ML16342A478
| ML16342A478 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 04/01/1994 |
| From: | Kirsch D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342A477 | List: |
| References | |
| 50-275-94-07, 50-275-94-7, 50-323-94-07, 50-323-94-7, NUDOCS 9404150150 | |
| Download: ML16342A478 (28) | |
See also: IR 05000275/1994007
Text
APPENDIX B
U.S.
NUCLEAR REGULATORY COHHISSION
REGION IV
Inspection Report: '0-275/94-07
50-323/94-07
Operating Licenses:
DPR-82
Licensee:
Facility Name:
Inspection At:
. Pacific
Gas
and Electric Company
Nuclear
Power Generation,
B14A
77 Beale Street,
Room
1451
San Francisco,
California 94177
Diablo Canyon Units
1 and
2
~
Diablo Canyon Site,
San
Luis Obispo County, California
Inspection
Conducted:
February
17 through Harch 19,
1994
Inspectors:
H. Hiller, Senior Resident
Inspector
H. Tschiltz, Resident
Inspector
Accompanying Personnel:
J. Minton, Inspector Intern,
Approved By:
D.
irsc,
C ie
Reactor Projects
Br anch
1
t
ige
Ins ection
Summar
Areas
Ins ected
Units
1
and
2
Routine,
announced,
resident
inspection of-
onsite followup of events,
operational
safety verification, plant maintenance,
surveillance observations,
quality assurance,
followup on corrective actions
for violations, other followup, and in-office review of licensee
event
reports.-
Results
Units
1
and
2
Stren ths:
A request for enforcement discretion
appeared
to have
been well
implemented.
Nuclear guality Services
appeared
to have performed
a well focused
and
appropriately critical assessment
of the major licensee
organizations.
9404150150
940401
ADOCK 05000275
6
Weaknesses:
I
~
Operators
did not properly vent the reactor vessel
head,
resulting in an,
RCS level
change of about six feet during the
RCS draindown evolution.
Summar
of Ins ection Findin s:
~
Violation 50-275/94-07-01
was
opened
(Section
2. 1).
~
Violations 50-323/93-16-01,
50-323/93-16-02
and 50-275/93-22-01
were
closed
(Section 7).
~
Followup Items 50-275/92-31-03
and Unresolved
Item 50-275/93-34-03,
were
" closed
(Section 8).
~
Licensee
Event Reports
50-275/94-01,
Revision
0 and 50-275/94-03,
Revision
0 were'losed
(Section 9).
Attachments:
il
~
Attachment
1 - Persons
Contacted
and Exit Heeting
~
Attachment
2 - Acronyms
-3-
DETAILS
1
PLANT STATUS
1.1
Unit
1
. The Unit operated. at
100 percent of rated thermal
power until March 11,
when
the Unit was shut
down for a scheduled
refueling outage.
The Unit is
currently in Mode 6.
1.2
Unit 2
The Unit operated
at
100 percent
power except for February
24,
1994 to
February
26,
1994
and March 6,
1994 to March 7,
1994, during which power was
reduced to 50 percent to clean
condensers.
2
OPERATIONAL EVENTS
(93702)
2. 1
Failure to Pro erl
Vent the Reactor
Vessel
Head Durin
Unit
1 Reactor
Coolant
S stem
Draindown
On March 14,
1994, during routine draindown of the Unit
1
RCS from a full
system,
to the level just b'elow the reactor
vessel
in preparation for
refueling,
an abrupt
change
in
RCS level occurred.
When
an indicated level of
111.5 feet
was reached,
both trains of level indication rapidly increased
to
an indication of 117.9 feet.
Draining operations
were halted to determine
the
cause.
Operators
determined that the step
in the drain down procedure
to vent the
reactor vessel
head
by cross-tieing
the level indication reference
legs
had
been
performed improperly.
This step cross-ties
the reactor vessel
head
volume with the top of the pressurizer
to provide
a
common reference
leg, thus
,assuring
a consistent
level reading
between
the two channels
of reactor
vessel
level indication,
and level equalization
between
the reactor vessel
and the
RCS loops.
The operators
had proceeded
to cross-tie
the level indication
between
the pressurizer
and the reactor vesse!
head
by performing the required
valve manipulations
concurrent with performing
RCS draining operations.-
The
control
room staff had not recognized
the
need to complete
the cross-tie
evolution before proceeding with the reactor vessel
draindown.
