ML16341E948
| ML16341E948 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 12/20/1988 |
| From: | Johnston K, Mendonca M, Narbut P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E947 | List: |
| References | |
| 50-275-88-31, 50-323-88-29, NUDOCS 8901170263 | |
| Download: ML16341E948 (58) | |
See also: IR 05000275/1988031
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
50-275/88-31
and 50-323/88-29
Docket Nos:
50-275
and 50-323
License
Nos:
Licensee:
Pacific Gas
and Electric Company
77 Beale, Street,
Room 1451
San Francisco,
California 94106
Facility Name:
Inspection at:
Diablo Canyon Units 1 and 2
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
October
23 through
December 3,
1988
K.
E. Johnston,
Resident Inspector
P.
P.
Narbut, Senior Resident
Inspec or
~Z~e
Approved by:
Y>C
>opfI'ate
Signed
g z. Q~~/I'V
Date Signed
M.
M. Mendonca,
Chief, Reactor Projects
Section
1
Date Signed
Summary:
Ins ection from October
23 throu
h December
3
1988
Re ort Nos.
50-275/88"31
~/
Areas Ins ected:
The inspection
included routine inspections of plant
operations,
maintenance
and surveillance activities, follow-up of onsite
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
30703,
36700,
61726,
62700,
62703,
71707,
92700,
92701,
92720,
93702,
and 94703 were used
as
guidance during this inspection.
Results of Ins ection:
One violation was identified regarding the failure of
a test engineer to follow a procedure
as described in paragraph 6.a..
No
deviations
were identified.
Areas of Stren ths
o
Although it occurred
immediately after the reporting period (on December
5, 1988) the licensee
notably achieved
a "black board"
on Unit 1.
This
effort reduced
the number of lit annunciators
during normal operation
from approximately
40 (two years
ago) to zero.
89011 70263 881220
ADOCK OSDO0275
G
PNU
o
The licensee's
management
response
to the
damage
and loss of a Unit 2
residual
heat
removal
pump while in a midloop condition was considered
to
be timely, thorough,
and commendably conservative.
The action plan
generated
and executed
was detailed
and actions specified were carried
out in formal ways such
as the issuance
of a temporary operating
procedure.
Areas of Weakness
Instances
of valve lineup problems
were emphasized
in the last resident
inspector
report (50-275/88-26).
Additional examples of valve lineup
problems occurred during this reporting period which reemphasize
the
need
for licensee
action.
Specifically, this report discusses
the discovery
of missing position seals
on an auxiliary feedwater
pump recirculation
valve (paragraph 3.b.), the-discovery of a mispositioned valve providing
sample air to the containment
vent noble gas radiation monitor (paragraph
4'.) and the unplanned
closure of the suction valve to a running safety
injection pump (paragraph
4. i. ).
Associated with the valve lineup
problems,
paragraph
11.b.
discusses
several
instances
of ineffective
action
on the part of quality surveillance
personnel
conducting valve
lineup survei llances.
This report contains
several
examples
of operator error and/or lack of
operator attention,
which, coupled with the inattentive overfilling of a
discussed
in the last resident inspector report
(50-275/88-26)
indicates
the
need for management
attention.
This report
discusses
a lack of operator attention in removing
a clearance
which led
to the
damage of running safety injection pump (paragraph 4.i.),
a lack
of operator attention resulting in four actuations
of the low temperature
overpressure
protection devices
(paragraph 4.o.),
and operator error in
failing to recognize
a need to perform compensatory
action when a
quadrant
power tilt ratio alarm was generated
dur ing nuclear instrument
calibrations
(paragraph
4. h. ).
o
The violation, identified in this report regarding
a test engineer
not
following procedure
for reading
an erratic
gauge during a surveillance
test, is a particularly noteworthy since the licensee
has
been
ineffective in resolving the previously identified problem of adequately
reading test instrumentation.
A similar violation was identified earlier
in February
1988.
Subsequently,
in September
1988,
a notice of deviation
was issued
because
the licensee
had not issued
a procedure
as committed
in the violation response.
The procedure
was subsequently
issued but
personnel
were apparently
not informed or trained in its use.
The issue
of ineffective communication of expectations
was also
a concern of the
most recent
SALP report and this violation reenforces
the
need for
continued
management
action.
DETAILS
1.
Persons
Contacted
"J.
D.
Townsend,
Plant Manager
"D.
B. Miklush, Assistant Plant Manager,
Maintenance
Services
"L. F.
Womack, Assistant Plant Manager,
Operations
Services
"B.
W. Giffin, Assistant Plant Manager,
Technical
Services
J.
M. Gisclon, Assistant Plant Manager for Support Services
C.
L. Eldridge, guality Control Manager
K.
C.
Doss,
Onsite Safety
Review Group
T.
A. Bennett,
Maintenance
Manager
W.
G. Crockett,
Instrumentation
and Control Maintenance
Manager
J.
V. Boots,
Chemistry
and Radiation Protection
Manager
T.
L. Grebel,
Regulatory
Compliance Supervisor
S. R.'ridley, Operations
Manager
R.
P.
Powers,
Radiation Protection
Manager
- W. J. Kelly, Compliance
Engineer
"S.
M. Skidmore, guality Assurance
Manager
"D. A. Taggert, guality Surveillance Supervisor
"W. T.
Rapp,
Onsite
Review Group. Chairman
- W.
D. Barkhuff, Senior guality Control Engineer
- T. J. Martin, Training Manager
The inspectors
interviewed several
other licensee
employees
including
shift foremen
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general
construction/startup
personnel.
- Denotes those attending the exit interview on December
12,
1988.
0 erational
Status of Diablo Can
on Units 1 and
2
Unit 1 was in power operations
at the beginning of the reporting period
and remained
so during the reporting period.
No reactor trips or
significant events
occurred.
Reportable
events
such
as containment
ventilation isolation occurred
as detailed in Section
4 of this report.
Unit 2 remained
in its second refueling outage for the reporting period.
The period began with fuel load just completed
and ended with the unit in
Mode 3 in preparation for return to service.
During the period numerous
events
occurred
as detailed in Section
4 of this report.
The most
notable of these
events
included severe
damage to two safety related
pumps; specifically,
a residual
heat removal
pump was
damaged
due to an
reassembly
error and
a safety injection pump was
damaged
due to operator
error in .processing
a clearance.
~ ~
3 .
0 erational
Safet
Ver ification
7l707
a.
Gener al
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's
facility.
The observations
and examinations of those activities
were conducted
on a daily, weekly or monthly basis.
On a daily basis,
the inspectors
observed control
room activities to
verify compliance with selected
Limiting Conditions for Operations
(LCOs) as prescribed in the facility Technical Specifications
(TS).
Logs, instrumentation,
recorder traces,
and other operational
records
were examined to obtain information on plant conditions,
and
trends
were reviewed for compliance with regulatory requirements.
Shift turnovers
were observed
on a sample basis to verify that all
pertinent information of plant status
was relayed.
During each
week, the inspectors
toured the accessible
areas of the facility to
observe
the following:.
(a)
General
plant and equipment conditions.
(b)
Fire hazards
and fire fighting equipment.
(c)
Radiation protection controls.
(d)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved procedures.
(e)
Interiors of electrical
and control panels.
(f)
Implementation of selected portions of the licensee's
physical
security plan.
(g)
Plant housekeeping
and cleanliness.
(h)
Engineered
safety feature
equipment alignment
and conditions.
(i)
Storage of pressurized
gas bottles.
The inspectors
talked with operators
in the control room,
and other
plant personnel.
The discussions
centered
on pertinent topics of
general
plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
b.
Auxiliar
Pum
Recirculation Sto
Valve Missin
Seal
On November 9, 1988, during a routine walkdown of the Unit 1
auxiliary building, the inspector discovered
valve FW"1"189, the
(AFW) motor driven pump 1-3 recirculation stop
valve,
was not sealed.
The inspector brought this to the attention
of the Shift Foreman.
A subsequent
review by the inspector of the applicable
sealed
valve
check list for the
AFW system revealed that the valve was required
to be sealed
in the'throttled position.
The monthly pump test
requires that the valve be throttled to allow between
49 and 51
gpm
recirculation flow with discharge
to the steam generator
isolated.
The inspector discussed
these findings with the shift supervisor
who
concluded that to determine if the valve was in the appropriate
position
an "as found" position was to be determined
(one quart'er
turn open),
and
a partial
pump test to be performed.
