ML16341G400
| ML16341G400 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 12/13/1991 |
| From: | Morrill P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341G401 | List: |
| References | |
| 50-275-91-37, 50-323-91-37, NUDOCS 9112310011 | |
| Download: ML16341G400 (30) | |
See also: IR 05000275/1991037
Text
U.
S
NUCLEAR REGULATORY
CONN'ISSION'EGION
V
Report
Nos:
50-275/91-37
and 50-323/91-37
Docket Nos:
50-275
and 50-323
License
Nos:
and
Licensee:
Facility Name:
Pacific
Gas
and Electric Company
77 Scale Street,
Room 1451
San Francisco,
California 94106
Diablo Canyon Units
1
and
2
Inspection at;
Diablo Canyon Site,
San Luis Obispo County, California
r
Inspection
Conducted:
October
10 through
November
18,
1991
Inspectors:
H. Mono, Senior Resident
Inspector
Ni. Miller, Resident
Insp ctor
Approved by:
.. or
~
,
ref,
eactor
rogects
ect>on
A
/@ /3/~/
ate
>gne
Summary:
Ins ection from October
10 throu
h November
18
1991
Report
Nos.
50-275/91-37
and 50-323/91-37
~dd:
d
d
d
dd
operations,
maintenance
and surveillance activities, follow-up of onsite
events,
and selected
independent
jnspection activities.
Inspection
Procedures
41500,
61726,
71707,
62703,
71710,
and
93702 were
used
as guidance
during this inspection.
Safet
Issues
Nanaoement
S stem
SINS) Items:
The licensee's
responses
to
Generic Letter 88-17 were reviewed.
Temporary Instructions
2515/101
and
2515/103
were closed
(Paragraph
9).
Results:
General
Conclusions
on Stren ths
and Weaknesses:
The licensee's
startup
testing
o
Unct
was per
orme
wst
good coor ination
and communications
between engineering
and operations
personnel.
Nanaoement
involvement in the
testino
was evident.
Detailed tai lboards
were performed to assure
that those
involved understood
the tests.
No .significant weaknesses
were identified.
9f f23j00f j 9j f~j3
ADQCK 05000~75
G
Si nificant Safet
Matters:
None.
Summary of Violations and Deviations:
None.
0 en Items
Summar
One
new open item;
no items closed.
0
DETAILS
Persons
Contacted
- J.
D. Townsend,
Vice President,
Nuclear
Power Generation
8 Plant Manaoer
Diablo Canyon
Power Plant
~D. B. Niklush;- Manager,
Operations
Services
- N. J.
Angus,
Yianager, Technical
Services
B.
W. Giffin, Manager,
Maintenance
Services
- D. H. Oatley,
Nanager,
Support Services
W. G. Crockett,
Instrumentation
and Controls Director
- W. D. Barkhuff, Quality Control Director
- R. P. Powers,
Nechanical
Maintenance
Director
D. A. Tagoart,
Director Quality Performance
and Assessment
T; L, Grebel,
Regulatory Compliance Supervisor
H. J. Phillips, Electrical Maintenance Director
- J. A. Shoulders,
Onsite Project Engineering
Group Manager
S.
R. Fridley, Operations
Director
R.
Gray, Radiation Protection Director
J.
V. Boots,
Chemistry Director
- J. J. Griffin, Senior Engineer,
Regul.atory Compliance
D. K. Cosgrove,
Safety
and
Emergency Services
Supervisor
R.
W. Hess,
Assistant Onsite Pro'ject Engineer
~i. B. Hock, Nanager,
Nuclear Safety
and Regulatory Affairs
- T. A. Moulia, Assistant
to Vice President
Operations
J.
N. Welsch, Operations
and Engineering Training Supervisor
R.
P. Flohaug,
Senior Quality Assurance
Supervisor
- Denotes those
attending
the exit interview.
The inspectors
interviewed several
other licensee
employees
including
shift supervisors,
shift foremen, reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
and quality
assurance
'personnel.
2.
Operational
Status of Diablo Can
on Units
1
and
2
Unit
1
was at
100K power for essentially
the entire inspection period,
with the exception of
a few days
(November
2-5
and 9-10,
1991).
During
those periods reactor
power
was reduced
to 50K to perform cleaning of
the circulatino water tunnels.
Unit 2 started
the inspection period in Node
5 (refueling 'outage
2R4),
and the reactor
was brought critical on October 20.
