ML16343A266
| ML16343A266 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 11/18/1994 |
| From: | Kirsch D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342C746 | List: |
| References | |
| 50-275-94-24, 50-323-94-24, NUDOCS 9411280044 | |
| Download: ML16343A266 (48) | |
See also: IR 05000275/1994024
Text
APPENDIX B
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-275/94-24
50-323/94-24
Licenses:
DPR-82
Licensee:
Pacific
Gas
and Electric Company
77 Beale Street,
Room
1451
P.O.
Box 770000
San Francisco,
Facility Name:
Diablo Canyon Nuclear
Power Plant,
Units
1
and
2
Inspection At:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
September
1 through October
15,
1994
Inspectors:
M. Tschiltz, Resident
Inspector
D. Corporandy,
Project Inspector
P. Goldberg,
Reactor
Inspector
C. Paulk,
Reactor
Inspector
L. Ellershaw,
Reactor
Inspector
B. McNeill, Reactor
Inspector
R. Pate,
Reactor
Inspector
Approved:
D, Ki sc
,
C ie
,
eactor
Prospects
rane
Ins ection
Summar
Date
Areas
Ins ected
Units
1 and
2
Routine
announced
inspection of onsite
response
to events,
operational
safety verification, plant maintenance,
surveillance
observations,
plant support activities, onsite engineering,
followup maintenance,
and onsite
and in-office review of licensee
event
reports
(LERs).
Results
Units
1
and
2
~0erati one:
Strength:
~
Refueling evolutions
were conducted
in
a precise
manner.
Problems
which
arose during fuel handling evolutions were resolved conservatively,
with
appropriate
regard for safety.
9411280044
941118
PDR'DOCK 05000275
6
Weakness:
~
A less
than
adequate
questioning attitude,
regarding
fDG configuration
and test requirements,
resulted
in attempting to test
EDG 2-1 with a
grounding device installed.
Strength:
~
The licensee's
investigation of MSSV and
PRV setpoint inaccuracies
showed significant effort and resources
had
been dedicated
to resolution
of this issue.
Although no specific solution to the problem
had
been
developed to date,
licensee efforts involved with the evaluation of
relief valve setpoint drift are viewed
as proactive
and thorough.
Maintenance:
Strength:
~
The high level of preplanning
and coordination of work and testing
significantly reduced
the duration of the higher risk evolutions during
the outage.
Weakness:
~
During Refueling Outage
2R6 there
were several
examples of deficiencies
in the method of controlling work and managing
equipment configuration.
Although, singularly, these specific instances
were not of great
significance,
when considered
in total there
was
an apparent
weakness
in
system configuration control.
This resulted
in several
instances
of
premature
authorization of work and testing
and inadequate
clearance
boundaries.
~PP
1
Strength:
~
Radiation
exposure
was significantly reduced
from Refueling Outage
1R6.
Although dose rates
were,
in general,
lower in Unit 2 containment,
as
compared to Unit 1, outage preplanning
and incorporation of lessons
learned
from Refueling Outage
1R6 appeared
to be significant
contributors in the reduction of personnel
exposure.
Summar
of Ins ection Findin s:
~
Violation 275/94-24-01
was identified (Section
2. 1).
~
Noncited Violation 323/94-24-01
was identified (Section 2.2),
1
I
1
F
0
~
Noncited Violation 323/94-24-02
was identified (Section
4. 1).
~
LERs 50-275/93-003,
Revision
1; 275/94-016,
Revision 0; 323/94-002,
Revision 0; 323/94-003,
Revision 0; 323/94-004,
Revision 0;
and 323/94-
005, Revision 0,
were closed
(Section 8).
~
LERs 50-275/94-009,
Revision 0,
and 50-275;323/94-003
were reviewed
and
remain
open pending completion of additional
inspection
(Section 9).
Attachments:
~
Attachment
1 Persons
Contacted
and Exit Heeting
~
Attachment
2 Acronyms
DETAILS
1
PLANT STATUS
(71707)
1.1
Unit
1
Unit
1 operated
at
100 percent
power during the entire inspection period.
1.2
Unit 2
Unit 2 operated
at
100 percent until September
21,
1994,
when the unit power
was reduced to maintain plant temperature
as the core reached
the end of life.
On September
24,
1994, Unit 2 was separated
from the grid and shutdown for
Refueling Outage
2R6.
Unit 2 remained
shut
down for the remainder of the
inspection period.
2
OPERATIONAL SAFETY VERIFICATION
(71707)
2.1
S stem Walkdown
During this inspection period,
the inspectors
performed
a safety
system
verification inspection.
This involved
a detailed inspection of a sample of
the accessible
portions of the instrument alternating current
(AC) system.
The inspectors utilized Operating
Procedure
(OP) J-10: II, "Instrument
System
Alignment Verification," Revision ll, as guidance for the
verification of the system configuration.
The purpose of OP J-10: II is to
verify normal
alignment
and operation of the instrument
AC system.
The inspectors
found two breakers
which were improperly labelled in
Attachment 9. 1 to the procedure.
The first breaker
was labelled
as
"PY-11A
Normal Supply Breaker
11N."
In accordance
with the alignment procedure,
the
breaker
should
have
been labeled
11AN.
The second
breaker
was labeled
as
"PY-
13A Normal Supply Breaker
13N."
In accordance
with the alignment procedure,
the breaker
should
have
been labeled
13AN.
The inspectors
also noted that the
white "power available" indicating light for Panel
PY-11A was not illuminated
as required
by the checklist.
Additionally, the inspectors
observed
that
there
was inconsistency
in the positioning of the spare
breakers
in that
some
were being maintained
in the open position
and others
were closed.
The
inspectors
informed the senior operator
who accompanied
them on
a portion of
the verification of these discrepancies.
During the inspection of the instrument
AC system,
the inspectors
found that
Breaker
11-18 in Panel
PY-11 was
opened without having
an active clearance
request.
This
w'as not in accordance
with Attachment 9. 1 of Procedure
OP J-
10: II, which required all individual load breakers
to be closed
and
any open
breakers
to be tagged
by an active Clearance
Request.
The inspectors
ensured
that the senior operator
was
aware of this discrepancy.
The senior operator
investigated
the required position of Panel
PY-11-18
and determined that the
breaker
should
have
been closed.
Operations
then closed the breaker
and
rt
reperformed
the alignment verification checklist
and found no other anomalies.
The inspectors
also noted that
OP H-5: II, "Control
Room Ventilation System
Alignment Verification," Revision 8, Attachment 9.2,
"Alignment Verification
Checklist," also required
Breaker
PY-11-18 to be closed.
The inspectors
found, in Attachment 9.2 to Procedure
OP H-5: II, that the load was the backup
power supply to the Unit 2 Train A logic and that the breaker
should
have
been
closed.
The inspectors
also found that Section
8. 1 of Procedure
OP H-5: II required
that the completed checklist
be routed to the Shift Technical Advisor,
and
that the completed checklist
be in the control
room file until superseded.