Initially,
during the
pump test,
the recirculation flow gage
read
between
40
and 140 inches of water, well outside the acceptance
criteria of 96
to 104 inches of water which corresponds
to between
49 and 51 gpm.
However,
due to erratic readings,
the gauge
was suspected
of being
inaccurate.
The gage
was
removed
and a new gauge
was installed.
The second
reading determined that recirculation flow was
50 gpm and
that the valve's
as found position was appropriate.
The inspector
discussed
this repeat
occurrence of a valve missing
its seal
(see inspection report 50-275/88-26) with the Operations
'Manager.
In the last inspection report, the Operations
Manager
described
a
new procedure for sealed
valves.
As a result of this
finding and others
by operations,
the licensee
is continuing to
review the sealed
valve program for adequacy
and
has initiated
a
equality Evaluation.
In addition,
an Action Request
was initiated to
evaluate
the
bad gauge.
The inspectors will continue to follow-up
the licensee's
corrective actions with regards, to the sealed
valve
program.
No violations or deviations
were identified.
4.
Onsite
Event Follow-u
93702
Unit 1 Inadvertent
Containment Ventilation Isolation
On November 2, 1988,
an auxiliary operator
erroneously
source
check
tested
the wrong monitor in the process
of source
check testing the
liquid radwaste radiation monitor RM-18,
a prerequisite for a liquid
r adwaste
discharge.
The, operator tes'ted the plant vent gas
radiation monitor (RM-148), causing
a containment ventilation
isolation (CVI).
The event was reported
as
a four hour
non-emergency
event and was also 'the subject of LER 1-88-23.
The
erroneous
source
check of RM-148 and consequent
CVI happened twice
in 1987.
Corrective actions taken in 1987 included implementation
of a source
check procedure
and improved labelling (red labels
on
all radiation monitors whose actuation results in a CVI).
Corrective
action for this most recent events
includes the
installation of plexiglass
covers
on radiation monitors which can
cause
a CVI.
The licensee
considers that the installation of covers
will inhibit operators
from source
checking the wrong radiation
monitor.
0
b.
Unit 2 Residual
Heat
Removal
Pum
2-2 Failure
On November
3, 1988, the lower motor bearing for Residual
Heat
Removal
(RHR) pump 2-2 failed shortly following its start.
It was
discovered
by an auxiliary operator
who smelled
and subsequently
saw
smoke
coming from the pump.
The pump was immediately shut
down
from the control
room.
The unit was in Mode
5 with the reactor coolant loops partially
filled.
This condition required both
since
the
RHR pumps were the only normal
and available
way to remove core
decay heat.
With the reactor coolant loops not filled, the steam
generators
were not available
as
a heat
removal
mechanism.
Other plant conditions
germane to the event were that the
containment
equipment hatch
was
open (containment integrity is not
required in Mode 5) and the reactor
coolant
pumps were uncoupled
and
on their backseat
(which provides possible-leak
path if the Reactor
Coolant System pressurized
as it would have if all
RHR cooling were
lost for several
hours).
Plant management
and the operating staff responded
to the event in a
timely, systematic
and thorough
manner.
The resident inspector
interviewed operations
supervision
and noted
that their initial actions
included elimination or stopping all work
on control
and power supplies that might effect the remaining
pump and, further, ordering the accelerated
hookup of at least
two
(so that core conditions could be monitored
if RHR was lost).
The resident
inspector attended plant management's
deliberations
and
action plan formulation meeting
and noted that the situation,
possible
scenarios,
and commensurate
actions
were thoroughly
discussed,
evaluated
and proper actions formulated and listed for
accomplishment.
The actions
included:
o
Establishin
containment closure
ca abilit within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of
loss of RHR.
This action included staging of tools personnel
and coordination with radiological personnel.
Later, in. the
evening of November 3, 1988, this action was changed to
straight
away containment closure
by direction of corporate
management.
o
Providin
an ade uate
S stem
vent
ath.
The licensee
blocked open
a Pressure
Operated Relief Valve
(PORV) and
had the Primary Relief Tank (PRT) rupture disk
physically removed to provide
a large vent path
and preclude
RCS pressurization.
o
Establishin
a contin enc
lan for o erations.
The licensee
prepared
and issued
a temporary procedure for operations
on
actions to be taken if RHR were lost.
The plan included
methods of feed
and bleed cooling and plant condition
0
prerequisites
including the blocked open
PORV, the removed
rupture disk, maintaining steam generators full (for reflux
cooling), maintaining two reactor thermocouples,
maintaining
a
charging
pump operable,
maintaining
a safety injection pump
maintaining wide range
and narrow range temporary
reactor
vessel
level indication,
and maintaining containment
closure.
The procedure
also included requirements
for
increased
monitoring of the operating
RHR pump including
trending of selected
parameters.
Licensee
management
also addressed
the paths to recovery from
the loss of the
RHR pump specifically, to repair the
damaged
pump or alternately to fill and vent the
RCS thus providing
steam generator availability.
Both paths
were accelerated
but
were predicted to require about
3 days.
The licensee
exited the event
on November 8, after the reactor
coolant
pumps were coupled
and the
RCS was filled and vented.
The repair of the
RHR pump was delayed
due to unpredicted
problems
such
as replacement
shaft runout problems (lack of
being straight)
and assembly with improper lubricant.
On
November
11,
1988, the
RHR pump was successfully tested
and
declared
The cause of the
RHR pump failure was the loosening of a nut on
the pump/motor shaft.
The nut was designed with a lock tab
washer which should
have prevented
the loosening of the nut.
One tab of the lock tab washer is turned
up against
a nut flat
and
one tab is turned
down against
a flat (or keyway)
on the
pump shaft thus preventing relative rotation of the nut and
shaft.
On the shaft of the failed pump the flat spot
had been
hand ground approximately flat as
opposed to more current
replacement
shafts
which have
a keyway machined in the shaft.
The approximate flat spot
on the shaft coupled with the fact
that the lock tab washer
was reused after
pump overhaul
(the
mechanic did not obtain
a
new lock tab washer) resulted in a
lock tab washer that did not perform its function and allowed
the nut to loosen.
Since the
pump is
a vertical shaft
assembly,
the loosening of this nut allowed the entire assembly
to move vertically downward with time.
The pump had been
successfully tested after overhaul
during the refueling outage
and
had successfully
run for about
350 pump hours.
The first
item to be
damaged
as the
pump moved vertically downward was
the lower motor bearing
lube oil sump which cracked allowing
oil to spill and
smoke
due to contact with hot rubbing
surfaces.
At the close of the reporting period the licensee
was preparing
but had not issued
a nonconformance
report on the event,
DC2-88-EM-N127.
The licensee
had determined that the event
was
not reportable
under
10 CFR 50.73 but was preparing to issue
a
voluntary
LER.
The licensee
had not completed root cause analysis at the end
of the reporting period but initial indications
expressed
by
the maintenance
manager
are that the maintenance
instructions
were not adequate.
The licensee
had not defined all actions required to prevent
recurrence
(in the absence
of a completed root cause analysis)
but had defined certain prudent actions; specifically:
o
The other Unit 2
RHR pump was partially disassembled
and the
lock tab washer installation was confirmed to be satisfactory;
o
The licensee
has prepared
a contingent design
change to stake
the nuts in place if required,
and
The licensee is preparing to examine the Unit 1
RHR pumps
and
the Unit 1 and Unit 2 Auxiliary Saltwater
(ASW) pumps which are
also vertical
pumps
and have
a similar nut locking device.
The inspectors will follow-up this item through the licensee's
LER
(2-88-15).
Com onent Coolin
Water Isolated to
RCP Thermal Barrier Cooler Of
W~ron
Unit
On November 4, 1988,
an
I8C technician isolated
component cooling
water to a Reactor
Coolant
Pump
(RCP) thermal barrier cooler for the
wrong unit.
The I8C technician
was to have worked on Unit 2 to fill and vent
a
flow indicator (2FI-90), the reactor coolant
pump thermal barrier
return flow indicator.
This work was performed
on Unit 1 instead,
which caused
an alarm in the control
room and
an automatic isolation
of component cooling water
(CCW) flow to the thermal barrier.
The technician realized
and reported his error to the control
room.
Operators
restored
cooling to the thermal barrier in accordance
with
their procedure AP-ll which requires
slow restoration to minimize
thermal
shock.