Full power was
reached
on October
31.
This was the shortest refueling outage
in Diablo
Canyon history.
Unit 2 continued
at
100K power for the remainder of the
inspection period.
0
On November
12,
1991,
at 2,00 p.m.,
an Unusual
Event
was declared
by
licensee
personnel
due to
a grass
and brush fire within the site boundary
which required offsite assistance.
At. 10:00 a.m..that
day, licensee
personnel
workino with personnel
from the California Department of
Forestry started
a "controlled" burn of brush
and grass
in
a hilly area
outside the plant protected
area,
but within the site boundary.
At
approximately ]:30 p.m., higher than expected
winds caused
the fire to
iump across
the fire break lines.
Addit,ional equipment
from the
California Department of Forestry
was requested.
The California
Department of Forestry provided
an airplane to drop fire retardant,
a
helicopter to drop water, additional fire engines
and bulldozers,
and
additional
crews.
At approximately 4:00 p.m.
on November ]2, 199], the
fire was declared
out.
The
Unusua'1
Event was terminated
at 4:03 p.m..
The fire burned
an additional
7 acres
beyond the
25 acres orioinally
planned.
Plant equipment,
structures,
and transmission
lines were not in
jeopardy.
The
NRC inspector monitored the licensee's
response
to the
event
and determined that the control
room personnel
were maintaining
close
communications
with the fire marshal
overseeing
the fire fighting
activities.
No violations or deviations
were identified.
4.
0 erational
Safet
Verification
71707)
a.
General
Durino 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 to evaluate
trends.
This operational
information was then evaluated
to
determine if regulatory requirements
were satisfied.
Shift
turnovers
were observed
on
a sample
basis
to verify that all
pertinent
information of plant status
was relayed to the oncoming
crew.
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)
Conduct of selected
activities for compliance with the
licensee's
administrative controls
and
approved
procedures
(d)
Interiors of electrical
and control panels
(e)
Pl ant housekeeping
and cleanliness
(f)
Engineered
safety feature
equipment
alignment
and conditions
(g)
Storage
of pressurized
gas bottles
The inspectors
talked with operators
in the control
room .and other
plant personnel.
The discussions
centered
on pertinent t4pics of
'eneral
plant conditions,
procedures,
security, training,
and other
aspects
of the work activities.
During these plant .tours the
NRC inspector
noted
on two occasions
that extension
cords
had
been routed into the Unit 2 diesel
generator
room through the ventilation openings
from the outside.
These extension
cords
appeared
to be associated
with construction
activities for the installation of the sixth dies'el
generator.
In
one case,
the extension
cord had
been
plugged into
a wall outlet,
and the extension
cord was run through the
CO
suppression
system
rolldown door area
and near the diesel fuel o)1 transfer switches.
The inspector
was concerned
that the extension
cords might present
a
fire hazard
or reduce
the effectiveness
of the
CO
suppression
system.
When this concern
was brought to the licfnsee's
attention,
the extension
cords were'removed.
The
NRC inspector
also, noted that the seal
on the handwheel for
manual
valve 8728B (Unit
1 residual
heat
removal
pump 1-2 discharge
valve)
was missing with the valve in its required
open position.
Licensee
personnel
subsequently
reattached
the seal.
Based
on this
finding and other licensee findings of missing seals,
the licensee
performed
a verification of approximately
100 sealed
valves
(approximately
30K of the total
number of sealed
valves)
and found
no additional
cases
of missing seals.
b.
Radiolo ical Protection
c ~
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
aware of
significant plant activities, particularly those related to
radiological conditions
and/or challenges.
ALARA considerations
were
found to be
an integral part of each
RWP (Radiation
Work Permit).
Ph sical Securit
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,
and protected
and vital area inteority.
Exterior lighting was
checked
during backshift inspections.
No violations or deviations
were identified.
~
~
5.
Onsite Event Follow-up (93702
a.
Missed Containment
Atmosphere
Sample'- Unit
1
On November 3,
1991,
at .2:00 a.m.,
licensee
personnel
idgntified
that manual
containment
atmosphere
samples
had not been Properly
taken
as required
by Technical Specifications
(TS) in that the
manual
samples
were drawn using
a sample cart
when the containment
isolation valves
were closed.
A representative
sample of the
containment
atmosphere
could riot be obtained with the containment
isolation valves closed.