When the inspectors
requested
a copy of the checklist from the Shift Technical
Advisor, the checklist
was not found in the control
room.
Further
investigation
by the licensee
regarding
the completed checklist failed to
identify its location.
The licensee
reperformed
the checklist
and
has filed
it in the control
room.
Additionally, the licensee verified that copies of
other procedures
were being maintained
as required in the control
room.
Safet
Si nificance
Technical Specification (TS) 3.7.5. 1 requires
at least
two separate
trains of the control
room ventilation system
be operable
in all
modes.
Each unit has
a train of control
room ventilation.
Each of the trains
consists of two subtrains
made
up of a supply fan,
a condenser,
a compressor,
a booster fan,
a pressurization
fan
and heater,
and respective
The
subtrains
for each unit share
a
common high efficiency particulate air filter
and charcoal
adsorber
component.
Each of the subtrains
has
both
a normal
and
backup
source of 120 volt instrument
AC.
Breaker
PY-11-18 supplies
the backup
power to Transfer Switch
EJPA, which feeds
the Unit 2 Train
A logic circuits,
Specific loads include:
control
room ventilation intake radiation monitors,
control
room ventilation damper indications,
and nonvital exhaust
Fans
E-35
and
E-36 permissive control circuits.
Normal system operation aligns
one
subtrain
per unit for operation.
The loss of the normal
120 volt instrument
AC power to Unit 2 Train A would result in a radiation monitor failure alarm
on the main annunciator.
If the
120 volt instrument
AC power was aligned to
the backup
power source with the Breaker
PY-11-18 open,
as
was found, the
power would not be restored.
If the problem was not readily apparent,
the
operator could realign to the other unit subtrain
and investigate
in
accordance
with annunciator
response
requirements.
Without 120 volt
instrument
AC, 480 volt equipment
would remain operational
and control
room
ventilation dampers
would fail as-is.
A total loss of a train (i.e., both
unit subtrains)
would result in entry into
a 7-day Action Statement.
If an
event were to have occurred with this alignment,
Emergency Operating
Procedure
(EOP)
E-0 required that operators
check control
room ventilation for
proper alignment following a reactor trip or safety injection and prompts
selection of another
subtrain if the in-service train has failed,
In the
situation where'll control
room heating, ventilation,
and air conditioning is
lost, operators
would have in excess
of
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to reestablish
control
room
ventilation flow without exceeding
control
room temperature limits.
Conclusion
The failure to maintain the breaker closed
as required
by
Procedures
OP H-5: II and
OP J-10: II was
a violation of TS 6.8. 1, which states,
in part, that written procedures
be established,
implemented,
and maintained
covering applicable
procedures
recommended
in Appendix
A of Regulatory
Guide 1.33, Revision
2, dated
February
1978.
Appendix A of Regulatory
Guide 1.33,
Revision 2,
recommends
procedures
covering surveillance testing;
preventive maintenance;
and startup,
operation,
and
shutdown of safety-related
systems.
Contrary to this requirement
implemented
by OPs H-5: II and J-10: II,
on September
22,
1994,
Breaker PY-ll-l8 was noted to be open without having
an
active clearance
request.
This is
a Severity Level
IV violation (275/94-24-01).
2.2
Clearance
of Both Centrifu al
Char in
Pum
s In Mode
4
During the performance of OP L-5, Revision
17, "Plant Cooldown from Minimum
Load to Cold Shutdown,"
both centrifugal charging
(CC)
pumps were cleared
while the plant
was in Mode 4.
applicable to Mode 4, requires that,
as
a minimum,
one emergency
core cooling system
subsystem
which includes at
least
one
CC pump
be operable.
However, while in Mode 4, both
CC pumps were
inoperable for
a period of approximately
67 minutes.
Pump 2-1 was cleared
during the performance of OP L-5, Step 6.2. 17.
Pump 2-2 was cleared
at the
same time in anticipation of the
TS requirement to disable
an additional
charging
pump when in Mode
5 prior to decreasing
below 161.9'F.
The shift
foreman authorized
the clearance
which removed
both
CC pumps from service.
Prior to providing the clearance
tags to the operators,
the shift foreman
recognized that
TS prohibited clearing both
CC pumps in Mode 4, but failed to
communicate this to the operators
and mistakenly authorized
hanging the tags
for both
CC pumps.
Since the hanging of the tags is controlled
by
OP L-5,
there
was not
a related
clearance
request;
therefore,
Attachment 9.5 of OP L-5
was
used to document
the hanging of the tags in accordance
with the proced'ure.
When hanging the tags,
on the control board,
the attachment
specified
clearance
of CC
Pump 2-1 or
Pump 2-2.
Consequently,
the procedure
did not
have
a provision for the operators
to hang tags
on both pumps.
Additionally,
when hanging the tags
on the power supply breaker,
the procedure similarly
specified: clearance
of the breaker for CC
Pump 2-1 or
Pump 2-2 but did not
have
a provision for disabling both.
In each of these situations,
the
operators
hanging the tags
made unauthorized
changes
to the procedure
by
changing the "or" to "and" and adding signature
blocks for the performer
and
independent verification of the tags.
Approximately 67 minutes after the
Pump 2-2 was declared
the shift foreman,
when observing the
control boards,
noted that both
CC pumps
had
been cleared in contrary to the
TS requirement for Mode 4.
The shift foreman immediately restored
Pump 2-2
to service.
i
Safet
Si nificance
The clearing of both
CC pumps
when in Mode
4 resulted
in
the inadvertent 'entry into TS 3.5.3, Action Statement
a.,
which required at
least
one emergency
core cooling system
subsystem
be restored
to operable
status within the next hour or be in Cold Shutdown within the next
20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />.
Since the plant was
shutdown
and in the process
of cooling down to
a cold
shutdown condition,
and since
Pump 2-2 was returned to service after
0-
l 'I
t
0
removing both
CC pumps for period of slightly greater
than
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the safety
significance of this event is minimal.
Conclusion
The inadvertent entry into TS 3.5.3 resulted
from inadequate
consideration of TS requirements
for Hode 4.
The improper authorization of a
clearance for both
CC pumps,
combined with the unauthorized
changes
made to
Attachment 9.5 of OP L-5, resulted
in simultaneously clearing both
CC pumps.
The clearance
of both
CC pumps
was not in accordance
with the requirements
of
Attachment 9.5 of OP L-5,
This is
a violation of TS 6.8. 1., which states,
in
part, that written procedures
be established,
implemented,
and maintained
covering applicable
procedures
recommended
in Appendix A of Regulatory
Guide 1.33,
Revision 2, dated
February
1978.
Appendix A of Regulatory
Guide 1.33,
Revision 2,
recommends
procedures
covering surveillance testing;
preventive maintenance;
and startup,
operation,
and shutdown of safety.-related
systems.
Contrary to this requirement,
on September
24,
1994,
both
CC pumps
were cleared while in Hode 4.