During the event
normal reactor coolant
pump seal injection was in
service,
therefore
the thermal
bar rier cooler function was not
required
and nothing detrimental
occurred to the reactor coolant
pump seals.
The I8C manager initiated a nonconformance
report
(NCR
DC1-88-TI-N216).
The underlying cause of the event
was determined
to be that the I8C technician
was dispatched
by his supervisor to
perform two jobs in sequence
(both requested
by operations).
The
first job was to check
an indicator locally at the waste
gas
compressor
in Unit 1 and then to perform an assist
step in a
surveillance
test
(STP-V-619,
Containment Isolation
Leak Valve
Testing)
Step 8.4.8 to cut in, fill, and vent FI-90 in Unit 2.
The
I&C technician
was verbally instructed
by the supervisor
and picked
a copy of the surveillance test procedure
page
from the operations
shift foreman.
For most jobs,
I8C technicians
are issued color
coded work packages,
the color accentuating
the unit to be wor ked.
As an aftermath of the event, it has
become clear that many "assist
jobs" (where
I8C action is invoked by an engineering
or operations
procedure)
do not result in a work package
being given to the
technician.
The licensee's
actions defined in the nonconformance
report were reviewed by the inspector.
The planned actions
included
counseling of the MC technician
and his supervisor
and establishing
policy that ."assist jobs" will be performed with work packages.
The licensee
determined that the event
was not reportable
under 10 CFR 50.73.
The inspectors
determined that the licensee's
actions
appeared
to be acceptable.
The effectiveness
of the licensee's
actions will be judged in the course of future inspection.
Diesel Generator
Technical
S ecification Inter retation - 24 Hour
Load Test
On November 4, 1988, the licensee's
Assistant Plant Manager for
Operations
and the Engineering
Manager discussed
with the Senior
Resident
Inspector
a technical specification interpretation which
had been
made
by the licensee.
Technical Specification 4.8. 1. 1.2.b.8 requires
a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> load test
of diesel
generators
to be performed every 18 months.
The technical
specification test requirement
as specifically written also requires
that the generator
achieve
a required voltage
and frequency within
13 seconds after the start signal.
This 13 second
requirement
had
not been
accomplished for one of the diesel
generator
units during
the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> lead test.
However, the
same parameter is specifically
measured
monthly during a start and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> run.
Therefore,
the
licensee
concluded that there
was
no technical
question regarding
diesel
generator operability.
The licensee
also concluded that the
technical specification requi rements
were met in that all specified
test functions
had been accomplished
in a relatively short time
period.
The resident inspector discussed
the licensee's
technical
specification interpretation with regional
management
and the
project manager.
The conclusion
drawn was that the licensee's
interpretation
was acceptable
based
on the fact that the
verification of voltage
and frequency within 13 seconds
had been
added to the 18 month surveillance test
and continued
use of the
interpretation
would not be required.
Contaminants
in Air 8 Nitro en
S stems
On November 4, 1988, the licensee
issued
a nonconformance
report,
DCO 88-TI-N125 on contaminants
found in the Nitrogen system.
The contaminants
consisted of rust and scale particles.
The
nonconformance
was generated
as
a result of a maintenance
review of
maintenance
events.
Reviewed events
included (1) an August 1, 1985,
Boric Acid Evaporator overpressurization
(and rupture disk blowout)
caused
by contamination
on nitrogen supply valve seats
which in turn
caused
in-leakage
and (2) an August 1988 nitrogen pressure
control
valve acting erratically in supplying nitrogen to the
The licensee
determined
the root causes
to be oxidation during
construction
and
a design deficiency in that critical components
should contain filters.
The licensee
actions defined in the
NCR were to issue
design
changes
for the installation of filters in the boric acid evaporator
nitrogen supply, to develop
and perform a system
blowdown, to
inspect
and clean nitrogen system
components,
and to define and
initiate design action for the installation of additional filters.
The licensee
actions
are primarily in the planning stage.
A similar nonconformance
(NCR) DCO-88-OP
N116 was written on October
17,
1988,
on grit, rust,
and scale in the Instrument Air system.
The
NCR was written as
a result of finding contamination
in
instrument air piping on October 12,
1988, during modification of
the main steam isolation valve air system.
The licensee
defined
actions to prepare
a procedure to clean the system
by air blow,
inspect
a sample of air instruments,
and to analyze the contaminants
found.
At the
end of the report period,
the licensee
had not yet
determined
long term corrective action.
The licensee
I8C manager
stated that immediate operability concerns
were allayed
by the operating
experience
to date which has
successfully identified fai ling components
thr ough inservice checks.
The I8C manager stated that the identification of the problem and
the orderly performance of corrective actions
were appropriate to
the circumstances.
The inspector will follow-up the licensee's
actions through the
nonconformance
review process.
Lubricatin
Oil
S ill
On November
6, 1988, during the Unit 2 main turbine bearing oil
flush after turbine disassembly
and maintenance,
approximately
300
gallons of lubricating oil was spilled in the turbine building.
The
area affected
by the oil included the 140 foot deck with spillage
down to the 85 foot level.
The spill was caused
when
a oil return
hose
loosened
and sprayed
oil.
The condition was immediately noted
and engineers
stopped
the
flush.
The licensee
conducted
a cleanup
under the direction of an
engineer.
In addition
gA personnel
performed
an audit of the
adequacy
of the clean
up effort.
The licensee
defined the cause of the spill to be not having the
return
hose properly tied off and
a procedural failure to limit the
operating pressure
of the flush system.
The licensee
maintenance
manager
stated that an Action Request
(AR) and guality Evaluation
(gE) were prepared
to document
and track corrective actions
specifically to more securely fasten the oil hose
and to limit
system pressure.
The licensee's
recovery from this event appeared
to be largely
,verbally directed except for some specific tasks
such
as exciter
cleaning.
The inspectors
did not devote additional time to this
item since the areas
affected were not safety related.
g.
Im ro er Wire Lu s on Batter
Char ers
On November 7, 1988, the licensee
discovered
improperly sized lugs
crimped to various wires
on a safety related Unit 2 battery charger
232.
Subsequent
examinations identified the
same conditions
on
battery chargers
231, 221,
and 222.
The licensee
prepared
a nonconformance
report (DC2-88-EH-N130)
on
November
15,
1988.
Discussions
with the assistant
plant manager
for maintenance
indicated the following:
o
The improperly sized lugs were not obvious because
the involved
wire has
a thick insulation.
o
Some wires could physically be pulled out of their crimped
lugs, putting their seismic qualification in question.
o 'he condition was caused
during manufacture
by the vendor.
o
Unit 1 was checked
and found to be satisfactory.
o
Unit 2 battery chargers
have
been corrected.
o
The Unit 2 battery chargers
had functioned successfully
since
startup.
o
The licensee
had not yet determined reportability under
10 CFR 50.73 or Part
21 but would do so as part of the nonconformance
process.
The inspectors will follow-up this item through the nonconformance
process
and through the licensee
report if determined to be
reportable.
I
h.
Hissed
uadrant
Power Tilt Ratio Surveillance
Following a periodic incore/excore
nuclear instrumentation
(NI)
cross calibration,
the power
range
channels
were,
one at a time,
removed from service for adjustment.
From the time the first power
range
channel
was adjusted
on November
8, 1988, until the last
channel
was completed
on November 10,
1988, the
gPTR alarm was lit.
The shift foreman
had originally determined that the
gPTR alarm
10
annunciated
because
the adjustment
made to N-41 gave
a false
indication of quadrant
power tilt and that the alarm would clear
when all four channels
were adjusted.
Although his assumption
was
correct,
the
SFM did riot make the determination that the
gPTR alarm
was inoperable until the alarm was discussed
with the operations
manager
and operations
supervisor
on November 10.
It was then
determined that once the individual adjustment of the NI's began,
the
gPTR alarm was inoperable
since it could not perform its
intended function had an actual
quadrant
power tilt occurred.
The license initiated a nonconformance
report and will issue
a
Licensee
Event Report
(LER 1-88-27).
The licensee
determined the
root cause to be personnel
error in that the annunciator
response
manual
was not used
when the
gPTR alarm annunciated (it requires
a
quadrant
power tilt calculation or a flux map)
and that the
appropriate
determination of inoperability was not made.
The
licensee
considers that contributory causes
included inadequate
training on the
gPTR alarm and less
than adequate
procedures;
specifically that the excore recalibration procedure
should specify
that its performance
renders
the
gPTR alarm inoperable.
The inspector will review the licensee's
corrective actions in
conjunction with the review of the
LER to be submitted.