Completion of
the cross-tie evolution not only placed the narrow range level indication in
service,
but also provided
a
common reference
leg for the reactor vessel
level
indication channels,
and
a vent path for the reactor vessel
head.
As
a result,
when the required valve line up to cross tie the vents
was
completed in containment,
an abrupt increase
in the indicated level
was
observed
and water levels were allowed to equalize
between
the reactor vessel
and the pressurizer,
causing
the indicated level transient.
The event
had
no
impact
Draining'perations
continued after the root
cause of the level
change
had
been determined.
The procedure,
OP A-2:II; Revision
11
(XPR), "Reactor Vessel - Draining the
RCS to the Vessel
Flange - With Fuel in the Vessel",
Step 6.4, stated
"Place
the
NR RVRLIS and the vent cross-tie
in servic'e
as follows:...NOTE:
The
following step aligns the
PRT nitrogen supply to the both the Pressurizer
and
the Reactor
Vessel
Head through the cross-tie."
The following step,
6.4.2,
implemented
alignment of the cross-tie,
and noted that the Narrow Range
Reactor
Vessel
Refueling Level Indication System
(NR RVRLIS) was not required
at that
RCS water level.
Operators
had
assumed that,
since the
NR RVRLIS was not yet required,
draining
operations
allowed
by Step 6.5, could continue in parallel with performance of
Step 6.4,
which placed the
NR RVRLIS and vent cross-tie
in service.
The above failure to properly perform Procedure
OP A-2:II, which resulted
in
incorrect level indication
and
an abrupt
change
in
RCS level, is considered
a
violation of Technical Specification 6.8. 1., which requires that procedures
be
implemented
governing the activities
recommended
in Appendix A of Regulatory
Guide 1.33, Revision
2, including procedures
involving draining
and refilling
of the recirculation loops,
and the reactor vessel.
(Violation 50-275/94-07-
01).
2.2
Offset of Main Steam Safet
Valve Lift Set pints
and Notice of
On March 9,
1994,
the licensee
was notified by
a vendor (Fermanite) that the
method
used to test
(HSSV) lift setpoints
during power
operations
was potentially inaccurate.
The vendor identified that the seat
lift area coefficient used to set the valves
may have
been incorrect,
resulting in the
MSSVs lift setpoints
being set about
two percent higher than
the intended setpoint.
At 6:00 p.m.
on March 12,
1994, after evaluation
and
analysis,
the licensee
determined that the issue
was applicable to Diablo
Canyon.
Because
TS 3.7. 1. 1 requires
HSSVs to be set within plus or minus
one
percent of the design setpoint, all
HSSVs were declared
At that
time, the licensee
requested
that the
NRC grant enforcement discretion; to not
enforce
TS 3.7. 1. 1, which would have required plant shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />,
.while the licensee
obtained test
equipment
and performed lift setpoint
testing.
The
NRC granted
the request,
documented
in an
NRC letter dated
March 15,
1994.
The licensee's
request
was well focused
and provided all required information
to evaluate
The licensee
completed testing
and
resetting of the valves, returning
them to operable
status
on March 15,
1994.
2.3
Hain Steam Safet
Valve Drift
A separate
issue
concerning
the
HSSVs involved unexpected
random drift of the
lift setpoint.
During several
days in February,
1994, routine surveillance
testing
shoved that most of the
20 Unit
(MSSVs)
had
experienced
apparently
random lift setpoint drift of up to
5 percent.
The
licensee
reset
each
HSSV lift setpoint to within plus or minus
one percent of
the required lift setpoint after each lift test,
as required
by TS.
Although
some setpoint drift had
been identified in the past, drift was typically no
greater
than
3 percent of the lift setpoint.
As
a result of the findings
on
Unit 1, the licensee
then tested
the Unit 2 HSSVs,
and found that similar
drift had occurred.
On Harch 4,
1994, testing of the Unit 2 valves
was
completed;
Safet
Si nificance
To address
past,
less
severe
HSSV setpoint drift, the
licensee
had performed analysis
which concluded that drift of up to plus or
minus three percent of the
HSSV lift setpoint
had
no effect
on safety.