Since the violation is of very low 'safety
significance
and since the inspectors
are satisfied with the
adequacy of the
corrective actions,
in accordance
with Section VII.B.(2) of the Enforcement
Policy, this violation was not cited (323/94-24-01).
3
PLANT HAINTENANCE
(62703)
During the inspection period,
the inspector
observed
and reviewed selected
documentation
associated
with the maintenance
and problem investigation
activities listed below to verify compliance with regulatory requirements,
administrative
and maintenance
procedures,
required quality assurance/quality
control department
involvement, proper
use of safety tags,
proper equipment
alignment
and
use of jumpers,
personnel
qualifications,
and proper retesting.
Specifically, the inspector
witnessed
portions of the following maintenance
activities:
Unit
1
Relief Valve CVCS-1-8116
Replacement
~
Pump 1-2 Gear Oil Cooler Inspection
Unit 2
~
Resistance
Temperature
Detector
(RTD) Bypass Hanifold Elimination
~
Fuel
Bundle Visual Examinations
~
Core Offload and Reload
~
Inverter IY-22 Installation
3. 1
B
ass Manifold Elimination
The inspector
observed
welding being performed
by a licensee
vendor in
conjunction with the
RTD modification on two occasions:
gas tungsten
arc
welding on Joint
FWI-FH207 and shielded
metal
arc welding on Joint FW4-FH207.
The inspector
reviewed
and verified that the weld procedure
specifications
(WPSs)
were properly qualified in accordance
with the
ASHE
Code.
During each of the observations,
the inspector verified that the welder
used
the proper
WPS
and that the heat
numbers of the welding material
in the
welder's
possession
were the
same
as that which were identified and documented
on the welder's
weld rod requisition slip.
During the gas tungsten
arc
welding process,
the inspector verified that the argon
gas flow rate
was set
in accordance
with the
WPS.
Additionally, the inspector
observed
the vendor
quality control inspector
measure
both the interpass
temperature
and the
amperage.
The measured
values
were within the established
limits specified
by
the
WPS.
During observation of the shielded
metal
arc welding on Joint
FW4-FH207, the
inspector
noted that the coated electrodes
(Type E-316L) were properly stored
in heated
electrode
caddies.
This particular weld joint required the initial
passes
to be performed
using the gas tungsten
arc welding process
and the
remaining
passes
to be performed using the shielded
metal
arc welding process.
The gas tungsten
arc welding had
been
completed
and the inspector
observed
the
welder begin the shielded
metal
arc welding.
The welder
had already set the
amperage
and voltage
on the power source.
However, after striking an arc
on
the component
and depositing slightly less
than
a 1/2-inch bead,
the welder
determined that
a higher amperage
was needed.
The welder stopped welding,
reset
the power source to
a higher amperage,
and ground out the weld metal
he
had just deposited.
The inspector questioned
the welder regarding his use of
the actual
component rather than
a "strike" plate to determine if he
had
sufficient amperage.
The welder stated that
he often used
a file or chipping
hammer
as
a "strike" plate,
but since the gas tungsten
arc welding and the
shielded
metal
arc welding
WPSs
had virtually the
same
amperage
parameters
(for the size electrode
being used),
and since the power source
had
been set
up by the previous welder
and verified by
a quality control inspector,
he
concluded it was not necessary.
The welder did obtain
an available
mockup of
the component to verify that his
new amperage
setting
was sufficient prior to
resuming welding on the actual
component.
While it did not appear that the
WPS
had
been violated, the inspector
considered
the
use of an actual
component,
rather than
a "strike" plate, to
determine if sufficient amperage
existed,
to have
been
an example of poor
practice.
The inspector discussed
this observation with licensee
and vendor
management.
It was determined that there
was
no prohibition regarding this
practice,
and eRisting general
welding procedures
did not address
the subject.
In any event,
licensee
and vendor management
personnel
acknowledged
and
understood
the concern.
The vendor quality assurance
site manager
immediately
discussed
this concern with the vendor welders
and conducted
a documented
"tailboard" (training session).
The session
used
a training document that
clearly described
the checking of welding parameters
prior to welding on
production parts or equipment.
The methodology consisted
of welding on
a
stainless
steel test piece to verify proper operation of the welding equipment
and the use of a calibrated
amperage
probe to check
amperage
and voltage prior
to production work.
It was also stressed
that the preset
welding parameters
are to be rechecked
any time welding variables
are
changed
and that these
activities will be monitored to assure
compliance.
Conclusion
The inspector considered
that the licensee's
corrective actions
were sufficient to address
the identified welding technique
concerns.
3.2
Inverter IY-22 Installation
The inspector
observed
selected
cable pulls which were part of Design
Change
Package
(DCP) DC2-E-48283.
Cables
211D,
211N,
G35POOA,
G35POOB,
and
G35POOC
were pulled from Cable Tray
RPAC through Conduits
K458H and
K7661 to
Panel
IY-22.
The inspector verified that the configuration
and mounting
detail
were properly implemented
by the licensee.
Also, the inspector
observed that cable pull techniques
(e.g.,
minimum bend radius,
no nicks,
cuts,
or scratches)
were proper
and that the quality control inspector
completed all required quality control hold point inspections.
Conclusion
The observed
cable pulls for the selected
cables
were
made in
accordance
with the work order.
3.3
Confi uration
Mana ement Durin
Refuelin
Outa
e
2R6
During Refueling Outage
2R6, there
were
a number of problems involving the
control of work.
These
problems
occurred
as
a result of the licensee's
failure to adequately
consider the effects of existing plant conditions
on
changes
in work activity schedules,
the licensee's
haste to accomplish
work,
and inadequate
communications.
3.3. 1
(AFW) Discharge
Check Valve (AFW-2-380) Bonnet
Removal
Work was authorized
on Valve AFW-2-380 which involved disassembly
of the
valve.
Valve AFW-2-380 is not isolable
from Steam Generator
(SG) 2-4.
Containment closure
was in effect at the time the work was being performed,
since core alterations
were in progress.
Work on Valve AFW-2-380 was within
the boundaries
set for containment closure,
since the secondary
side of SG 2-4
was
open to containment
atmosphere.
Valve AFW-2-380 work was originally
scheduled
to commence after the completion of core off-load; however,
changes
in the outage
schedule
resulted
in disassembly
of the valve during core
alterations.
During removal of Valve AFW-2-380, bonnet water was observed
to
be leaking from the body-to-bonnet
connection.
When the mechanic
working on
the valve noted the water,
work on the valve was stopped
and the body-to-
bonnet joint was tightened.
The licensee's
investigation revealed that the
work on Valve AFW-2-380 had improperly occurred during core alterations.
-10-
Safet
Si nificance
Containment
closure
was not violated when Valve AFW-2-380
was partially disassembled
since the feed line was full of water; therefore,
the loosening of the valve bonnet did not provide
a direct path from the
containment
atmosphere
to the outside
atmosphere.
~Summar
Work controls were inadequate
in that they did not prevent work
within the boundaries
established
for containment closure.