Containment isolation valves
FCV-678, 679,
and
681 were closed
due to work being performed
on the containment
particulate
and
gas radiation monitors
and
on the sample
pump
associated 'with the monitors.
TS 3.4.6.1'specifies
that
when
a containment
atmosphere
monitor is
plant operations
may continue for up to 30 days
as long
as
manual
samples
of the containment
atmosphere
are taken
and
analyzed
every
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
If manual
samples
are not obtained,
the
TS
specifies that the plant should
be shut
down to hot standby
conditions within the next six hours
and to cold shut
down
conditions within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The containment
isol'atioh
valves
were closed
on November
1 at approximately 4:50 p.m.
and
based
on the results of containment
atmosphere
tests,
the licensee
has concluded that the last valid sample
was
drawn
on November
2 at
12:40 a.m..
When subsequent. manual
containment
atmosphere
samples
were drawn
on November
2
and 3, the containment isolation valves
were apparently closed
(based
on the sample results
showing
no
activity).
Therefore the samples
did not represent
containment
atmosphere.
Procedures
specified that the containment isolation
valves
were to be verified to be open;
however, this
was not done.
Approximately 26 hours3.009259e-4 days <br />0.00722 hours <br />4.298942e-5 weeks <br />9.893e-6 months <br />
elapsed
between
when the last valid
containment
atmosphere
sample
was taken
and
when the closed
isolation valves
were identified and another valid sample taken.
The results of the samples
showed
acceptable
activity levels in
containment;
therefore,
there
was minimal safety impact
due to the
missed
sample.
However, this event revealed
several
weaknesses..
The operation of the manual
sampling
system
can allow
a
recirculation flow path to be established
such that
'a normal
sample flow rate is indicated
even with the containment
isolation valves closed.
Technicians
thought the isolation
valves
were
open
based
on the indicated flow rate
and did not
verify valve positions
although
procedures
specified that the
proper valve positions
be verified.
Subsequent
testing
by the
licensee
appears
to indicate that the recirculation flow is not
significant during operation of the manual
sample cart with the
containment isolation valves
open.
Technicians
who obtained
a sample
on November
2 at 12:47 p.m.
were not sensitive to the results
which showed
no activity.
This result
was not consistent
with past
samples
and could have
led to the earlier identification of the closed
containment
isolation valves.
0
Communications
between
operations
and chemistry/IEC were not.
adequate
to ensure that appropriate
compensatory
measures
were
taken
when the containment isolation valves for the, sample line
were closed.
The licensee's
evaluation of the event, is described
in NPR
DCI-91-TC-N098.
The licensee
has
concluded that this event is not
reportable.
The inspectors
concluded that this item was not
a
violation of the technical'pecifications
since
a valid sample
was
taken before the six hour action statement
would require
shutdown
to hot standby.
Steam
Introduced Into Nitro en
S stem Pi in
- Unit 2
During plant heatup of Unit 2 on October
15,
1991,
a
smoke detector
alarmed inside containment.
Upon investigation
by licensee
personnel,
the paint on nitrogen system piping in containment
was noted to be
smoking.
It was also noted that the nitrogen fill valves to steam
generator
2-2 (valves
2013
and 906) were open.
This allowed steam
at approximately
400 degrees
F and 400 psi from steam generator
2-2
to enter the nitrogen
system piping.
Licensee
personnel
closed
the
nitrogen fill valves to prevent further heatup of the piping.
The nitrogen line is used to provide
a nitrogen blanket for the
during outages
and also provides
a backup method
for operating certain valves in the reactor coolant
letdown system.
The letdown system valves
are inside containment
and are normally
operated
by instrument air.
The nitrogen line is not used during
normal plant operations,
and its outboard
containment isolation
valve is sealed
closed.
The nitrogen fill valves
were manipulated
during system vent
and fill operations
and apparently
were not
restored
to the closed position.
The licensee
performed
a detailed
walkdown of the nitrogen
system
piping which included disassembly
of some piping connections
to
determine
the extent of steam
and water intrusion.
The piping
arrangement
in the plant apparently provided
which
prevented
water from reaching
solenoid valves for the letdown valve
actuators.
The licensee
evaluated
the impact of the elevated
temperature
and water intrusion
on the piping and components
in the
system
and determined that the event did -not significantly
damage piping or components
except
the nitrogen pressure
regulators.
The licensee
disconnec4ed
lines to pressure
regulator
5199
and also
capped
the nitrogen lines to the letdown valves to preclude similar
problems
in the future.