Unit 2 Safet
In 'ection
Pum
Failure
On November ll, 1988, at 12:50 a.m., operations
discovered that the
suction valve for Safety Injection (SI)
Pump 2-2 had been isolated
since 10:30 p. m. that night.
This resulted in the failure of the
pump due to a sheared
pump shaft.
The Unit was in Mode
5 and
operability of the safety injection pumps
was not required.
SI pump 2-2 had been placed inservice at 9:09 p.m. to fill three
in accordance
with Operating
Procedure
OP B-3B: I.
At
that time,
pump suction valve 8923B was open with power removed
and
on
a clearance.
At 10:30 p.m., the clearance
was reported off for
test
(ROFTed).
Since the control
room pump position switch was in
the closed position,
when power was returned to the valve it closed.
This eliminated suction to the running SI pump.
The subsequent
heating
caused
the impeller to expand in its housing,
deform,
and
finally shear its shaft at the third element
from the inboard seal.
The motor continued to turn this portion of the shaft until the
pump
was stopped at 12:50 a.m..
The licensee initiated an Event Response
Plan which evaluated
the
cause,
reviewed the damage,
and initiated repair efforts. It was
determined that although the
pump casing
was reusable, it required
machining at the inboard seal prior to use.
As a result,
a new pump
was procured
from another plant and installed.
It was determined
that the motor did not experience
excessive
wear or heat
and could
be reused.
Testing confirmed that the overcurrent trip relays were
functioning properly, indicating that the motor did not experience
an overcurrent condition.
11
The licensee
also reviewed control
room annunciation indications
and
found that
no annunciators
"came in", and on further review of
annunciator location and design that none were expected.
Calibration checks
indicated that all inputs (motor bearing
temperatures,
stator temperature,
and seal
water temperature)
were
functioning as designed.
At the close of the inspection period,
the licensee
was reviewing the adequacy of annunciation
for the
pump.
One proposed solution was the use of a low current alarm,
which would serve the purpose of a low suction pressure
alarm and be
relatively simple to install given existing wiring.
The Technical
Review Group
(TRG) reviewing the nonconformance
report
determined
the following root causes
to the event:
o
The clearance
procedure
did not require adequate
review of the
return to service of a clearance
point with its affected
system
in operation.
o
The senior control operator failed to recognize that the
control board valve positioner
was in the closed position and
what impact it would have
on system operation
when
he removed
the clearance
tag from the valve positioner.
o
Operations
personnel
failed to adequately
monitor the
accumulator fill evolution in that it took over 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to
recognize
the status
of the system.
The
TRG identified the following corrective actions:
o
Revisions to the clearance
procedure.
o
Addition of a low SI pump motor current alarm.
o
Counseling of the operators.
o
Generic instructions
on filling tanks.
The inspectors will follow-up licensee
actions
through the
nonconformance
report and the voluntary
LER (2-88-16).
Diesel Generator
1-3 Failed to Start
On November 12, 1988, Diesel Generator
1-3 failed to start during
testing.
The test
was
a specific test of the second level
undervoltage
relays,
the first level undervoltage
relays were
jumpered out for the test.
A licensee electrician determined the cause to be dirty contacts
on
second
level undervoltage
relay 27
HG B4.
The contacts
were cleaned
and the test
was reperformed satisfactorily.
Licensee
records
show
that the relay had been
removed
on September
21, 1988, for periodic
calibration.
The procedure
used required contact cleaning
and an
continuity check at that time.
0
12
The licensee's
Nonconformance
Report
NCR DC2-88-TN-N132 was in draft
at the close of the inspection report.
The licensee
had not
resolved
the reason for dirty contacts
occurring
on November 12,
1988.
Further,
the licensee is preparing
a special
report required
by
technical specifications
to report all valid and non-valid failures
to start.
The residents will follow-up the licensee's
action
through review of the nonconformance
and special
report process.
Boron In'ection Tank Relief Valve Heat Tracin
On November 18,
1988, during a routine walkdown, the system engineer
for the chemical
and volume control
system
observed that thermal
insulation over heat tracing
on the Unit 1 Boron Injection Tank
(BIT) relief valve (RV) was not properly restored following
maintenance.
Additionally, the heat tracing
had been lifted away
from the valve approximately 4" to 6" to facilitate
RV maintenance
performed during the Unit 1 refueling outage earlier this year.
Temperature
measurements
of the relief valve subsequent
to the
discovery found the temperature
to be 130 degrees
F,
15 degrees
F
less
than the Technical Specification (TS) 5.4.2 required
145
degrees
F (which maintains
boron in solution).
It was determined
by the Onsite Project Engineering
Group
(OPEG)
that 130 degrees
would not have precipitated
enough
boron to have
prevented
the relief valve from lifting at its designed
pressure.
The licensee
also determined that the heat tracing'TS 3.5.4.2 did
not apply to the
RV since it is not a part of the BIT flow path
piping.
The root cause
was determined to be
a failure to provide separate
instructions for the removal
and reinstallation of heat tracing and
insulation during the Unit 1 outage in conjunction with other work.
The licensee
revised its practices prior to the Unit 2 outage
and
supplied separate
work orders for the installation
and removal of
heat tracing and insulation
and for the work performed
on
components.
Inadvertent Start of Auxiliar
Pum
s
On November 21, 1988, the licensee
made
a 4-hour non-emergency
report
due to the inadvertent start of Unit 2 auxiliary feedwater
system
pumps.
The pumps started
due to a start signal
from the newly installed
AMSAC system (Accident Mitigation System Actuation Circuitry) during
testing of the newly installed system.
Testing of the system
had
been ongoing since October 30, 1988, but had not caused
actuation
since the auxiliary feedwater
(AFW) had been de-energized
for other
refueling outage
reasons.
When operations
personnel
made the
system available
on November
21, testing then induced
a start of the
now energized
equipment.
The plant computer
(P-250)
had
been taken
out of service for modifications about one-half
hour prior to the
13
pump start.
The
AFW was
made available
and started
but was not
noted
by operators
for about another one-half hour until the P-250
was restored
and the alarm typewriter started printing an alarm.
In discussion with the
I8C manager
and the plant operations
manager,
the following was established:
o
The
AFW pumps were .lined up on recirculation to the condensate
storage
tank, therefore
no damage
was incurred.
o
The motor driven pumps started.
The steam driven pump had its
steam admission valve open it did not start
due to the absence
of steam in Mode 5.
o 'he
blowdown did not isolate.
This feature
was
part of the intended design.
Subsequent
examination
showed the
wiring design to be in error.
Although this was subsequently
corrected, it pointed out a separate
problem according to the
I8C manager.
Specifically the problem was that test
requirements
were not specified
by PG8E design engineers.
The
test requirements
are, deduced
by test engineers
at the site
based
on the modification drawing logic.
The I8C manager
further stated that in this case
the drawing circuitry as
described
in modification drawings did not describe
a logic
where
blowdown would be isolated.
Therefore,
test engineers
did not specify it as
a feature to be tested.
The licensee's
response
to the maintenance
team inspection
indicated that, in the future, test requirements
would be
specified
by design engineers
and that details of the test
methods
would be invoked by plant staff personnel.
The inspectors will follow-up licensee
actions through the
nonconformance
and event report process.
Residual
Heat
Removal
Water
Hammer
On November 23,
1988,
a water
hammer
was noted in the control
room
concurrent with the start of an Residual
Heat Removal
Pump in Unit 1
dur ing a routine surveillance test.
Operators
performed
a walkdown
and noted
no damage.
Subsequently,
walkdowns were performed
by
engineering
and again
no damage
was noted.
Engineering personnel
conducted
a series of pump starts with several
personnel
stationed at various points along the
RHR system.
The
engineers
noted decreasing
energy in the water
hammer effect with
subsequent
pump starts
and noted the location of the loudest noise
to be near
the suction check valve to the Refueling Water Storage
Tank (RWST).
The licensee
engineers
developed
two theories
regarding the cause of
the water
hammer,
one involving entrapped air in long horizontal
runs
and
one involving temporary opening of the
RWST check valve on
starts
due to suction
dynamic action.
The licensee
engineers
have
referred the matter for further study by a general office group
referred to as the water
hammer task force.
The licensee
engineers
do not consider the energy demonstrated
to be
an operational
concern
based
on engineering
judgement.
A second
similar water
hammer event occurred
on December 1, 1988,
as noted in
paragraph 4.s..