The
licensee
then performed similar analysis of the as-found condition of the
HSSVs,
and concluded that the as-found Unit'
and
2 setpoints
would not have
had
an adverse effect on any design basis
events.
The inspector
concluded
that the licensee's
analyses
provided adequate
assurance
the observed drift in
setpoints
would have minimal effect on any design basis
events.
2.4
Failure of a Steam Generator
Level Transmitter
Seal
Resultin
in Non-
Conservative
Protection
S stem Bistable
Res
onse
On Harch ll, 1994, operators
observed
Level Transmitter
LT-519
fail high without causing
the expected resultant reactor protection
system
bistable trip.
Operators
promptly tripped the associated
bistable.
The subsequent
investigation
and repair work determined that
a
conduit seal
associated
with. providing the required
Equipment gualification
for the level transmitter
had failed.
Both the conduit seal
and the
transmitter .were manufactured
by Rosemount.
The licensee
determined. that
a
short circuit had occurred in the seal
and initiated 'a guality Evaluation to
track the ro'ot cause investigation.
The seal
was sent to the vendor
(Rosemount)
for failure analysis.
Neither licensee
nor Rosemount
investigations
have identified the cause of the failure to date,
nor have
similar failures
been identified in industry.
The licens'ee's
investigation
'nd
analysis
are continuing.
The failure of the bistable to trip was determined to have
been
a result of
exceeding
the protection set comparator
design
maximum voltage of 15 volts.
The short circuit in the conduit seal
resulted
in the current path bypassing
the current limiter in the transmitter.
As
a result,
the comparator
was
subject to
a voltage spi ke over the
15 volts design
maximum rather
than
typical voltage of less
than
6 volts.
h'hen the comparator
was subjected- to
a
voltage spike of over it's design
maximum,
a non-conservative
response,
failure of the bistable to trip, occurred.
The vendor manual for the over
ranged
component
in the comparator,
an operational
amplifier, also stated that
valid responses
were not expected
over the
15 volt design
maximum.
The licensee
determined that,
because
redundant'nd
diverse reactor protection
trains were available,
the
SSPS safety function would have
been satisfied
under design basis conditions.
The inspector
agreed,
with the exception of
the concerns
noted below.
The inspector
expressed
concern regarding
a
common
mode failure vulnerability
of the existing
SSPS
comparators
to fail in
a non-conservative
manner.
The
licensee
pointed out that
an
NRC safety analysis
had
been
performed to
evaluate
the
common
mode failure of the protection set functions of the
planned
Eagle
21
SSPS
upgrade,
to be installed in both units.
From
a functional standpoint,
the Eagle
21 failure would bound the concern for
a
common
mode comparator failure identified by the inspector;
that, is, the
failure of all trains of a trip function at the 7100 analog
Hagan rack
protection sets.
The
NRC safety analysis
associated
with NRC License
Amendments
84 (Unit 1)
and
83 (Unit 2) concluded that the analysis of
protective function diversity to the Eagle
21 upgrade
provided reasonable
assurance
that adequate diversity exists in diverse functions to mitigate
eve'nts.
Since the
SSPS in both units will be replaced with the Westinghouse
Eagle
21
solid state protection
system upgrade,
the licensee
investigated
the effect of
a similar voltage spike
on the
new system.
Hoth analyses
of the design
and
testing using the maintenance
training installation determined that Eagle
21
could withstand
up to 32 volts and continue to respond
in a conservative
fashion
(by causing
a high bistable trip).
Analysis
and discussions
with
determined that
up to 120 Volts could
be applied to the current
loop without causing
the Eagle
21 upgrade
system to fail in
a non-conservative
manner.
The licensee's
responses
resolved
the inspector's
concern
in this
area,
The inspector
expressed
concern that this failure of the bistable to trip when
subjected
to
a voltage spike
may additionally be
a generic
concern for
plants which may not have the
same level of diversity of reactor
protection functions
as Diablo Canyon.
The licensee
stated that Westinghouse
had
been
informed both directly and
by industry information issued
by the
licensee,
and
was evaluating
the failure for applicability to other
plants.
The inspector
had
no further concerns
in this area.
2.5
Conclusions
For the issues
associated
with MSSVs, the inspector
reviewed the licensee's
safety analyses
and operability evaluation.