The lines were blown down to remove
any
remaining water.,
and the letdown valves
were cycled to assure
no
damage
was sustained.
The event
and evaluation
are described
in AR
A0248331.
The
NRC inspector
reviewed the licensee's
evaluations
and
had
discussions
with licensee
personnel.
The evaluation
appeared
to be
thorough
and complete.
Based
on inspector discussions,
.the
licensee
revised
procedure
AP-9, Loss of Instrument Air, 'to indicate
that the affected
letdown valves
were
no longer provided:.with
a
backup nitrogen supply in Unit 2.
The inspector
had
no further
questions
regarding this event.
No violations or deviations
were identified.
6.
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
certified.
These activities include:
Work Order
R0096039 - Cleaning
CCW Heat Exchanger
2-1
Work Order R0071268 -
Pump 1-2 Oi 1
Sample
No violations or deviations
were identified.
7.
Surveillance
61726)
~
~a.
Observations
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.
These tests
include:
STP M-15:
Integrated
Safeguards
Test
STP R-30:
Startup
From Refueling
( Initial Criticality)
STP R-6:
Low Power Physics Testing
OP L-2:
Hot Standby to Startup
Mode
TP T0-8902,
Rev.
1:
RHR Water
Hammer Testing
STP 1-2D:
Power
Range
Channel Calibration
'7
b.
Testino Auxiliary Feedwater
AFW)
S stem Valves
No
On October-27,
1991, the 'inspector
observed testing of Valves
associated
with the the turbine-driven auxiliary feedwater
(AFW)
system in Unit 2.
The testing
was performed.to obtain v/lve
performance
data in response
to
This
testino
was performed during power operations
(at approximately
30K
power)
so that
steam would be available to run the turbine-driven
AFW pump.
Testing
was
implemented
by licensee
procedures
HP E-99.01,
Revision
0,
MOV Flow Test - TDAFW Flow Control Valves LCV-106, 107,
108,
and
109;
MP E-99.02, Revison',
MOV Flow Test - TDAFW Steam Supply
Valves
FCV-37, 38,
and 39;
and
STP P-6A, Revision 4, Performance
Test of Steam-Driven Auxiliary Feed Pump.'he
conduct of testing is
described
in procedure
NPAP C-3,
"Conduct of Plant
and Equipment
Tests."
The inspector
reviewed the test procedures
and concluded
that the procedures
appeared
to meet the requirements
of NPAP C-3.
The inspector
noted that the testing
appeared
to have
been
appropriately
controlled in that
a tai lboard discussion
was
conducted
both with the control
room staff and with technicians
stationed
at the valves.
Expected plant performance,
alarms,
and
test termination contingency actions
were discussed.
In addition,
a control
room shift change
was anticipated
and during the first
tai lboard discussion,
operators
determined
the appropriate
plant
conditions to suspend
testing during the shift change.
After the
shift change,
another tai lboard
was held with the
new shift which
reviewed the expected
plant performance,
alarms,
and test termination
contingency actions.
The inspector
observed that experience
gained
from earlier valve testing,
regarding minimizing plant transients,
was discussed
during each of the tailboard discussions.
A
representative
of licensee
management
wa's present
at each tailboard
discussion
and during the entire test evolution.
During the changes
in plant equipment status
and the resulting minor
plant transients,
operators
maintained stable plant conditions
and
coordination with 'technicians
at the valve stations.
Overall control
of testing
was effective
and
appeared
to maintain the priority on
safe operations.
The control
room operators
conservatively recognized
the need to
demonstrate
valve operability after the restoration of the system
back to original conditions
and cycled the -valves to demonstrate
operability.
violations or deviations
were identified.
8.
Enoineerino Safet
Feature
Ver ification
71710)
During this inspection period selected
portions of the containment
spray
system for Units
1
and
2 were inspected
to verify system configuration,
equipment condition, valve
and electrical
lineups,
and local breaker
positions.
violations or deviations
were identified.
8
9.
Loss of Deca
Heat
Removal
and T12
5
3
b.
Backaround
8
On October
17,
1988,
the
RRC issued'Generic Letter 88-17 .regarding
the potential
loss of decay heat
removal during nonpower operations.
This generic letter
was
due in part to
an event at Diablo Canyon in
April 1987 which highlighted previously unrecognized
concerns
associated
with reduced reactor coolant
system
(RCS) inventory
conditions.