The inspectors will follow-up this as
an open item, since the
licensee
does not consider the item to be a nonconformance
(Follow-up Item 50-275/88-31-01).
Containment Ventilation Isolation
Event in Unit 2
On November 12,
1988, the licensee
made
a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
non-emergency
report to the
NRC due to a containment ventilation isolation (CVI)
event in Unit 2.
The event occurred during planned calibration of plant ventilation
radiation monitor
2 RM-14B.
The procedure calls for lifting leads
to prevent
a CVI.
The cause of the event was determined to be that
the lifted leads
were lifted and taped
away in a manner which
allowed the lead terminal
lugs to come into contact
and complete
a
CVI signal
when, later in the procedure,
fuses
were pulled.
The inspectors will follow-Up the licensee's
corrective action
through the event report to be issued.
Unit 2 Low Tem erature
Over ressure
Protection
S stem Actuation
On November 25, 1988, while in Mode 5, Unit 2 experienced
four low
temperature
overpressure
protection
(LTOP) system actuations.
The
first actuation occurred at 6:20 a.m. following filling and venting
the
RCS while operators
were attempting to pressurize
to 390 psig to
run the reactor coolant pumps.
The lift involved pressurizer
power
operated relief valve PCV-456, which at low temperatures
is set to
liftat 435 psig hot leg pressure.
The other three lifts occurred
within the span of four minutes while operations
brought the
RCS to
400 psig to perform
RCS leakage
inspections.
As a result of these
actuations,
the licensee
is required
by technical specifications to
submit
a special
report.
The hot leg pressure
transmitters
are 0-3000 psig instruments
accurate
to 3X or 30 psig;
and although the controls for PCV-456 and
the control
room instruments
are fed from one transmitter,
PT 403,
the process
loops are separate.
In this case,
the instrumentation
in the control
room read approximately
25 psig lower than the
controls for PCV-456 were sensing.
As a result,
operators
were
operating
much closer to the liftpoint. than perceived.
In
addition,
a contributing cause to the first lift, as determined
by
the operations
manager,
was operator inattention.
A contributing
cause in the second set of lifts, as determined
by the operations
manager,
was lack of procedural
guidance
on the
use of the seven
means of control
room indication supplied by two pressure
15
transmitters.
The inspector will follow the determination of
corrective action in follow-up of the special
report to be
submitted.
Unit 2 Containment Ventilation Isolations
On November 26,
1988, Unit 2 experienced
two containment ventilation
isolations
(CVIs).
The first CVI occurred
when radiation monitor
2-RM-148 spiked high.
The cause
was determined to be
a detector
tube failure.
The second
CVI occurred during removal of the failed
detector
from service for repair.
Since the original CVI signal
had
been reset
and ventilation was in normal
mode the act of lifting
leads to remove the failed high radiation monitor caused
the
electrical contact to be broken and then
made
up again (during the
physical act of lifting a round termination lug off the termination
post).
The recontact provided
a second "spike" to the logic circuit
causing the
CVI actuation.
The inspectors will follow-up licensee
actions
through the
LER
process.
Unit 1 Containment Air Particulate
Monitor
RM-12
Ino erable
On November
26,
1988, instrumentation
and controls (I8C) technicians
discovered
the sample
supply isolation valve for RM-12 closed.
It
was determined
by the licensee that it had been closed
on or
sometime
since October ll, 1988,
when
IBC had last performed routine
testing.
Either
RM-12 or the containment
fan cooler condensate
monitoring system are required to be operable
as part of the reactor
coolant system
(RCS) leakage detection
system (Technical Specification 3.4.6. 1).
The condensate
monitoring system
was not
put in service during this time frame and was therefore not used to
detect
RCS leakage.
The licensee's
determination of root cause
and corrective action
will be followed up by the inspector in response
to the
LER to be
issued
on this subject.
Electrical Transient Resultin
in En ineerin
Safet
Features
Actuations
On November 28, 1988, at 8:08 p.m.,
when, Unit 2 was in Mode 4 (Hot
Shutdown)
a temporary loss of power to vital instrument
distribution panel
PY-22 resulted in the actuation of several
Engineered
Safety Features
(ESF)
as well as several
other
actuations.
Actuations included CVI, fuel handling building
ventilation mode shift, pressurizer
heater trip, steam
dump closure,
and letdown isolation.
At the end of the report period, the cause of the electrical
was still under investigation.
The inspector will
follow-up the event through review of the
LER to be submitted
on the
event.
16
s.
Second
RHR Water
Hammer
On December
1, 1988, Unit 1 experienced
a second
RHR water
hammer
when the
RHR pump was started for surveillance testing.
Paragraph
4.m.
regarding the
RHR water
hammer event of November 23, 1988,
provides further discussion.
5.
Maintenance
62703
The inspectors
observed portions of, and reviewed records
on, selected
maintenance activities to assure
compliance with approved procedures,
technical specifications,
and appropriate
industry codes
and standards.
Furthermore,
the inspectors verified maintenance activities were
performed by qualified personnel,
in accordance
with fire protection
and
housekeeping
controls,
and replacement
parts were appropriately
cer tified.
a.
Residual
Heat
Removal
Pum
2-2
As described
in the previous section,
on November 3, 1988, the lower
bearing
on
RHR pump 2-2 failed shortly after an attempt
was
made to
start the
pump.
Details of the initial failure and subsequent
problems
are contained in section 4.
The inspector
observed
the
following maintenance activities
on the pump; portions of the
as-found inspection, as-left shaft runout measurements,
and portions
of the motor reassembly.
The activities observed
were found to be
performed in accordance
with appropriate
procedures.
It was noted
that the activity was observed
by quality control inspectors
and the
maintenance
department
manager.
b.
Unit 1 Centrifu al Char in
Pum
1-2 Lube Oil Leak
On November 17,
1988, during a routine walkdown, the inspector
noted
that centrifugal charging
pump 1-2 (CCpp 1-2), which was in
operation,
had
a significant amount of lube oil under
and around the
pump.
No specific leak point was apparent,
although it appeared
to
come from the area of the
pump outboard bearing.
The condition was
noted to the Unit 1 shift foreman
and the maintenance
manager.
S stem - A Brief Descri tion of 0 eration
In order to understand
the issues
in this section of the report
a
brief description of the operation of the charging
pump bearings
lubrication oil system is necessary.
Specifically, two pumps take
suction from the lube oil (LO) reservoir;
the
CCpp shaft driven
"main"
LO pump and
a motor driven "Auxiliary" LO pump.
The two
pumps supply
a header
which supplies
system flow and bypass
flow.
Bypass flow is controlled by a relief valve which is designed to
maintain system pressure
between
10 and
12 psi.
Main flow goes
through the lube oil cooler (cooled
by component cooling water),
through
a filter and to a header.
The header
supplies the inboard
and outboard
pump bearings,
pressure
instrumentation
and controls.
The pressure
instrumentation
and controls include
a local indicator,
a low lube oil pressure
a lube oil pressure
CCpp start
permissive,
and start
and stop pressures
for the Auxiliary LO pump.
The system is designed
such that on a control
room start,
the
Auxiliary LO pump starts
and raises
lube oil pressure
from
essentially
zero psig.
The lube oil pressure
permissive
(PS
295/296) allows the
CCpp to start
when pressure
reaches
the setpoint
of about
9 psig.
The Auxiliary LO pump and the Main
LO pump build
up system pressure
to a setpoint which turns off the Auxiliary pump
(PS 293/294).
System pressure
should then reach
an equilibrium
based
on the setting of the relief valve which acts
as
a pressure
regulating device.
Ins ection:
The inspectors
investigation of the leak revealed
a number of
concerns
described
below:
o
The inspector
reviewed action requests
and determined that
there is long history of charging
pump lube oil system problems
with a number of unresolved
issues.
Starting in March 1983
problem reports chronicle pressure
switch setpoint problems,
oil pressure
outside manufacture
recommendations,
excessive
auxiliary
LO pump cycling and lube oil leaks.
One quality
evaluation
was
open at the time of inspection.
It was opened
on November 16,
1986,
and identifies problems
on
CCpp 1-2 and
CCpp 2-2 such
as excessive
clearances,
leaking valves,
quality and instrument setpoints.
Responsibility
and due dates
on the
gE had changed
and when reviewed by the inspector the
target date
was September
1989.