Additionally, when
the work on the valve was rescheduled,
inadequate
consideration
was given to
the requirements
for the conditions which were required for the work.
This
problem has
been appropriately
documented
by the licensee
in an Action
Request.
3.3.2
Removal of Hain Steam Safety Valves
(HSSVs)
Following cooldown to Mode 5, the removal of the
HSSVs
was authorized.
The
clearances
issued for the work were administrative
in nature
and required only
that the plant
be in Mode 5.
Although the Shift Foreman,
who authorized
the
clearances,
discussed
the
need to vent the
SGs, prior to removal of the
HSSVs,
with the Mechanical
Maintenance
Foreman,
the
need for venting
was not included
in the turnover to the night-shift Mechanical
Maintenance
Foreman.
Instructions for coordinating with Operations
to verify the
SGs were vented,
prior to HSSV removal,
were only included
on two of the six subclearances.
When the Mechanical
Maintenance
Foreman
reviewed the packages,
the special
instructions
on two of the six subclearances
were not considered.
Residual
heat in the
SGs resulted
in the production of steam,
and removal of the
HSSVs
was
commenced without the
SGs being adequately
vented.
During
a walkdown of
the area,
the licensee
observed that removal of the
HSSVs
had
commenced
without the
SGs being vented
and expressed
this concern to the mechanics.
At
this point mechanics
were cleared
from the area
and the
SGs were vented
by
opening
steam
dumps.
Safet
Si nificance
Mechanical
maintenance
personnel
were authorized to
remove the
HSSVs without adequate
consideration for the steam pressure
in the
SGs.
~Summar
Adequate control of WSSV removal
was not maintained.
WSSV removal
was authorized without ensuring the proper conditions
were established
for the
work.
This problem has
been
documented
by the licensee
in an Action Request
and the licensee
problem resolution
process will follow corrective actions.
3.3.3
Emergency Diesel
Generator
(EDG) 2-1 Testing with Grounding Device
Installed
~Back round
During postmaintenance
testing of EDG 2-1, the
EDG was started
twice with a grounding device installed
on the
EDG output breaker.
Both times
EDG 2-1 tripped
on differential current
across
the output breaker.
The
differential current trip compares
the current flow coming into the
EDG output
breaker
and the current flow going out of,the breaker
and shuts
down the
at approximately
17
amps differential.
The grounding device which was
installed
on the
EDG output breaker provided
a current path to ground at the
4
I~
-11-
breaker.
Following the second
attempt to start the
EDG, it was determined
that the grounding device
was the source of the problem.
The grounding device
was
removed
and
an inspection of the control circuitry was performed.
The
inspection did not reveal
any damage
as
a result of leaving the grounding
device installed during testing.
Safet
Si nificance
EDG 2-1 was not considered
during this testing.
Therefore,
problems
associated
with testing did not adversely affect the
operability of electrical
power sources
required
by plant TS.
~Summar
Although it was
known prior to commencing
EDG 2-1 testing that the
grounding device
was installed in the output breaker,
the effect of the device
remaining installed during testing
was not thoroughly understood
by the
personnel
involved with the testing.
Controls established
to ensure that
EDG 2-1 was ready for testing were inadequate
in that they did not preclude
the performance of testing with the grounding device installed.
The testing
was not properly controlled in that the initial
EDG trip during testing
was
not thoroughly investigated prior to continuing with the testing.
The
licensee
has
documented this problem in a nonconformance
report.
3.3.4
Insufficient Clearance
Established for Installation of Drain Adapter
Work involving the installation of a drain adapter
on the containment 'closed
drain piping system
was not adequately
isolated
from other
connected
systems.
As
a result,
an evolution being performed,
which created
increased
backpressure
in the reactor coolant drain tank,
caused
a radioactive spill
inside containment
from the drain adapter of approximately
100 gallons.
The
licensee's
investigation revealed that, in addition to inadequate
controls
being established
for the work, the system
had
been
breached prior to purging
the volatile gases
in the reactor coolant drain tank.
Safet
Si nificance
Failure to establish
adequate
boundaries for the breach
of a radioactive
system created
the potential for personnel
injury, the spread
of radioactive contamination,
and equipment
damage.
~Summar
The clear ance
used for the installation of the drain adapter
was
inadequate
in that it did not adequately
isolate the portion of the system
being breached for the work and
no other controls were in effect which would
have precluded
other system interactions
from affecting the work area.
Overall Conclusion
The problems described
in Sections
3.3. 1 through 3.3.4 are
of concern to the
NRC because
the contributing causes
include inadequate
communications,
a perceived
need for haste
in accomplishing
outage
work,
and
an inadequate
consideration
of existing plant conditions
on work schedule
changes.
The controls which ensure that proper conditions
are establi,shed
for
work and testing
were not adequate
in these
circumstances
to preclude
foreseeable
problems
from occurring.
None of these specific examples,
when
considered
separately,
resulted
in situations of significant safety concern.
However,
since these
same controls were used during the outage for work on
safety-related
systems,
the
NRC was concerned
about the number of these
-12-
problems which occurred during Refueling Outage
2R6
and their potential for
recurrence
in circumstances
of increased
safety significance.
4
SURVEILLANCE OBSERVATIONS
(61726)
Selected
surveillance tests
required to be performed
by the
TS were reviewed
on
a sampling basis
to verify that:
(1) the surveillance tests
were correctly
included
on the facility schedule;
(2)
a technically adequate
procedure
existed for performance of the surveillance tests;
(3) the surveillance tests
had
been
performed at
a frequency specified in the TS;
and
(4) test results
satisfied
acceptance
criteria or were properly dispositioned.
Specifically, portions of the following surveillances
were observed
by the
inspector during this inspection period:
Unit
1
~
Surveillance
Test Procedure
(STP) I-lA, Revision 47, Routine Shift
Checks
Required
by Licenses
Unit 2
~
STP M-12A21, Revision 2, Station Battery
121 Performance
Test
~
STP 1-72B, Revision
11, Seismic Trip Channel
Calibration
~
STP V-15, Revision 4,
ECCS Flow Balance Test
~
STP P-3A, Revision
12,
Performance
Test of Residual
Heat
Removal
(RHR)
Pumps
4. 1
P-3A
Performance
Test of RHR
Pum
s
The
STP P-3A test provides data for determining
RHR pump performance
under
conditions of pump recirculation to maximum flow.
While observing
the
performance of the test,
the inspector
noted that the licensee
personnel
involved with the surveillance
were recording the
pump recirculation data in
accordance
with Step 12.7.6 with Valve RHR-2-8809B in the
open position.
During the portion of the test where
Pump 2-2 is aligned to run
on
recirculation,
Valve RHR-2-8809B is required to be closed
by Step 12.2.6.
The
inspector questioned
the system engineer
regarding the reason
Valve RHR-2-
8809B was
open since the procedure
required it to be shut.
The system
engineer
reviewed the procedure
and remarked that the valve should
be closed.
The system engineer
then notified the operator performing the test that the
valve should be'losed.