The licensee's
conclusions
appeared
valid; that
no adverse
effects
on any design
basis
events
would have
occurred
due to the
MSSV setpoints.
For the non-conservative
response
of the level transmitter bistable,
the
inspector
reviewed the
NRC staff safety evaluation,
and,
based
in part
on that
evaluation,
concluded that the licensee's
assessment
appeared
valid.
The
concerns for Westinghouse
generic vulnerabilities
have
been transmitted
by the
licensee
to Westinghouse
and to the industry.
3
OPERATIONAL SAFETY VERIFICATION
(71707)
.1
L
The inspector
noted that the log entries for entry into the Technical
Specification action statements
associated
with the
MSSV Notice of Enforcement
Discretion discussed
above were incorrect.
The error involved the
documentation
of time of entry into the action statements,
which was several
hours too early.
The licensee
stated that the operator recording the action
statements
listed the time that the operability evaluation
was initiated,
rather than
when the evaluation
was concluded.
The licensee
promptly
corrected all log errors.
0
Based
on the,low safety significance of the errors,
the inspector considered
the licensee's
action adequate.
The inspector will continue to monitor the
licensee's
performance
in this area
as part of routine inspection activities.
I
3.2
Conclusion
Examples
of, minor log errors
were identified by the inspector
and were
promptly corrected
by the licensee.
The licensee's
response
was appropriate.
4
PLANT MAINTENANCE
(62703)
During the inspection period, the inspector
observed
and reviewed selected
documentation
associated
with maintenance
and problem investigation activities
listed below to verify compliance with regulatory requirements,
compliance
with 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
Unit 2
Diesel fuel oil suction cross-tie
piping replacement
(both units)
Diesel fuel oil discharge
cross-tie piping replacement
(both units)
Replacement
of the main annunciator
system with
a temporary annunciator
system in preparation for the Unit
system
upgrade
Temporary diagnostic modification (jumper) to Inverter
IY 2-2
Repair of Steam Generator
Level Transmitter
LT-519
4. 1
Lack of Documentation of Seismic Interaction
Anal sis for Tem orar
Modification
During
a routine plant walkdown, the inspector
observed that
a temporary
modification (jumper) to add monitoring capability to the
IY 2-2 inverter had
been
placed within a foot of the safety related inverter IY 2-2,
and
a jumper
(No. 93060)
had
been installed to allow monitoring of the inverter
performance.
Since the monitoring equipment,
an oscilloscope,
had not been
physically restrained,
the inspector raised the question of 'possible
seismic
interaction
between the monitoring equipment
and the inverter,.a
seismic
target.
The jumper safety analysis
required
by 10
CFR 50.59 did not include
a
seismic interaction analysis.
The inspector identified three
aspects
of
potential
seismic interaction which did not appear to have
been systematically
'
addressed
in the safety analysis:
I) the force transferred
to the frame of the
inverter from a collusion with the monitoring device;
2) potential interaction
with devices directly mounted inside the location
on the panel
which the
monitoring device could contact;
and,
3) the potential
weakening of the
inverter frame structure resulting from a gap created
by wiring which was
routed under the side panel of the inverter, resulting in
a fraction of an
inch separation
of the side panel
from the lower foundation panel.
Discussions
with the licensee's- onsite design engineering
group addressed
the
inspector's
concerns.
The potential for seismic interaction
was not
a concern
since
no relays or electrical
devices
were in direct contact with the panel
which may
come in contact with the monitoring device.
The frame structure of
the inverter was expected
to have sufficient design
margin to withstand
contact with the monitoring device during
a design basis
seismic
event with no
damage.
The routing of the wiring. under the side panel,
cau'sing
a gap, did
not significantly weaken the inverter's structural integrity.
Based
on
further detailed discussions,
the inspector determined that the licensee's
conclusions
were valid.
Interviews 'with members of the Plant Staff Review Committee
(PSRC),
revealed
that the evaluation of seismic interaction
had
been discussed
during
PSRC-
evaluation of the jumper,
and the
PSRC
had concluded that
no interaction
was
likely, based
on engineering
judgement
and familiarity with seismic
requirements.
The licensee
subsequently
modified the jumper procedure checklist to include
a
requirement for documentation
of applicable
seismic interaction analysis.