This appeared
to be
an example
of a lack of timely corrective action
and
a lack of clear
problem ownership which was identified to the licensee at the
management
SALP meeting held in Walnut Creek, California,
on
October 26,
1988.
o
Instrumentation
and Relief Valve setpoints
were inadequately
controlled.
The
pump manual
requires that pressure
to the
pump
bearings
be maintained
between
10 and 12 psig.
The system
engineer,
following questions
from the inspector,
found that
the relief valve, which acts
as
a lube oil system pressure
regulator
was set to 19 and 20 psig, respectively for the two
charging
pumps,
by the periodic maintenance
procedure.
As a
result,
system pressure
has not been controlled by the relief
valve since with the valve fully closed
main
LO pump discharge
pressure
is between
12 and
17 psig.
In addition, the Unit 1
and
2 CCpp start permissive setpoints
were different and
documentation
did not definitely established
what the
appropriate settings for the permissive were.
As a result,
the
LO system
has operated consistently outside the
recommended
10
to 12 psig band.
o
The leak on
CCpp 1-2 had received little attention since the
leak was identified by the licensee.
The leak was identified
on August 23, 1988,
on an Action Request.
The inspector
brought the matter to the maintenance
managers
attention
on
18
November 18,
1988.
At that time,
no actions'o
analyze or
correct the situation
had been performed.
The amount of oil added to pumps
and motors is not trended.
An
informal log at the auxiliary building auxiliary operator
panel
was
used to track how much total oil was put into various
pumps.
However, the log did not specify exactly where the oil
went (e.g.
the log indicated that
3 gallons of oil had been
added to the
CCpp on October 25, 1988, did not specify where it
was added;
the pump, the speed increaser,
or the motor).
In
addition, through interviews with the auxiliary operators
(AOs)
it was determined that not all
AOs were aware of the log.
These
concerns
were discussed
with the assistant
plant manager for
maintenance
on November 29,
1988.
As a result of these discussions
a system engineer
was given the task of establishing
what problems
existed
and what corrective actions
were necessary.
In addition,
the work planning manager stated that
a procedure in draft would be
revised to include actions to be taken following the discovery of'n
oil leak similar to the actions
being specified in the draft for a
boron leak.
These actions
include
a timely engineering
walkdown and
evaluation.
Finally, the plant manager
committed in the exit
meeting to consider
implementing
pump and motor oil consumption
trending.
The inspectors will follow-up the licensee's
actions in
the course of future inspections.
No violations or deviations
were identified.
6.
Surveillance
61726
By direct observation
and record review of selected
surveillance testing,
the inspectors
assured
compliance with TS requirements
and plant
procedures.
The inspectors verified that test equipment
was calibrated,
and acceptance
criteria were met or appropriately dispositioned.
a ~
Auxiliar Saltwater
Pum
2-2 Baseline
Performance
Test
On October 28, l988, the inspector
observed portions of the
performance of the Auxiliary Saltwater
Pump 2-2 baseline
performance
test
(STP P-7A).
The test
was performed to determine
a new pump
curve for the
ASW pump following impeller replacement.
Except for
the one discrepancy
discussed
below, the test
was performed in
accordance
with the procedure.
The procedure
requires
the reading of an annubar flow gauge to
determine flow with varied heat exchanger outlet valve position
(steps
8, ll to 8. 15).
The inspector, observed that the annubar
was
fluctuating erratically + 5X of full scale.
The test engineer,
after attempting to throttle the gauge isolation valves to minimize
the oscillation, observed
the gauge for between
30 and
60 seconds
to
visually determine
a mean flow value.
This reading
was not obtained
in accordance
with procedure
AP C-353, "Administrative Procedure
Dealing With Gauge Oscillations During the Performance
of ASME
Section
NI Required Tests",
issued
September
23,
1988.
The
0
19
procedure
requires that if a gauge is oscillating irregularly
greater
than
2X of the midpoint reading but not exceeding 10'f
range,
to "..take
5 spot readings at 10 second intervals,
sum
the
5 readings
and divide the
sum by 5 to obtain
an average
reading."
In addition, the procedure
also requires that
an action
request
should
be written which was not done.
The failure of the
test engineer to follow procedure is an apparent violation (Item
50-323/88-29-01).
The above incident was preceded
by a history of enforcement actions
dealing with improper test instrument reading.
A similar instance
was observed
by an inspector
on February 10,
1988 when fluctuations
of flow of greater
than that allowed in the procedure
were observed
when testing
a Containment
Spray
pump 1-1.
-This resulted in a
notice of violation (Inspection Report 50-275/88-04) for failure to
=
obtain test reference
values within tolerances
specified in ASME XI.
In response
to the notice of violation, the licensee
committed to
write an an administrative procedure for reading
and interpreting
test instruments
by July 1, 1988.
An inspection in September
found
that the licensee
had not implemented this commitment.
This
resulted in a notice of deviation (Inspection Report 50-275/88-25)..
Procedure
AP C-3S3, which implemented the licensee's
original
commitment
was issued shortly after the inspection
(Open Item
50-275/88-25-01,
closed).
The inspector discussed
the system engineer's
failure to follow the
procedure with the assistant
plant manager for technical
services.
Three issues
were discussed.
First, from interviewing the system
engineer,
the inspector determined that he had been
unaware of the
issuance
of procedure
AP C-3S3
and that a determination of why he
had been
unaware
and corrective actions to prevent recurrence
was
needed.
Second,
the inspector
requested
the licensee
provide the
technical
basis for the sampling method
used in procedure
AP C-3S3.
Finally, the inspector
expressed
concern that the issue of gauge
reading
had been handled slowly and was another
example of untimely
resolution of identified problems discussed
in the
SALP report.
Following the discussion
a nonconformance
report was initiated.
The technical
review group
(TRG), which convened to review the
nonconformance
report determined that the engineer
had not been
informed nor trained on
AP C-3S3, although it was his
own supervisor
who had written the procedure.
Further, the
TRG determined that no
formal mechanism existed to notify and train plant engineering
personnel
of new and revised administrative procedures.
Corrective
actions identified by the
TRG included establishing
a formal program
to accomplish training in new and revised procedures
for plant
engineering
and to assess
the
need for such
a program in other
departments.
The inspector will review these corrective actions in
follow-up of the notice of violation enclosed in this report.
At the end of the report period, the licensee
had not provided the
inspector with a basis for the averaging
technique
described
in AP
C3S3.
This was discussed
in the exit meeting
and the plant manager
20
committed to include the basis in their response
to the notice of
violation enclosed
in this report.
b.
Continuit
Testin
of Feedwater Isolation Slave
Rela
On December
2, 1988, the inspector
observed
the testing of the train
"A" solid state protection
system
(SSPS)
feedwater isolation slave
relay (K601A) for Unit 1.
Three attempts
were required to actuate
K601A (which, is normally closed
and opens
on an actuation signal).
During the first two attempts,
the relay failed to open.
These
first two attempts
were performed by the senior control operator
and
an auxiliary control operator.
The third attempt
was witnessed
by
the shift foreman
and supervising
instrumentation
and controls (I&C)
technician.
To test slave relay K601A, test switch S801A is taken from "normal"
to "push-to-test."
This actuates
test relay K801A which provides
a
bypass circuit which ensures
that the feedwater isolation valves
remain
open
when
K601A is tested.
In addition,
K801A provides
a
permissive
which allows S801A,
when depressed,
to actuate
K601A. It
was determined
by the
I&C technician that the set of contacts
which
provide this permissive did not make
up.
The determination
was
based
on indirect evidence
as
opposed to direct observation of the
contacts
or evidence
which ruled out failure of the slave relay.
The evidence
included:
o
K801A made
a buzzing all three times which, per the
technician,
indicates that the relay had not rotated completely
when it actuated.
o
Visual observation
by the
I&C technician
on the third attempt
that
K801A had not rotated completely.
o
The slave relay
K601A did not actuate at all the first two
tries
and rotated fully the third try indicating it had not
received
any power on the first two attempts.
o
A history of test relay problems
and
no history of slave relay
problems.
The inspector discussed
the test with the
I&C manager
and concurred
that the licensee
determinations
appeared
to be appropriate.
One violation was identified as noted above in paragraph
6. a..
8.
Radiolo ical Protection
71707
The inspectors periodically observed radiological protection practices
to
determine whether the licensee's
program was being implemented in
conformance with facility policies
and procedures
and in compliance with
regulatory requirements.
The inspectors verified that health physics
supervisors
and professionals
conducted
frequent plant tours to observe
activities in progress
and were generally
aware of significant plant
activities, particularly those related to radiological conditions and/or
21
challenges.