The operator
then repositioned
Valve RHR-2-8809B to
the closed position.
Review of the master
copy of the procedure
being used
for the test indicated that the operator
had,
in error, initialed for
Valve RHR-2-8809B being in the closed position in Step 12.2.6
when, in fact,
the valve was open.
I
-13-
Safet
Si nificance
The impact of Valve RHR-2-8809B being in the incorrect
position was minimal since,
during the portion of the
pump testing which
measured
recirculation flow, an upstream valve,
RHR-2-HCV-637,
was closed.
As
a result,
the recirculation flow of the
pump would not have
been affected
by
the improper positioning of Valve RHR-2-8809B,
assuming that Valve RHR-2-HCV-
637 did not have significant leakage.
Following completion of the
recirculation flow measurements,
the surveill,ance
procedure
Step
12.9 directs
the opening of RHR-2-8809B.
Therefore, if the licensee
had not identified
that Valve RHR-8809B was in the incorrect position prior to that point in the
procedure,
the improper positioning would have
been self-revealing during the
performance of Step
12.9 and,
as
a result,
would not have
impacted the
remainder of the test.
The licensee
issued
a bulletin to the test
team
and
the operations
department
to correct the cause of the problem.
The bulletin
described
the preferred
methods of self-verification during the performance of
surveillances.
Conclusion
The requirements
of STP
P-3A were not met for the performance
of
Pump 2-2 recirculation testing in that Valve RHR-2-8809B
was
open
when the
procedure
required it to be closed.
The failure to perform the surveillance
in accordance
with the procedure
is
a violation of TS 6.8. 1', which states,
in
part, that written procedures
shall
be established,
implemented,
and
maintained
covering applicable
procedures
recommended
in Appendix
A of
Regulatory
Guide 1.33,
Revision
2, dated
February
1978.
Appendix A of
Regulatory
Guide 1.33,
Revision
2,
recommends
procedures
covering surveillance
testing; preventive maintenance;
and startup,
operation,
and shutdown of
safety-related
systems.
Contrary to this requirement,
on October ll, 1994,
Valve RHR-2-8809B was not closed during the performance of STP P-3B as
required
by Step 12.2.6.
Since the violation is of very low safety
significance
and since the inspectors
are satisfied with the adequacy of the
corrective actions,
in accordance
with Section VII.B.(1) of the Enforcement
Policy, this violation was not cited (323/9424-02).
5
ONSITE ENGINEERING
(37551)
5.1
Failure of EDG l-l to Stabilize
Between
59 and
61 Hertz
Hz
Within
13 Seconds
On March 29,
1994, with Unit
1 defueled,
during the performance of
Surveillance Test Procedure
(STP)
M-9A, "Emergency Diesel
Engine Generator
Routine Surveillance Test,"
EDG 1-1 failed to meet the acceptance
criteria for
frequency during the simulated
undervoltage start.
The frequency stabilized
at
a value of 60.3
Hz in 15.74 seconds,
which exceeded
the
TS acceptance
criteria of 13 seconds.
At the time, the other two Unit
1 diesel
generators
were out of service for maintenance activities.
Following the failure of
EDG 1-1 to pass
STP M-9A, the licensee parallelled
EDG 1-1 to the
bus
and continued to allow it to run, in order to return it to
status until determination of the cause of the frequency
problem.
The licensee
based
the conclusion of
EDG operability after
a stabilization
time problem on
TS Interpretation
85-02, which assumed
that start
and
0
0
-14-
frequency stabilization
was not required,
since the diesel
generator
was
already parallelled to its bus.
The licensee initially postulated that the most probable
cause of the
frequency stabilization problem was related to electrical
governor
performance.
and movement of irradiated fuel were suspended
as
a precautionary
measure
to allow for the diesel
generator to be taken out
of service for corrective maintenance.
Maintenance
personnel
successfully
adjusted
the governor during the second
adjustment.
On March 30,
1994,
EDG 1-1 was declared
operable after successful
completion of STP H-9A.
The licensee
continued to investigate
the root cause of the failure of EDG 1-1
to achieve rated frequency within TS time limits.
The licensee's
investigation
included talks with the governor manufacturer,
checking of
potentially affected diesel
generator
components,
and
a review of industry
and
Diablo Canyon experience.
Although, at the time of the inspection,
the
licensee
had not conclusively determined
the root cause,
the licensee's
corrective actions
appeared
to be directed
towards identification of the root
cause
and resolution of the problem.
For example,
measures
were being
implemented for all six diesel
generators
to periodically ensure that the
electrical
governor adjustment
locknuts are properly tightened
and that needle
valve "as-found" settings
are trended to determine if drift of the settings
is
a contributing factor.
Conclusion
The licensee's
response
to the
EDG l-l frequency stabilization
problem appeared
to be timely, thorough,
and appropriate to the circumstances.
5.2
Review of DCP M44425
The inspectors verified that the design basis
was not altered without proper
NRC notification and that adequate
postmodification testing
was planned.
In
addition,
the quality of the
DCP, proper reviews,
and design interface
controls were verified.
The following DCP was reviewed with no comments:
DCP H44425,
Revision 3,
"Remove the Narrow Range
RTD Bypass
Piping Network and
Install Thermowells in the Reactor
Coolant
System
Loop Piping with New Fast
Response
RTDs," and associated
Design
Change
Notices
(DCN):
DC2-EM-44425,
Revision 2,
and Field Change
H-18002;
DC2-EP-44425,
Revision
0 and Field
Changes
P-17936,
P-17932,
and P-18013;
DC2-EC-44425,
Revision
1,
and Field
Change
C-01813;
DC2-EP-46280,
Revision
1
and Field Changes
H-17965,
H-17934,
and H-17933;
DC2-EP-46281,
Revision 0,
and Field Change
H-17963;
DC2-EP-46282,
Revision 0; DC2-EP-46283,
Revision 0,
and Field Change
H-17964;
and DC2-SP-
44425,
Revision 0,
and Field Changes
H-17962
and H-18062.
5.3
B
ass'limination
DCN DC2-EH-44425,
through Revision
2, described
a modification that consisted
of replacing the existing single-element
RTDs with new "fast response"
dual-
element
RTDs.
This included removing the
RTD bypass piping,network and
associated
supports
connected
to the reactor coolant
system at the hot legs,
f'I
4 %. g
gl
'ta.
-15-
cold legs,
and crossover
legs, installation of thermowells to house the
new
RTDs,
and addition of new cabling to connect the
new
RTDs to the plant process
protection
system cabinets.
This
DCN was considered
the principal design
document,
and it addressed
work activities by discipline (i.e., mechanical,
electrical, etc.),
and identified each of the applicable
sub-DCNs.
During this inspection,
the primary in-process
work activity observed
by the
inspector dealt with installation (i.e., machining,
welding,
and
nondestructive
examination)
of thermowells
and caps.
This work had
been
contracted
to Westinghouse
Electric Corporation
and
was being performed
under
DCN DC-2-EP-44425,
Revision 0.