4.2
Installation of Tem orar
Annunciator Durin
Main Annunciator
S stem
Re lacement
On March 14, the inspector
obser'ved
the licensee transition from the Unit I
main annunciator to
a temporary annunciator
to support replacement
of the main
The inspector
questioned
the licensee
regarding
the procedure
that would be followed if the temporary
system failed.
The licensee
stated
that,
upon loss of the temporary annunciator,
although the annunciator
response
procedure
required only that the annunciato'r
be returned to service,
and that important parameters
be monitored,
the licensee
would also stop all
important operations,
and closely monitor selected
plant parameters
while the
system
was returned to service.
About 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after the transition to the temporary
system,
the temporary
system ma'lfunctioned.
Licensee
troubleshooting
found that
a, cable connector
for one of the temporary annunciator
computers
was loose.
During the
troubleshooting while the system
was .inoperable,
the licensee
stopped all
evolutions which "could result in changes
to existing plant conditions.
Additional operators
were stationed
to monitor plant parameters
such
as
pump performance,
RCS temperature,
RCS level,
and other significant
indicators.
The annunciator
was returned to service within 30 minutes, all
connectors
for the temporary annunciator
system were verified,
and access
to
areas
adjacent to the temporary annunciator
components
were restricted
from
routine personnel traffic.
4.3
Conclusions
The licensee's
actions to document the seismic safety analysis,
and to respond
to the annunciator
system failure were examined
and appeared
appropriate.
5
SURVEILLANCE OBSERVATIONS (61726)
Selected
surveillance tests
required to be performed
by the Technical
Specifications
were reviewed
on
a sampling basis to verify that:
I) 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 Technical Specifications;
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.
~ Analog Channel
Operational
Test Nuclear Source
Range
Unit
2
~
ASM System
Flow Monitoring
~ Routine Surveillance
Test of Auxiliary Saltwater
Pumps
Conclusions
The inspector
concluded that the surveillance tests
appeared
to have
been
performed in an acceptable
manner.
6
Review of guality Activities (40500)
6. I
ualit
Performance
Assessment
Re ort
1
The inspector
reviewed the recently issued guality Performance
Assessment
Report-issued
by Nuclear guality Services
to determine if the report
was
'appropriately probing
and critical of problem areas
and potential
problem
areas
in various licensee
organizations..
In this report,
the Nuclear guality
'ervices organization
evaluated
safety performance of the various licensee
organizations.
Current problem areas,
trends
and corrective action for
problem areas
were reviewed.
The report concluded that both site
and
corporate office engineering
organizations,
as well as the Nuclear guality
organizations,
were in need of additional
focus in complying with procedural
requirements
and in implementing
problem ownership.
The other organizations
evaluated,
including Operations
and Yiaintenance,
were considered
to have
adequate
identification and correction of problems,
although
problems in
personnel
methods
were noted.
-10-
In summary,
the concern for appropriate
implementation of personnel
methods,
following existing instructions,
and ownership of problems,
appeared
to be the
major concerns.
The report also
made note of minor equipment
management
problems,
and concluded that few problems of great significance
had occurred.
6.2
Nuclear Safet
Oversi ht Committee Heetin
On Harch 16,
1994, the inspector
observed
portions of a meeting of the Nuclear
Safety Oversight Committee
(NSOC) in order to evaluate
NSOC involvement
and
focus
on plant safety
and management
performance.
Recent
issues
were
discussed,
such
as operational
events,
concerns identified by NRC inspections,
quality assurance
audits,
and
Independent
Safety Evaluation
Group evaluations.
Discussion
focused
on root causes
of the
above issues,
as well
as
commonalities of problems
and corrective actions for the
above issues.
The
discussions
observed
appeared
to have
been appropriately responsive
to safety
and management
issues.
6.3
Conclusions
The samples of the licensee's
quality functions,
which were inspected
as
noted
above,
appeared
to have
been
performed in a probing, critical,
and well
directed
manner.
7
FOLLOWUP
ON CORRECTIVE ACTIONS FOR VIOLATIONS
(92702)
7. 1.
