in effect for the
test.
Alarm and protective function setpoints
were found to be
within acceptance
criteria,
and the data sheet
was completed
as
required
by the procedure.
Required administrative approvals to
perform the test
had been obtained.
c.
Unit 1
SSPS
Slave
Rela
0 eration
The inspector
observed portions of STP H-16J, "Operation of Slave
Relay
K612 Train A 8 B."
Slave Relay K612B, when actuated,
closes
blowdown and sample lines for containment isolation
Phase
A.
Relay
K612A has
no function and is not tested.
Technical Specification 4.3.2. 1 Table 4.3-2 requires that Solid State
Protection
System
(SSPS)
slave relays related to containment
isolation are tested
on a nominal quarterly frequency.
The
licensee,
however,
performs slave relay testing for containment
isolation within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of'he Actuation Logic Testing
(STP
I-16A2) which is required in Table 4.3-2 to be performed
on
a
monthly frequency or at least every
62 days
on
a staggered test
basis.
The inspector
observed
communications
between operations
personnel
performing the test.
Appropriate test data
was taken,
and
systems
were returned to service
as required
by the procedure.
No violations or deviations
were identified.
6.
NRC IE Information Notice 86-96
Closed
IE Information Notice (IE-IN) 86-96,
"Heat Exchanger
Fouling Can Cause
Inadequate
Operability of Service Water Systems,"
discusses
the potential
for fouling in heat exchangers
in raw water systems
and its affects
on
a
facility's ability to reject heat to the ultimate heat sink.
As required
in Administrative Procedure
(AP) C-14Sl, "Dissemination of Operating
Experience,"
the licensee
reviewed IE-IN 86-96 for applicability to the
Diablo Canyon Site.
Their review concluded that only one safety related
heat exchanger
was subject to the potential for fouling, specifically the
CCW heat exchanger.
The Auxiliary Saltwater
(ASW) system,
which takes
its supply from the Pacific Ocean
and is the plant's ultimate heat sink,
removes
heat from the
CCW system through the
CCW Heat exchanger.
The
following design features
and operational
and maintenance activities are
in place to minimize fouling of the
ASW system.
1)
Bar racks
and traveling screens
remove debris at the intake to the
ASW pumps.
2)
Periodic demusseling
and desliming minimizes fouling of the
ASW
system.
0
3)
CCW heat
exchanger
differential pressure
(delta
P) can
be monitored
in the control
room.
Excessive fouling will result in a high alarm
at a delta
P of 167 inches of water.
The heat exchanger
is
considered
operable with up to 170 inches of water delta
P.
If high
delta
P is verified, Annunciator Response
procedures
require that
the heat exchanger is isolated for cleaning.
4)
As part of the monthly surveillance testing program,
CCW heat
exchanger
performance is measured.
The
CCW system,
which is
a closed
loop system that cools all other safety
related water cooled heat exchangers,
gets its makeup
from the makeup
water system.
The makeup water system
has three
main sources
of water;
the seawater
evaporator,
Diablo Creek and associated
waterwells,
and the
seawater
reverse-osmosis
unit.
All sources
are processed
through
a
clarifier, filter beds
and demineralizers.
Based
on the above discussion,
the inspector
concludes
the licensee
has
adequately
addressed
this issue
and it is thereby closed.
No violations or deviations
were identified.
Licensee
Event
Re ort Follow-u
Based
on an in-office review, the following LERs were closed out by the
resident inspector:
Unit 1:
86-21, 87-02,
87-04
Unit 2:
87-01, 87-02
The
LERs were reviewed for event description,
root cause,
corrective
actions taken,
generic applicability and timeliness of reporting.
Unit 2
LER 87-01 "Reactor Trip on Low-Low Steam Generator
Water Level"
failed to identify miscommunication
between
the
SFM and
CO as
a
contributing factor to the trip.
As documented
in Section 3.b of NRC
Inspection
Report (IR) 50-323/87-09,
at the time of the event the
SFM was
involved in a shift turnover briefing.
The
SFM had previously
communicated
to the
CO that
he wanted the plant to be on line by a
certain time, but did not mean to suggest that the turbine
ramp
up should
begin.
However, the
CO interpreted
the communication
such that the
turbine
ramp
up was initiated, while other experienced
operators
were
also participating in the briefing.
Via cover letter to the IR dated
March 31,
1987, the licensee
was requested
to provide written response
to
the
NRC describing corrective actions to prevent reoccurrence
of
miscommunications
of this nature.
In the
LER the licensee
did not
identify miscommunication
between
the
SFM and
CO as
a contributing factor
to the trip.
Accordingly, Pacific Gas
and Electric should take the steps
necessary
to be assured
that this event,
and all future events,
are
adequately
assessed
and reported to the
NRC,
and corrective actions
are
taken for all contributing factors to the events.
The licensee
agreed to
revise the
LER.
0
15
No violations or deviations
were identified.
8.
Defeated Safet
Features
and Intentional Entr
Into T.S. 3.0.3
Recently, at another nuclear
power plant in the United States,
operators
defeated
a plant safety feature
by inserting
a
dummy signal into safety
circuitry and then intentionally entering T.S. 3.0.3 for operational,
convenience.
In response
to this occurrence,
the inspectors
evaluated
the licensee's
controls which prohibit actions of this nature at Diablo
Canyon.
Administrative Procedure
(AP) C-4S1 "Mechanical
Bypass,
Jumper
, and Lifted Circuit Log Accountability System" specifically directs that,
if installation of a "jumper" results in " a change in the function of a
system operation
as described
in the
FSAR" a safety evaluation
must be
performed in accordance
with plant procedures.
For the purposes
of the
procedure,
the term "jumper" refers to an electrical
jumper, lifted
electrical
lead,
mechanical
bypass
or modification,
and any other bypass
which renders
a safety feature
incapable of performing its intended
function (such
as insertion of a
dummy signal).
The safety evaluation
must then
be approved
by the Plant Staff Review Committee prior to
installation of the jumper.
The inspector
concludes
the licensee's
procedure
AP C-4S1 addresses
the identified concern.
Regarding intentional entry into T. S.
3. 0. 3. for operational
convenience,
Operations
Department
personnel
indicated to the inspector that plant
policy prohibits intentional entry into T.S. 3.0.3.
The inspector
ascertained
that the licensee
had
no written policy in this regard,
and
that this policy was not specifically addressed
in operator
training
classes.
Accordingly, the licensee
agreed to perform the following:
o
A shift foreman's
memo stating plant policy on this matter would be
issued
and reviewed
by all operating shift crews.
o
Revisions to APs to preclude intentionally entering T.S. 3.0.3 would
be pursued.
o
Training Lesson
Plan
LM-8 will be revised to inform all licensee
candidates
that T.S. 3.0.3 should not be intentionally entered.
This policy will also
be covered during requalification training of
licensed operators.
No violations or deviations
were identified.
9.
Exit
On April 29,
1987
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph l.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.