All hardware for this job, including welding
materials,
had
been
procured
by the licensee,
who was also responsible for the
performance of all postmodification
and functional testing.
The inspector
reviewed the following WPSs
and procedure qualification
records
(P(Rs) that were applicable to the
RTD modification:
WPS 10800,
Revision 5,
and
P(R 418, Revision 0, for the shielded
metal
arc welding
process;
and
WPS 50800,
Revision 7,
and
P(R 417,
Revision
1, for the gas
arc welding process.
These
WPSs
had
been
developed
and qualified for
welding of groove
and fillet welds in stainless
steel
in accordance
with the
1993 Addenda to the
1992 Edition of the
ASME Code.
The inspector verified
that all
ASHE Code required essential
variables for both welding processes
had
been identified, qualified,
and included in the
WPSs.
The inspector also verified that all
ASME Code required tests
and examinations
had
been identified and incorporated into the
RTD design
change.
This
included hydrostatic testing,
visual examination, liquid penetrant
examination,
and radiography.
The hydrostatic testing
and radiography
were
within the licensee's
scope of work, while the visual
and liquid penetrant
examinations
were within the scope of the vendor's contract.
Conclusion
The licensee
and vendor
had properly considered
and accounted for
ASHE Code requirements
regarding welding, testing,
and examination during
development of the
RTD modification project.
With the exception of welding, observation of the work (i.e., machining
and
nondestructive
examination)
was performed
by the inspector during review of
the licensee's
repair
and replacement activities,
which are part of the
ASHE
Code Section
XI in-service inspection
program.
This subject is addressed
in
NRC Inspection
Report 50-275/94-25;
50-323/94-25.
6
FOLLOWUP HAINTENANCE
(92902)
The licensee
has experienced
problems with the pressurizer
backup heater
circuit breakers.
Host of the problems
were related to the breaker failing to
close
as
a result of binding.
In October
1993,
the licensee initially attributed the failure of
Breaker 52-IH-74 to dried lubricant.
As
a result of the licensee's
investigation, it was noted that this particular breaker,
and three other
I
-16-
breakers,
had not been included in the preventive maintenance
program.
The
licensee
then developed
a preventive maintenance
task for these
breakers.
Three of the four breakers
had the preventive maintenance
by September.
1994.
The remaining breaker,
which was the first to fail, was scheduled
for, but had not undergone,
preventive maintenance.
On September
6,
1994,
Breaker
52-1H-74 failed to actuate.
The electrical
craft initially identified the cause
to be excessive dirt buildup on the
operating
mechanism
because
of the lubricant.
An electrical craft supervisor,
however,
noticed
a difference
between
the failed breaker
and
a spare
breaker.
The difference
was that the tab of the close latch release
lever was not bent
at
a 45 degree
angle
on the failed breaker.
As a result of the lever not
being bent,
the coil was required to move further to allow the breaker to
close.
This extra
movement required extra time, giving the appearance
of
sluggish operation,
which initially was thought
by the licensee
to be
as
a
result of a sticking mechanism.
The licensee
bent the tab of the close latch
release
lever to approximately
45 degrees
and tested
the breaker
satisfactorily.
Conclusion
The licensee
planned to either revise
Procedure
HP E-64.4,
"Maintenance of FPE Type
FPS2 Circuit Breakers,"
to include
a check for the
angle of the latch release
lever, or replace
the breakers
with a different
design.
These
actions
appeared
to appropriately
address
correction of the
problem.
7
PLANT SUPPORT ACTIVITIES
(71750)
7. 1
Ph sical Securit
Observations
7. 1. 1
General
Integrity of Protected
Area
(PA) Barriers
The inspector
performed
a walkdown of the
PA perimeter
boundary.
The fence
support
members,
fabric,
and barbed wire were examined.
No damage
or
degradation
was found.
The inspector verified that the size of all openings
were well within the acceptable criteria and there
were
no signs of erosion at
the base of the fence.
The fence
was generally taut
and the bottom bar or
wire prevented
the fabric from being lifted.
The inspector
attempted
to lift
the bottom of the fence in several
places.
In the area
where the fence
was
the most loose,"it could only be raised
1 -
2 inches.
The maximum allowable
is
6 inches.
Conclusion
The
PA barrier
was determined
to be generally in good condition
and in compliance with the licensee's
Security Plan.
7. 1.2
Maintenance of Isolation Zones
Around
PA Barriers
During the walkdown of the
PA perimeter fence,
the isolation zones
around the
PA barriers
were found to be free of objects, clearly marked,
and of
sufficient size to permit clear observation
and assessment
of any unauthorized
activity by the security force members.
-17-
Conclusion
The isolation zones
are being maintained
in accordance
with
licensee
procedures.
7. 1.3
PA Personnel
and
Package
Access
The inspector
reviewed the
PA personnel
and package
access
process,
including
the explosive detector,
metal detector,
and x-ray machine,
with a Security
Shift Supervisor.
The operation of each device
and the expected
actions
and
responses
by the security officers observing or operating
the equipment
were
discussed.
The inspector
observed
the operation of the search tt ain for
approximately I/2 hour during the period day shift was reporting to work.
The
responses
to the explosive detector
alarms,
metal detector
alarms,
and
unidentifiable objects
passing
through the x-ray machine
were observed.
The
resulting pat-down
searches
or package
inspections
appeared
to be adequate
to
identify any unauthorized
materials,
The security officers issuing the
picture badges
were careful to check that the badges
issued
were for the
individuals pictured
on the badges.
Conclusion
The access
to the
PA for personnel
and packages
was being
adequately
controlled in accordance
with licensee
procedures.
7. 1.4
Protected
Area Vehicle Access
The inspector
observed
the entry of a vehicle into the
PA.
The vehicle
was
searched
by
a security officer.
The search
included the cab,
engine
compartment,
undercarriage,
cargo area,
and tool boxes.
No unauthorized
material
was found.
However, the officer did identify two objects that were
initially omitted from the materials verification form, but were subsequently
allowed into the
PA after the driver of the vehicle completed
the required
documentation.
The inspector
examined
several
parked vehicles inside the
PA.
All but one
were licensee
owned vehicles.
The inspector verified that the ignition keys
had
been
removed
and the doors locked
on the licensee's
vehicles
and that,
in
addition, the steering
had
been disabled
on the nonlicensee
vehicle.
Conclusion
The access
to the
PA for vehicles
was being adequately
controlled
in accordance
with licensee
procedures.
7. 1.5
Physical
Security
Power Supply
The inspector
reviewed the records for the tests of the physical security
secondary
power supply.
Diablo Canyon Nuclear
Power Plant tests
the secondary
power supply once
each quarter.
The inspector verified from the records that
the security die'sel
generator
picked
up the loads in less
than the minimum
time allowed when the normal
power supply was interrupted.
Conclusion
Inspected
elements
of testing the physical security secondary
power supply were in accordance
with licensee
procedures.