Closed
Violation 50-323 93-16-01:
Reactivit
Increase
While
Shutdown
Due to Boron Dilution b
Mixed Bed Demineralizer Return
To
Service
This violation involved
a situation wherein the licensee
allowed
a boron
dilution of the
RCS to occur while shut down,
as
a result of not properly
implementing corrective actions for lessons
learned
from industry experience.
By a letter dated
August 30,
1994,
the licensee
responded
to the issue
by
performing corrective
aetio'ns
which included training
on lessons
learned for
Operations
per'sonnel,
correction of proce'dures
to implement industry standard
corrective actions
(such
as placing administrative tags
on demineralizers
regarding
boron concentration,
saturating
demineralizer
beds with boron prior
to placing them in operation,
checking
boron concentrations
of unused
demineralizer vessels)
and other procedure
changes.
The licensee
also
reviewed industry experience
in addition to boron dilution concerns
to
determine if other areas
of industry experience
had
been properly reviewed
and
applied to the licensee's
operations.
The inspectors
examined
the licensee's
corrective actions
and implementation,
and concluded that the actions
appeared
to have
been appropriate
and acceptably
implemented.
7.2
Closed
Violation 50-323 93-16-02:
Reactivit 'ncrease
At Power
Due to
Cation Demineralizer
Bed Return to Service
This violation involved
a situation wherein the licensee
allowed
a boron
dilution of the
RCS to occur while at power,
soon after
a startup,
as
a result
of not properly implementing corrective actions for lessons
learned
from
industry experience.
By a letter dated
August 30,
1994,
the licensee
responded
to the issue
by performing corrective actions,
which included
training
on maintaining
a questioning attitude,
the importance of consulting
all affected groups before taking
an action,
documenting
intended actions,
correction of procedures
to specify conditions,
such
as
boron concentrations,
that existed
when the demineralizer
bed
was last in service,
and other
procedure
changes.
As discussed
above,
the licensee
also reviewed industry
experience
in addition to boron dilution concerns to determine if other areas
of industry experience
had
been properly reviewed
and applied to the
licensee's
operations.
The inspectors
examined
the licensee's
corrective
actions -and implementation,
and concluded that the actions
appeared
to have
been appropriate
and acceptably
implemented.
7.3
Closed
Violation 50-275 93-22-0I:
Inade uate Control of Plant
Lubricants
This issue
involved the addition of incorrect types of oil to safety related
pumps.
The most recent
occurrence
involved
a mixture of oil to an
ASW pump.
The licensee's
corrective actions
included tighter control of plant lubricants
by issuing lubricants at
an issue control point, training of operators
and
maintenance staff regarding labeling
and control of lubricants,
color coding
of lubricant containers,
and reduction
and elimination of several
small
lubricant storage bottles
used throughout the plant.
The inspector
examined
the licensee's
corrective actions
and concluded that the actions
appeared
appropriate
and acceptably
implemented.
8
FOLLOMUP OF
OPEN
ITENS (93702)
8.1
Closed
Followu
Item 275 92-31-03:
Lack of ASME Re uired Drain Lines
for Relief Valve Tail i es
The inspector identified that several
of the safety related relief valve
tailpipes which direct the valve discharge
in
a vertical direction did not
have drains
as required
by ASHE code.
The licensee
had pursued
a decision
by
the
ASHE code committee to accept
the valves without drains,
as installed,
but
later decided to discontinue pursuit of a code committee ruling,
and initiated
an
NCR to install drains in the tailpipes.
Hr. H. Ang'us,
Manager,
Nuclear
Engineering Services,
made
a formal commitment to the
NPC to install drains in
all relief valve tailpipes for which ASHE code
commitments
were applicable.
The inspectors
consi'dered that this resolved
the concern in
a satisfactory
manner.
8.2
0 en
Unresolved
Item 50-275 93-34-03:
Safet
Significance of Lack of
Rated Fire Barrier for Power
0 erator Relief Valve Conduits
During
a postulated fire, equipment
may be subject to spurious
operation
as
a
result of short circuits.
Therefore,
10 CFR 50, Appendix R,Section III.G
requires that equipment which may have spurious operation during
a fire and,
therefore,
may prevent safe
shutdown of a plant must
be protected
from short
circuits by rated fire barriers.
For Diablo Canyon,
spurious
operation of a
PORY during
a fire may prevent safe
shutdown.