ALARA consideration
was found to be an integral part of each
RWP (Radiation
Work Permit).
Removal of Scaffoldin
From Unit 2 Containment
The inspector
observed
health physics
(HP) practices
in the removal
of scaffolding from the Unit 2 containment while the Unit was in Mode
5
on November 6, 1988,
between approximately 9:30 p.m.
and midnight.
Scaffolding was delivered to the containment
equipment
hatch at the
140'evel
from the 115'evel
by PG8E General
Construction
(GC) personnel.
The scaffolding and clamps were then wiped down by the
GC personnel.
The
wipes were then frisked by
HP personnel
monitoring the evolution.
The
scaffolding and clamps
were then passed
out the containment
equipment
hatch,
over
a walkway of herculite,
which had been laid down prior to
opening the hatch; to a holding area.
The equipment
remained controlled
inside
a surface contamination
area
and did not pass
from one level of
contamination control to another.
The inspector
interviewed
one of two HP technicians
monitoring the work.
The
HP technician stated that all wipes were being frisked to determine
the relative contamination of the scaffolding.
The technicians
acceptance
criteria was 10,000
dpm.
The technician stated that
no
contamination greater
than the acceptance
criteria.
The technician also
indicated that the intent was not to decontaminate
scaffolding but to
identify scaffolding with relatively high contamination.
The inspector
discussed
the work with the radiation protection
foreman for containment.
His understanding
of the process
concurred with that of the technician.
In addition,
he stated that the scaffolding would be bagged
and frisked
before being taken outside the Radiological Controls Area for storage
as
radioactive material.
He noted that this was the practice
used in three
previous
outages.
The
RP foreman stated that scaffolding taken
from a
hot particle zone
(HPZ) received inspection
and either decontamination
or
bagging prior to removal
from the
HPZ.
He noted that to his knowledge
no
scaffolding was at that time being removed from an
HPZ.
The inspector also interviewed the security guard
who was present
when
the equipment
hatch
was opened.
He stated that the laydown area
and path
to containment
had
been established
prior to opening the hatch.
The inspector discussed
with and observed
GC personnel
transfer
scaffolding from the 115'evel
to the 140'evels
At the time of the
inspection it was observed that no scaffolding was being disassembled
and
that scaffolding being transferred
were parts
staged for removal outside
the bioshield
on the 115'evel.
The i.nspector
found practices of HP and
GC to be acceptable.
Additionally, the following morning, the radiological protection manager
was requested
to independently
assess
whether radiological practices
in
the movement of the scaffolding were proper.
His subsequent
response
after
a survey of radiological
personnel
involved in the job was that
radiological practices
were proper,
The request to the radiological
protection
manager
was
made in response
to the fact that
some workers
involved in the job had expressed
concerns
regarding the adequacy of
controls exercised.
22
No violations or deviations
were identified.
9.
Ph sical Securit
71707
Security activities were observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative procedures
including vehicle and personnel
access
screening,
personnel
badging, site security force manning,
compensatory
measures,
arid protected
and vital area integrity.
Exterior lighting was
checked during backshift inspections.
No violations or deviations
were identified.
10.
Licensee
Event
Re ort Follow-u
92700
aO
Status of LERs
d
The
LERs identified below were also closed out after review and in
selected
cases
follow-up inspections
were performed
by the
inspectors
to verify licensee corrective actions:
Unit 1:
88-14,
88-20
Unit 2:
87-26, 88-04, 88-08, 88-11, 88-12
b.
0 en
Unit 2 Ino erable
Reactor Cavit
Sum
Level Indicator
LER
2"88"13"00
On November 14, 1988, the licensee
issued
LER 2-88-13-00 which
discussed
the Unit 2 inoperable reactor cavity sump level
(RCSL)
indicator.
The level indicator was found to be inoperable during
the recent refueling outage
due to the isolation of it's instrument
air supply.
The
RCSL indicator is part of the technical specification 3.4.6. 1 reactor coolant leakage detection
system which
includes the'ontainment
structure
sump, the containment particulate
and gaseous
radiation monitors
RM-11 and
RM-12, and the Containment
Fan Cooler Collection Monitoring System
(CFCCMS).
The inspector
reviewed the "Analysis of Event" portion of the
LER.
In a review of the operability status of the
CFCCMS and
RM-11 and
RM-12, the submittal stated that "Except during routine testing of
the radiation monitors, all channels
were available to perform their
intended function.
The above two monitoring systems
remained
and would have indicated increased
signs of RCS leakage,
had there
been any."
The inspector
found approximately five
corrective maintenance
work orders
on RM-ll and RH-12, indicating
that the radiation monitors
had been out of service for other than
"routine testing."
In addition,
a review of the inspectors
notes
showed that the radiation monitors
had been inoperable
from
September
28 to October 1, 1987.
The licensee
was requested
at the
exit meeting to provide the out of service times for RM-ll and
RM-12.
23
In addition, the
LER is misleading in that the
CFCCHS was
made
as
a compensatory
action only when
RM-12 was taken out of
service.
The analysis
submitted did not fully discuss
the adequacy
of the remaining leakage
detection
systems.
C.
These questions
were discussed
with the Regulatory Compliance
Supervisor
who committed to submit a revised analysis.
This item is
considered
an unresolved
item (Item 50-323/88-29-02)
pending
resolution of the inspectors
questions.
0 en
Emer enc
Core Coolin
S stem
Not Vented Within
Technical
S ecification
Re uired Limit
LER 2-88-06
The
LER issued July 5, 1988, specified,
as corrective actions,
revision of Administrative Procedure
AP C-3Sl " Surveillance Testing
and Inspection."
The revision was to emphasize
the timely closure
of completed recurring surveillances
so that a new test
can be
scheduled.
At the end of the report period, this revision had not
been
completed
(a period of five months).
At the exit meeting,
the
inspectors
discussed
the ongoing concern with lack of timely
corrective action.
This item will remain open.
(Closed
Inadvertent Autostart-of Diesel Generator
1-3
Due to
Personnel
Error
LER 2-88-12-00
The licensee
submitted
LER 2-88-12-00
on November 8, 1988.
The
LER
discussed
'the inadvertent start of a diesel
generator
when a
maintenance
contractor for the Unit 2 outage tried to obtain power
to test
an auxiliary transformer relay from the startup transformer
and energized its differential relay.
The inspectors
found the root cause
determination corrective actions
to be acceptable.
This was
an example where personnel
did not
recognize that instructions
were not adequate
and did not stop their
activity.
This issue
was the subject of discussion
in the
meeting (Inspection
Report 50-275/88-30).
The inspectors will
continue to monitor the'licensee's
progress
in this area
(LER
50-275/88-12-LO,
Closed).
No violations or deviations
were identified.
ll.
Reactive
Ins ection
a 0
Containment
Tem erature
Tem orar
Instruction 2515/98
CLOSED
In response
to high containment
temperatures
affecting safety
related
components at a number of plants,
a Temporary Instruction
issued
June
20, 1988)
was issued requiring an
inspection of containment
temperatures
and monitoring systems.
The
TI included an attachment that listed eight questions.
The
inspectors
findings for the questions
are included as
an attachment
to this report.
In summary,
the inspector
found that the licensee's
temperature
monitoring was acceptable
to meet design basis
accident
assumptions.
The licensee's
efforts to formalize its procedures
for monitoring
and evaluating
peak temperature
experienced
during
a fuel cycle were
found to be prudent
and will be followed through routine inspection.
Effectiveness
of ualit
Assurance
Ins ections
36700
A review was performed of a limited sample of guality Support
surveillance
inspection.
guality Support (gS), the onsite division
of guality Assurance,
performs periodic surveillances
on all aspects
of plant activities in accordance
with gS procedure
gS-4.
The
inspector
reviewed surveillances
gS 88-0562,
0715,
and 0746.
All
three were walkdowns of containment penetration
manual isolation
sealed
valve checklists.
Although a number of discrepancies
between
the checklist
and
as-found condition were noted in the three surveillances,
none of
the survei llances
adequately
discussed
the cause of the
discrepancies
or invoked adequate
tracking of corrective actions.
S 88-0562
The
gS inspector identified f'ive discrepancies
with the inside
containment isolation valve sealed
valve checklist
OP K-10B1,
including valves in the positions other than specified in the
checklist
and missing seals.