As directed
by the generic letter, the licensee
responded
in submittals
dated
January
6, 1989, regarding expeditious
actions,
and
on February 6,
1989, regarding
proorammed
enhancements.
In addition,
the licensee
provided supplemental
responses
in letters
dated
January
17
and
Yiay 31,
1991.
NRC letters
dated April 26,
1989,
and August 22,
1991,
document
the completion of the
NRC's
review
and
acceptance
of the l,icensee's
responses.
Review
The
NRC inspector
reviewed the licensee's
responses
to Generic
Letter 88-I7 in accordance
with Temporary Instructions
2515/101
and
2515/103 to verify completion of the licensee's
actions
and to
verify that trainina
and procedures
were appropriate
to prevent
and
mitigate
a loss of decay heat removal.
Training lesson
plans
were
reviewed,
class
attendance
lists were checked,
and
a training video
tape
was reviewed.
The inspector
reviewed current plant procedures
and held discussions
with operations
personnel
to verify the
acceptability
of procedural
limitations, precautions,
and actions.
In general,
the licensee's
training
and procedures
were found to be
complete
and adequately
covered
the areas
specified in the generic
letter.
Because
of the licensee's
past
experience
with problems
when operating with
a reduced
RCS invenstory,
licensee
personnel
were
very sensitive to the potential
problems
and the
need for prompt
actions to limit any adverse
consequences;
The inspector verified that training had
been
conducted shortly,
after the April 1987 event at Diablo Canyon
and that reduced
inventory trainino continues
to be
a part of initial and
requalification trainino for licensed operators.
Specific training
in this
area
was conducted for licensed operators just prior to the
recent Unit
1 refueling outage
which occurred
in spring 1991.
In
addition, training of non-licensed
personnel,
such
as auxiliary
operators
and maintenance
personnel,
regarding
reduced
RCS inventory
operations
was also verified.
There
are
no specific administrative
provisions which require additional training prior to conducting
reduced
RCS inventory operations.
However,
based
on discussions
with licensee
personnel, it appears
that licensee
personnel
are
sufficiently sensitive to the potential
problems that the
need for
additional training would be considered
prior to actually or
potentially enterino
a reduced
inventory mode.
Such training
occurred prior to the Unit
1 refueling outage
in early 1991
even
thouoh reduced
inventory operations
were not planned.
Further
guidance
does
not appear to be necessary
at this time.
The inspector's
review of the applicable refueling,
abnormal
operating,
and administrative
procedures
showed that in general,
the
guidance
contained
in the generic letter
had
been incorporated'into
site procedures.
Appropriate precautions
and limitations'ad
been
specified to prevent,
monitor,
and mitigate the consequences
of
a
loss of decay heat
removal while under reduced
RCS invenihry
conditions.
However, the inspector
noted that in some
pr'ocedures
clarification and revision still needed
to be performed,
and
procedures
needed to be checked to assure
consistency
of
information.
The licensee
agreed to evaluate
and take appropriate
actions to address
these
issues.
The areas
of comment
are described
below:
New procedures
were developed
in the areas
of outage planning
(Administrative Procedure
ADS.DC52)
and diagnoses
of problems
with decay heat
removal
when in Modes
5 and
6 (Abnormal
Operating
Procedures
OP
AP SD-0 through 5).
These
procedures
.
contain additional
information not provided in other procedures,
such
as the
need to wait 42 days after shutdown
and to have
three containment
fan cooler units operating if the containment
water sealed
is to be used.
Abnormal Operating Procedure
AP-16, "Malfunction of the
System,"
needs to be revised to indicate it is applicable only
in Modes 1-4.
Operations
Procedure
A-2:III, "Reactor Vessel - Draining to
Half Loop Operations
with Fuel in Vessel,"
does
not have
sufficient guidance
in establishing
and maintaining containment
closure for other than the major penetrations.
Additional
guidance
appears
necessary
to assure
that other penetrations
which could
be open to outside
containment,
such
as
when
maintenance
on valves is being done,
are appropriately
controlled
such that the penetrations
could
be closed, if
required.
In addition, operations
management
recognizes that,
because
of the limited pressure
retaining capability of the
using only a water seal,
additional
guidance is
needed to effectively seal
the penetration
should containment
pressurization
occur.
This penetration
is used only during
outages
to bring temporary lines into containment,
such
as for
cleaning activities.