-12-
The licensee identified that, for several fire areas,
the circuits for the
Power Operated Relief'Valves
(PORVs) were not protected
from spurious
operation
by rated fire barriers,
but by dedicated
conduit (conduit in which
only. one circuit is installed).
The inspector
was concerned
that this
configuration
may not meet the requirements
of 10 CFR 50, Appendix R, Section
III.G, which requires
rated fire barriers.
The licensee
provided engineering
evaluations
which concluded that the conduit
and other fire protection
measures
in the affected
area provided adequate
assurance
that
a fire would not cause
a spurious operation of a
PORV.
Part of
the engineering
evaluation
was
based
on acceptance
by the
NRC of similar
configurations of dedicated
conduit for other safe
shutdown
equipment,
as well
as identification of fire suppression
and
a light fire loading in the areas.
Conclusion
It was not apparent that adequate
basis
had
been provided to allow an
exemption
from the requirements
Accordingly, this
issue will be further discussed
with Regional
and
NRR management
to achieve
resolution.
9
IN-OFFICE REYIEM OF LICENSEE
EVENT REPORTS
(90712)
The following LERs were closed
based
on in-office review:
275/94-01,
Revision
0
275/94-03,
Revision
0
Inadequate
Seals
Due to
Lack of Damming Boards
Technical Specification 3.7. 1. 1 Not Het During
Hain Steam Safety Valve Surveillance Testing
Due
to Indeterminate
Causes
0
-13-
ATTACHMENT 1
1
'PERSONS
CONTACTED
1.1
Licensee
Personnel
- G. M. Rueger,
Senior Vice President
and General
Manager,
Nuclear
Power Generation
Business
Unit
- J. D. Townsend,
Vice President
and Plant Manager,
Diablo
Canyon Operations
'.
H. Fujimoto, Vice President,
Nuclear Technical
Services
- R. P.
Powers,
Hanager,
Nuclear guality Services
- J,
S.
Bard, Director, Mechanical
Maintenance
H. J.
Angus,
Manager,
Technical
Services
- W. G. Crockett,
Manager,
Technical
and Support Services
- R. P.
Flohaug,
Supervisor,
Performance
and Assessment
- S.
R. Fridley, Director, Operations
- R. D. Glynn, Senior Performance
Assessment
Engineer
- T. L. Grebel,
Supervisor,
Regulatory
Compliance
- B. W. Giffin, Manager,
Maintenance
Services
J. J. Griffin, Group Leader,
Onsite Engineering
C.
R. Groff, Director, Plant Engineering
- J. A. Hays, Director, Onsite guality Control
- J. R.'inds, Director, Nuclear Safety Engineering
- K. A. Hubbard,
Engineer,
Regulatory
Compliance
- J.
E. Molden, Director, Instrumentation
and Controls
- T. A. Houlia, Assistant to Vice President,
Plant Management
- S.
R. Ortore, Director, Electrical
Maintenance
P.
G. Sarafian,
Senior Engineer,
Nuclear guality Services
- J. A. Shoulders,
Director, Nuclear Engineering Services
- D. A. Taggart, Director, Onsite guality Assurance
- Denotes those attending
the exit interview.
1.2
NRC Personnel
- H. Miller, Senior Resident
Inspector
- H. Tschiltz, Resident
Inspector
J. Winton, Inspector
Intern,
In addition to the personnel
listed above,
the inspectors
contacted
other
personnel
during this inspection period.
+Denotes
personnel
that attended
the exit meeting.
2
EXIT MEETING
An exit meeting
was conducted
on March 29,
1994.
During this meeting,
the
inspectors
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 in,ormation provided to, or reviewed
by,
the inspectors.
ASW
LER
M8TE
,
NSOC
PSRC
RVRLIS
SPR
SSPS
-14-
ATTACHMENT 2
c
Auxiliary Salt Water
Licensee
Event Report
'easuring
and Testing
Equipment
Nonconformance
Report
Nuclear Safety Oversight
Committee
Power Operated
Relief Valves
Plant Staff Review Committee
Pressurizer
Relief Tank
Pump
System
Radiation
Work Permit
Residual
Heat
Removal
System
Reactor
Vessel
Refueling Level Indication System
Spent
Fuel
Pool
Site Problem Report
Solid State Protection
System