The "Disposition/Conclusion" section
of the surveillance
stated:
I
"These valve positions
are satisfactory for the
mode
we are
currently in, but must be corrected
before entry to Mode 4."
r
An independent verification by the inspector determined that the
plant was in Mode
6 "Core Alterations" at the time of the
gS
inspection.
In this mode
TS require
a level of containment
isolation, although not as stringent
as the
Modes
1 to 4 alignment.
The operations
department
was controlling the
Mode
6 containment
isolation with a clearance
and
OP K-10B1 was "inactive" (essentially
not controlled).
The inspector determined that gS had not verified
that the discrepancies
identified agreed with the containment
clearance
although the resident inspector
independently
made this
verification.
The
gS effort identified seal
valve "discrepancies"
from a list that was not applicable.
S 88-0715
This surveillance
documented five discrepancies
of outside
containment isolation valve checklist
OP K-10B2.
The disposition
stated
"The above
must be corrected before entry to Mode 4."
In an
interview with the
gS inspector,
the inspector
learned that
gS had
handed
the list of discrepancies
to the Unit 2 shift foremen
(SFM)
for action.
In addition,
no action
was taken to formally follow-up
the correction of the discrepancies
and to determine
the cause.
The
inspector
independently
discussed
the
gS list with the
SFM and
25
discovered that the
OP K-1082 valve alignment
was in process.
Four
of the points
had yet to be signed off.
The other
two points
involved end caps
and plugs not installed.
On follow-up, after
discussions
with the resident inspector,
gS determined that the
appropriate
end caps
were installed
and the original
gS finding had
been erroneous.
This is another
example where
gS did not perform a
verification that the applicable controls were, in fact,
functioning.
S 88-0716
This gS inspection resulted
from discussions
the resident inspector
had with the
gS supervisor
as
an effort to formally resolve
discrepancies
identified in the previously discussed
surveillance
gS-88-0715.
The
new report (gS-88-0716)
stated
"Deviations listed
previously have
been corrected with the exception of valve
AIR-S-2-200."
Again, the deviation was not tracked nor did gS
indicate in the surveillance report that the valve had not been
closed
by operations
or that
Op K-10B2 had not been completed
by
operations.
As a result of the findings discussed
above,
the resident
inspector
discussed
weaknesses
identified in the conduct of gS survei llances
with the
gS supervisor.
Specifically, the inspector considers that
if a "deviation" is found by gS, its validity should
be verified,
the cause of the deviation should
be identified,
and formal
corrective action should
be taken.
If these final steps
are not
taken,
then the effectiveness
of the
gS surveillance
program of
identifying quality problems
and initiating lasting corrective
actions is limited.
Mhile it was noted that gS has accomplished
the
above in some of their recent inspections
(such
as the Penetration
63 issue during the Unit 1 second refueling outage
and the Auxiliary
Saltwater impeller issue),
the concept that inspections
should
be
conducted to a meaningful conclusion
appears
to need additional
attention.
As a result of the discussion,
the
gS supervisor initiated a guality
Evaluation
on the issue of gS surveillance follow-up.
The inspector
will evaluate
the adequacy
of the corrective actions in a future
inspection.
12.
Unresolved
Items
Unresolved
items are matters
about which more information is required in
order to ascertain
whether they are acceptable
items,
items of
noncompliance,
or deviations.
An unresolved
item disclosed
during this
inspection is discussed
in Paragraph
10.b. of this report.
On December
12,
1988,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.
C
26
ATTACHMENT TO INSPECTION
REPORTS 50-275/88-31
and 50-323/88-29
INFORMATION FOR TI 2515/98
CONTAINMENT TEMPERATURE SURVEY
1.
2.
3.
Plant
Name:
Diablo Canyon Units 1 5 2
Unit 1
Docket Number:
50-275
Unit 2
Docket Number:
50-323
What are the average
containment
temperatures
during operations
as
recorded
by the licensee?
Note:
We are interested
in the peak operating
temperatures
during the hottest
summer months.
Discussions
with the Operations
Department indicated that Diablo Canyon
normally operates
with containment
temperatures
below 110 degrees.
The
inspector
reviewed containment temperature
history data provided by plant
engineering
which confirms this for the months of April to October 1987
and April to September
1988.
The temperatures
provided were the
technical specification required daily recorded
average of four
containment
temperature
monitors.
The average
containment temperatures
varied for these
summer
months
from between
94 and 103.3 degrees
F.
The
hottest temperature
recorded
was 108.4 degrees
in October
1987 for Unit
l.
Diablo Canyon rarely experiences
high ambient temperature
conditions
due
to the coastal
climate.
During the
summer months,
coastal
fog covers the
site for most of the day,
keeping temperatures
in the 60's
and 70's.
Infrequently, inland winds will warm the coast
as in October 1987.
The
containment is cooled by five containment
fan cooler units
(CFCUs), which
are cooled
by the component cooling water system which is cooled by the
auxiliary salt water system
(ASWS), the ultimate heat sink, which take
suction from the Pacific Ocean.
The ocean
temperature
normally remains
below 64 degrees
F.
The
ASWS and
CFCUs are sized for accident conditions
and at normal temperatures
can easily handle containment
ambient
conditions.
Containment
temperature
at which the plant is licensed to operate (i.e.,
operating
temperature
specified in the
FSAR).
Plant Technical Specification 3.6.1.5 requires that average
containment
temperature
shall not exceed
120 degrees
F in modes
1 through 4. If 120
degrees
F is exceeded
for over eight hours the licensee is required to be
in hot standby in the following six hours
and cold shutdown in the
following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
To ver ify containment
average
temperature
the
licensee
is required to take
an average of four monitors.
The monitors
are located inside the bioshield between the steam generators,
o'utside
the bioshield
on the
same level,
on the refueling deck level,
and on top
of the steam generator
missile barriers
away from the steam generators.
The basis for Technical Specification 3.6. 1.5 is to ensure that the
overall containment
average air temperature
does not exceed the initial
temperature
condition assumed
in the safety analysis for a loss of
coolant accident.
These initial conditions for the
LOCA analysis
are
described
in FSAR Table 6.2-4.
'eview the temperature
readings
and provide your assessment
as to whether
or not you believe the average
temperature
readings
accurately reflect
containment conditions,
or if there is a significant difference,
due to
S
g
~
27
temperature
sensor
location or stratification of containment
atmosphere
which could produce hot spots.
The average
temperature
readings
appear to provide an accurate
containment
average
temperature
in that it is a simple assessment
of what
is the average
temperature
of the containment air volume, providing an
energy input for the
LOCA calculation.
The containment
does
have "hot
spots" which are not accounted for by the average
temperature.
Mhat temperatures
are
used
by the licensee
in its equipment environmental
qualification program when calculating the remaining qualified lifetime
for all equipment inside containment,
and are these
temperatures
consistent with temperatures
experienced?
Post-LOCA environment temperatures
are based
on the initial ambient
average
temperatures
of 120 degrees.
In addition, the equipment life
calculations
are
based
on 120 degrees
at the component.
Currently, the
licensee is establishing
a program of monitoring the peak temperature
experienced
at all environmentally qualified equipment locations inside
containment.
This involves attaching temperature
recording stickers
(which record the highest temperature
to which they are exposed) at the
beginning of a fuel cycle and removing them during the next refueling
outage.
The results
are then forwarded to Engineering for analysis.
At
the time of this report
a final analysis
had not been performed for
either Units 1 of 2.
Preliminary data indicates that
some equipment is
exposed to greater that 120 degrees,
such
as equipment
on top of the
pressurizer.
The solenoid valves,
which operate
the pressurizer
power
operated relief valves,
have
been replaced
and will be examined
by
Engineering.
The inspector will follow-up the results of Engineering's
evaluation of
operational
temperature
data during routine. inspection.
Administrative temperature limit for the containment, if no technical
specification limit exists.
Not Applicable,
see
item 4.
Recent history of temperatures
inside containment.
Provide containment
average air temperature
in addition to the containment air temperatures
to compute the average
containment
temperatures
for the months of April,
May, June, July, August,
and September
1987, if the plant has not
operated
during those
months
use
an operating period close to these
months.
A table was forwarded to
NRR separately
showing the daily containment
average
temperatures,
recorded in accordance
with TS surveillance
requirement 4.6. 1.5, for the months of April to October
1987 for Units
182 and April to October 1988 for Unit 2.
Days where data
was not
recorded
the unit was not in Mode 1 to 4.
Cs