-18-
7.2
Emer enc
Pre aredness
7.2. 1
Emergency
Preparedness
Exercises
and Drills
During review of the records for exercises
and drills for 1994,
the inspector
verified that the drills and exercises
were being conducted
as required
and
all findings and deficiencies
were tracked
on the Drill Action Item Report.
Conclusion
The emergency
preparedness
drills and exercises
were being
performed at the required periodicity,
and the findings
and deficiencies
were
being tracked
in accordance
with the
Emergency
Plan.
7.2.2
Emergency
Response
Facilities
The inspector toured the Technical
Support Center with one of the
Emergency
Planning Coordinators
and verified the facility was readily available for
emergency
operations.
The emergency
procedures
were available
and were being
maintained.
There were
some
spaces
that were being used for normal
operations,
but these
areas
would be promptly vacated
to make
them usable for
emergency
operations.
The inspector verified that the telephones
were
operational
by selecting
and testing several
at random.
Conclusion
The Technical
Support Center
was readily available
and maintained
for emergency
operations.
8
IN-OFFICE REVIEW OF LERs
(90712)
The inspectors
performed review of the following LERs associated
with
operating events.
Based
on the information provided in the report,
review of
associated
documents,
and interviews with cognizant licensee
personnel,
the
inspectors
concluded that the licensee
had met the reporting requirements,
had
addressed
root causes,
and
had taken appropriate corrective actions.
The
following LERs are closed:
275/93-003,
Revision
1
Low Temperature
Overpressure
Protection Setpoint
Analysis Nonconservatism
Due to Miscommunication
275/94-016,
Revision
0
Diesel
Generator
Started
as
Designed
Upon De-
energization of Startup
Bus
Due to Offsite
Wildfire
323/94-002,
Revision
0
TS 3.0.4 Not Met Following Inadequate
In-Service
Testing
323/94-003,
Revision
0
Auxiliary Building Ventilation System Outside of
Design Basis
Due to Previous
Nonconservative
ASTM Testing
C, ),
-19-
323/94-004,
Revision
0
Partial
Phase
A Containment
Isolations
Due to
Safeguards
Output Driver Card Failure
323/94-005,
Revision
0
Fuel
Handling Building Ventilation System
Outside of Design Basis
Due to Previous
Nonconservative
ASTN Testing
9
ONSITE LER REVIEW
(92700)
9. 1
0 en
LER 275 94-009
Revision 0:
Not Met Durin
Pressurizer
Code Safet
Valve Surveillance Testin
Unit
1
LER 94-009,
Revision 0, identified that the three Unit
1 pressurizer
safety valves were set-pressure
tested
at the Westinghouse
Service Center test
facility in Harch
1994.
The as-found setpoints of all three valves were found
outside the
TS tolerance of 2485 psig, plus or minus
1 percent.
These valves
were reset to the correct set pressure
prior to being reinstalled.
The
LER
which reported
the failure of the valves to liftwithin the required
band
stated that the root cause of the valves
being outside of the
TS tolerance
had
not yet been determined.
However,
NRC review of this issue
revealed that
PGEE
had performed
an extensive
safety valve test
program
and
was in the process
of
evaluating the results of the program.
The Diablo Canyon pressurizer
safety valves are Crosby Valve and
Gage .Company,
size
6M6, Model HP-BP-86, valves
and were installed
on loop seals
on both
Units
1 and 2.
The Diablo Canyon
TS and the
ASNE Code required that the
pressurizer
safety valves
be periodically tested to verify the setpoint to be
2485 psig, plus or minus
1 percent.
A review of the periodic test results for
the as-found setpoint data indicated the valves failed to meet the setpoint
tolerance
on numerous
occasions.
The inspectors
reviewed
Document
BL1-996C, "Diablo Canyon Pressurizer
Safety
Valve Test
Program Results."
The test
program started
in 1990
and included
dimensional verification of valve tolerances
and design
and fabrication of a
prototype valve.
The prototype valve
and standard
safety valve were tested
under the
same conditions
and results
compared.
The initial tests
performed
were
steam tests without
a loop seal.
The results of the steam tests for both
the prototype valve
and the standard
valve indicated that the setpoint varied
a great
deal
depending
on
how much seat
leakage existed prior to opening.
The
report concluded that steam testing
was inappropriate for the valve, since the
valve leaked during steam testing
and the setpoint could not be accurately
determined.
The second
series of tests
were performed with a loop seal
in
place.
The loop seal
temperature
and ambient temperature
were closely
maintained to the actual conditions at the plant.
A number of setpoint tests
were performed
bn the standard
and the prototype valves.
The repeatability of
the setpoint of the standard
valve was plus or minus 0.9 percent
(22 psi).
The repeatability of the setpoint of the prototype valve was plus or minus
0.4 percent
(11 psi).
I
k
-20-
The pressurizer
safety valve test
program report
had
a number of
recommendations.
Among the recommendations
were,
having the licensee
prepare
which would allow testing of the pressurizer
safety
valves with a loop seal
in place instead of testing directly on steam,
modifying the six pressurizer
safety valves to match the prototype valve
configuration,
and revising appropriate test procedures
to specify testing the
valves
on
instead of directly on steam.
The inspectors
reviewed mechanical
maintenance
Procedure
HP H-7.36, Revision
14, "Pressurizer
Safety Valve Lift Point Setting Using Steam."
The procedure
contained
a detailed discussion
on
how the setpoint
should
be determined.
The
procedure
included the requirement to use
and
an environmental
chamber with temperature
requirements
specified for the loop seal,
valve inlet
body,
and bonnet.
The procedure
included the
ramp rate for the
pressure
increase
during the test.
The inspectors
concluded that the
procedure
had excellent detail
and
was very clear.
The inspectors
noted that
all of the recommendations
for the test
program were incorporated.
Nonconformance
Report
DC1-89-TN-N099, Revision 3, dated January
1,
1994,
was
initiated in 1989
and remains
open.
The nonconformance
report documented
the
concern that the
TS setpoint tolerance of plus or minus
1 percent for the
pressurizer
safety valves could not
be maintained
at Diablo Canyon.
The
report documented
the history of the valve failures since
1989
and the
corrective actions to attempt to solve the setpoint drift problems.
The inspectors
reviewed Calculation
N-126, dated April 22,
1994,
"Overpressure
Analysis for Unit
1
1R6 as found pressurizer
safety valve setpoints."
This
calculation
was performed to show that the Unit
1 pressurizer
safety valves
were capable of providing adequate
overpressure
protection for the reactor
coolant
system with the as-found setpoints.
The analysis
showed that the
system pressure
was lower that
110 percent of its design
pressure.
The calculation
concluded that there
was sufficient overpressure
protection with the as-found setpoints.
The inspectors
considered
that the
calculation
was adequate.
Conclusion
Overall, the inspectors
concluded that the Diablo Canyon personnel
were being proactive in the manner in which they were researching
the safety
valve setpoint drift problem.
This
LER remains
open pending completion of the
corrective actions.