Procedure
AP SD-2,
"Loss of RCS inventory," should include
guidance
to open valve HCV-142 to establish
a gravity feed flow
path to the charging
pumps (step 7g).
Instructions for monitorino and trending
RHR pump motor
amps
are not described
in procedures.
10
The current mid-loop trouble alarm
(PK 02-21A) setpoint
specified for RCS temperature
is 190 degrees
F, although
procedure
A-2:III specifies that
RCS temperature
should
be
maintained
less that ]60 degrees.
In addition, the. alarm
setpoint for the wide ranoe
and narrow range reactor
vessel
refueling level indication system
(RVRLIS) has
not been
establi,shed
in the plant computer.
Current procedures
require
an additional
manager
to be present
whenever
midloop operations
are conducted;
however,
the
licensee
has
informed the
NRC that this commitment is no longer
necessary
based
on the administrative
actions
taken to prevent
and mitigate
a loss of decay heat removal.
This-is not yet
reflected in procedures.
During discussions
with licensee
pe'rsonnel,
the
NRC inspector
was
informed that evaluations
were being performed to assess
the
capability of the pathway resulting from the removal of'ressurizer
safety relief valves to function
as the hot leg vent path.
This
pathway would be in place of detensioning
the reactor
vessel
head
studs.
Removal of the safety relief valves is being explored
as
an
alternative
because
detensioning
of the reactor
head
and the
associated
steps
are viewed by the licensee
as
more complicated
and
with
a higher possibility for errors.
Because
an
RCS vent path
as
a
result of detensioning
the reactor
head
was discussed
in the
licensee's
response
to the generic letter, the licensee
was
requested
to inform the
NRC in writing should another
method of
venting
be proposed,
such
as through the safety relief valve
openings.
c.
~Summar
In general,
training
and procedures
covering reduced
RCS inventory
operations
appear
appropriate.
Progress
has
been
made in the
structure of procedures
and in refining the previous
procedures
to
reflect more current information
and analyses.
While this progress
appears
beneficial overall,
procedures
are currently in
a
transition.
The licensee
stated that appropriate
changes
to
procedures, will be made to address
the inspector's
comments,
as well
as those
changes
already being considered.
In the past,
because
the
licensee
has
not planned to perform reduced
RCS inventory operations
with fuel in the reactor vessel,
the procedure
revisions
have not
been
a high priority.
However, there is
a possibility that these
reduced
inventory operations
would be needed
unexpectedly
due to
a
tube leak or reactor coolant
pump seal
problem'.
It
is expected that the procedures
would be reviewed
and updated prior
to the performance
of reduced
inventory operations.
It is also
noted that reduced
inventory. operation
may be planned
in the latter
staoes
of the next'refueling
outages
should extended
inspection
and maintenance
activities occur.
0
11
'
This closes
the review of the licensee's
responses
The licensee's
corrective actions to the'above
comments will
be reviewed in future inspections
(Followup Item 50-275/'91-37-01).
No violations or deviations
were identified.
10.
Startup Activities - Unit 2
93702
71707)
a ~
b.
Hi
h Pressurizer
Safet
Relief Valve Tailpipe Temperature
- Unit 2
'uring the startup of Unit 2 from the recent refueling outage,
licensee
personnel
noted that pressurizer
safety relief valve 8010C
had
an elevated tailpipe temperature
indication of 'approximately
200-220
degrees
F.
Total leakage to the pressurizer relief tank
(PRT)
was monitored
and
was found to be 0.008-0.025
gpm.
Based
on
previous licensee
analyses,
on the safety relief piping
wil1 exist
up to
a leakage rate of 0.05
opm.
The
NRC inspector
had discussions
with licensee
personnel
to
determine
the significance of the leakage
and the monitoring which
would be performed during plant operations.
Based
on these
discussions,
the licensee will continue to monitor tailpipe
temperatures
and record
PRT in-leakage
rates
as already provided for
in alarm response
procedures.
In addition, the licensee
has
installed
a containment
monitor to display loop seal
temperatures
to
assure
that the loop seals exist.
temperatures will be
recorded
during routine entries into containment.
The
NRC inspector
.verified that the temperature
information was being recorded.
In
addition, the inspector verified that the licensee
had provided
operators
with specific guidance that the relief valves might not be
operable if high loop seal'emperatures
are observed.
Current
.tailpipe temperatures
for valve 8010C indicate
a downward trend.
Licensee
personnel
indicated that actions
had
been
taken to resolve
the leakage
problem
and that engineering activities are continuing
to determine
whether additional-system
or valve design
changes
would
be beneficial.
It is noted that Unit 1 safety relief valves
8010A
and
B also
have elevated tailpipe temperatures
(170-180 degrees
F).
The licensee
is monitoring the elevated tailpipe temperatures
and
is recording
PRT in-leakage for Unit 1.
Durino the
above discussions,
licensee
personnel
indicated that
an
evaluation
was being drafted which was intended to demonstrate
that
safety relief valves would still be operable without loop seals.
The licensee
plans to submit this eval.uation to the
NRC when completed.
Failure of Feeder
Breaker from Auxiliar
Transformer to 0 en
-. Unit 2
On October
23,
1991, during the attempt to transfer
the
4
kV vital
bus
H from the auxiliary transformer to the startup transformer,
the feeder
breaker
from the auxiliary transformer failed to open.
During subsequent
attempts
to open the auxiliary feeder breaker,
the
breaker
was observed
to have
smoke
coming from the cubicle.
The
control
power for the breaker
was
removed with the breaker still
providing power to bus
H.
The auxiliary feeder
breaker
was manually
tripped,
and
power
was provided to bus
H by the startup transformer.
12
The licensee's
investigation of the breaker failure revealed. that
the trip coil appeared
to have
become slightly misaligned with the
armature
assembly.
This misalignment
could- be sufficient to catch
the dropping armature,
when the trip coi 1 is energized.
'Since only
the force of gravity pulls the armature
out of the trip qoil,
a minor
interference
or misalignment
can reduce the
amount of arohture travel
and cause
the breaker to fail to trip.
This failure mech'anism
was
demonstrated
on. another similar breaker.
The failure of this breaker to trip is significant in that power to
a vital bus would not be provided.
Under plant conditions which
would cause
a transfer to the startup transformer,
such
as a.fault,
the failure of the breaker
to open could cause
an overcurrent
condition if the startup
power system
attempted
to also provide
power to the
bus or if the fault continued to exist
on the
system.
In addition, the diesel
generator
would be unable to
provide power to the
bus
because
of an interlock which prevents
diesel
oenerator
breaker closure if the auxiliary feeder breaker is
closed.
Therefore,
power to one of the three
4
kV vital buses
would
not
be provided.
The licensee
performed testing of the replacement
breaker
and
a
visual inspection of the alignment of similar breakers
in Units
1
and 2.
No other alignment problems
were identified.
The licensee's
evaluation is described
in
NCR DC2-91-EM-N095.
The
NRC inspectors
verified that visual inspections
without breaker
removal
could
determine
whether the coi 1
and armature
were properly aligned
and
that the licensee's
corrective actions
appeared
appropriate.
No violations or deviations
were identified.
ll.
Operator Simulator Trainin
41500
The
NRC inspector. observed requalification training for licensed
operators
which involved
a three
hour simulator
scenario
and
a one hour
critique session
(Lesson
No. LS-4-5A).
The scenario
involved the
successive
loss of
a component cooling water system
heat
exchanger,
a
generator
load reject,
a small
break
LOCA,
a large break
LOCA,
and
finally a loss of startup
power.
This training session
involved both
operations
personnel
and training instructors.
The crew positions
manned
were shift foreman,
senior control operator,
control operator,
auxiliary
control operator (2),
and shift technical
advisor.
The training scenario
emphasized
the
use of procedures
and the ability of
the crew to transition from one
emergency
procedure to another.
The crew
demonstrated
the understanding
of the
need to adhere
to procedures
in
a
stepwise
manner
and were able to transition
between
procedures.
The
critique session- highlighted the technical
issues
related to the scenario
and also the
need to follow procedures
even for routine evolutions.
The
inspector
noted that in the critique session
there
was little discussion
related to crew interactions
or individual performance.
Based
on
discussions
with the trainina supervisor
and
a supervisor
involved in the
13
training session
witnessed
by the inspector, it appeared
that the licensee
i~i~-ii'c~~ that more
can
be done to strengthen
the crew interactions
area.
The training manager
and operations
management
indicated that this area
had
been reviewed in the past
by the operations director
and this:area
would be
given further operations
management
attention.
12.
Exit
On November
22,
1991,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspector
summarized
the
scope
and findings of the inspection
as described
in this report.
I
I