9.2
0 en
LER 275 323 94-003
Revision 0:
TS 3.7. 1. 1 Not Het Durin
HSSV
Surveillance Testin
Units
1
and
2
LER 94-003,
Revision 0, identified that
on February
9,
1994, for
Unit
1
and
on Harch 5,
1994, for Unit 2, while performing setpoint testing
on
the
HSSVs,
TS 3.7. 1. 1 was not met.
Thirteen Unit
1 valves
and
15 Unit 2
valves did not meet the
TS setpoint tolerance of plus or minus
1 percent.
For
Unit 1:
one valve was
between
1 - 3 percent
low; five valves were between 1
3 percent high; five valves
were greater
than
3 percent
high with a maximum of
9 percent;
and two valves did not lift due to the test equipment
load cell
-21-
limitations.
For Unit 2:
one valve was between
1
3 percent
low; one valve
was
between
1
3 percent high;
seven
valves
were between
1 - 3 percent high;
and six valves were greater
than
3 percent high.
The highest
was
approximately
9 percent
above the setpoint.
Additional testing
was conducted
and adjustments
made
as necessary
until all of the valves lifted within TS
tolerances.
The
LER stated that the root cause
and corrective actions for the
HSSVs being out of TS tolerance
had not been determined.
The root cause
and
corrective actions
would be included in a supplemental
LER.
The
20 Unit
1 valves
were sent off-site to the Westinghouse
Western Test
Center
and tested
on steam.
The
20 Unit 2 valves
were tested
in place using
the Trevitest lift assist
device.
The Trevitest lift assist
device allowed
the valve to be tested
in place
by using system pressure
and the additional
,force of the assist
device to lift the valve stem.
The set pressure
was
calculated
by knowing the
mean seat
area of the valve.
For both Units
1 and
2
valve tests,
the licensee
stated that the vendor
had provided
a
new mean seat
area
since the area previously used
was not accurate.
In addition,
the
licensee
stated that the
20 Unit 2 valves would all
be tested
on steam during
the Unit
2 outage this year.
The inspectors
reviewed Calculation N-110, Revision 0, "Overpressure
Study for
unit
1
1R6 As Found
HSSV Setpoints."
The calculation
was performed to
determine if the capability of the
HSSVs with the Unit
1 as-found setpoints
would provide overpressure
protection for the
SGs.
The calculation
assumed
that the two valves which did not open
due to the limitations of the test
equipment
were unavailable.
The calculation concluded that the peak
secondary
side pressures
were lower than
110 percent of the design pressure;
therefore,
the
HSSVs with the as-found setpoints
would have provided adequate
overpressure
protection.
The inspectors
considered
the calculation to be
adequate.
Nonconformance
Report DC1-89-TN-N098, Revision 00, dated April 28,
1994,
"Hain
Steam Safety Valve Lift Point," was initiated in 1989
and remains
open.
This
nonconformance
report documented
the history of the valve failures since
1989
and the corrective actions to attempt to solve the setpoint drift.
The
licensee
stated that the Unit 2 HSSV tests,
which will be performed during
Refueling Outage
2R6,
may be included in this nonconformance
report.
The licensee
stated that Diablo Canyon
had completed
a test
program for the
HSSVs in August
1994.
They stated that the test
program consisted
of setting
the valves
on steam
and then setting
them using the
AVK lift assist
device.
The purpose of the test
program
was to determine
the
mean seat
area of the
valve that would be used with the lift device which would correlate with the
set pressures
determined
during steam testing.
The licensee
stated
they had
performed
a large
number of tests
both
on steam
and then using the
AVK
equipment.
Three valves set at three different set pressures
were used for
the tests.
The inspectors
requested
a copy of the test procedure
used for
this series of tests.
However, the licensee
stated
they had not used
a test
procedure.
The licensee
stated that the test results
were preliminary since
the testing
was concluded
August 26,
1994.
The inspectors
did not review any
P
-22-
of the test data.
The licensee
stated that the preliminary test results
indicate that the correlation
between
steam testing
and the lift assist
device
testing
was very close
and setpoint
spread
was within plus or minus
1 percent.
Conclusion
An NRC review of the final report of the set pressure
correlation
tests
should
be performed prior to closing this
LER.
,,II
1
PERSONS
CONTACTED
1.1
Licensee
Personnel
ATTACHMENT 1
G.
H.
Gen
- W. H.
- R.
T.
LE
J.
S.
J.
R.
D.
H.
S.
G.
- W. G.
- S.
R.
- B. W.
J. J.
C.
R.
J.
A.
- K. A.
M.
E.
- D. B.
S.
R.
P.
G.
- D. A.
B. T.
E.
V.
R.
H.
D.
B.
Rueger,
Senior Vice President
and General
Manager,
Nuclear
Power
eration
Business
Unit
Fujimoto, Vice President
and Plant Manager,
Diablo Canyon Operations
Powers,
Manager,
Nuclear guality Services
Grebel,
Supervisor,
Regulatory Compliance
Bard, Director, Mechanical
Maintenance
Becker, Shift Supervisor,
Operations
Behnke,
Senior Engineer,
Regulatory Compliance
Chesnut,
Supervisor,
Reactor
Engineering
Crockett,
Manager,
Technical
and Support Services
Fridley, Director, Operations
Giffin, Manager,
Maintenance
Services
Griffin, Group Leader,
Onsite Engineering
Groff, Director, Plant Engineering
Hays, Director, Onsite guality Control
Hubbard,
Engineer,
Regulatory
Compliance
Leppke, Assistant
Manager,
Technical
Services
Miklush, Manager,
Operations
Services
Ortore, Director, Electrical Maintenance
Sarafian,
Senior Engineer,
Nuclear guality Services
Taggart, Director, Onsite guality Assurance
Hansen-Harris,
Watch
Commander,
Security
Waage,
Supervisor,
Emergency
Planning
Horris, Coordinator,
Emergency
Planning
Harsh,
Coordinator,
Emergency
Planning
1.2
NRC Personnel
- H. Tschiltz, Resident
Inspector
- Denotes -those attending
the exit meeting
on October
18,
1994.
In addition to the personnel
listed above,
the inspectors
contacted
other
personnel
during this inspection period.
2
EXIT MEETING
An exit meeting
was conducted
on October
18,
1994.
During this meeting,
the
resident
inspector
reviewed the scope
and findings of the report.
The
licensee
acknowledged
the inspection findings documented
in this report.
The
licensee
did not identify as proprietary
any information provided to, or
reviewed by, the inspectors.
'V
r
ATTACHNENT 2
ACRONYNS
ASNE
DCN
LER
OP
TS
WPS
alternating current
American Society of Mechanical
Engineers
American Society for Testing
and Materials
centrifugal
charging
(high head injection)
chemical
and volume control
system
design
change notice
design
change
package
emergency
diesel
generator
licensee
event report
operating
procedure
protected
area
procedure qualification records
residual
heat
removal
resistance
temperature
detector
surveillance test procedure
Technical Specification
weld procedure specifications