ML16342D352
| ML16342D352 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 06/21/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342D350 | List: |
| References | |
| 50-275-96-09, 50-275-96-9, 50-323-96-09, 50-323-96-9, NUDOCS 9606280131 | |
| Download: ML16342D352 (58) | |
See also: IR 05000275/1996009
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos:
License
Nos:
50-275,
50-323
DPR-SO,
Report
No:
50-275/96009,
50-323/96009
Licensee:
Paci fic Gas
and
El ectri c Company
(PGE E)
Facility:
Diablo Canyon
Power Plant,
Units
1 and
2
Location:
Avila Beach, California 93424
Dates:
April 14 - May 25,
1996
Inspectors:
M. D. Tschiltz, Senior Resident
Inspector
S.
A. Boynton,
Resident
Inspector
J. J. Russell,
Resident
Inspector,
San Onofre Nuclear
Generating Station
G.
W. Johnston,
Senior
Project Inspector
Approved by:
H. J.
Wong, Chief, Reactor Projects
Branch
E
Division of Reactor Projects
9606280i3i 96062i
ADQCK 05000275
8
0
EXECUTIVE SUMMARY
Diablo Canyon
Power Plant,
Units
1
8
2
NRC Inspection
Report 50-275/96009,
50-323/96009
This report covers
a six-week period of resident
inspection,
which
incorporated
operational
safety verification, maintenance
observations,
surveillance observations,
onsite engineering,
and plant support activities.
Draindown of the reactor coolant system
(RCS) to mid-loop operation
was
well controlled.
However, operators failed to recognize
the impact of
the failure of containment
fan cooler unit
(CFCU) 2-5 on the draindown
requirements
until prompted
by the inspector
(Section 01.2).
Hultiple incidents related to the fuel handling building ventilation
(FHBV) system demonstrate
that licensee
actions to maintain operability
of the
FHBV system during movement of loads over the spent fuel pool
have not been fully effective.
LER 50-323/96009-01
described
the
failure to maintain available the emergency
power source for the only
fuel handling building ventilation system during the
Unit 2 refueling outage.
A violation was identified (Section 08. 1).
Maintenance:
A maintenance
procedure for the emergency diesel
generator
(EDG)
governor actuator
improperly referenced
an excessive
torque value for
the bolted connection of the actuator to its mounting bracket.
The high
torque value,
coupled with less
than full thread
engagement
of the
governor mounting capscrews,
contributed,
in part, to the cracking of
the mechanical
governor mounting brackets
on
EDGs 1-3 and 2-2
(Section Ml.l.3).
The inspectors
identified
a non-cited violation during the adjustment of
(AFW)
Pump 2-1 trip throttle valve linkage.
The
adjustment
was not performed in accordance
with the applicable
maintenance
procedure
in that all bolts for the
end bearing
housing
were
not installed nor torqued
as specified
(Section Ml.l. 1).
i
The licensee failed to perform
a safety evaluation
in accordance
with
when it developed
the equipment control guideline that
allowed the
use of a temporary jumper to supply non-vital
power to the
spent fuel pool
(SFP) cooling pumps.
A violation was identified
(Section
E1.3).
The licensee failed to properly track its commitment to replace
the main
steam isolation valve (HSIV) actuator pins
on Unit 2 during 2R7.
As
a
result,
pin replacement
was not scheduled
in the Unit 2 outage until
questioned
by the inspector
(Section E1.2).
The inspectors
identified
a prompt operability assessment
which non-
conservatively credited the use of Class II pressurizer
power operated
relief valve automatic actuation circuits.
The crediting of the
automatic actuation circuitry was concluded to be inappropriate.
However, other factors could
be credited
and therefore
no actual
safety
issue existed
(Section El.3).
Re ort Details
Summar
of Plant Status
Unit
1 began this inspection period at
100 percent
power.
The unit remained
at full power throughout the inspection period.
Unit 2 began this inspection period in Hode
6 for seventh refueling outage
(2R7).
On Hay 9, the unit entered
Hode
5 and
Hode
1 on Hay 24.
The unit was
in Hode
1 undergoing
power ascension
at the
end of the inspection period.
I. 0 erations
Ol
Conduct of
Operations'1.
1 General
Comments
71707
The inspectors
conducted
frequent reviews of ongoing plant operations.
The conduct of operations,
including refueling operations,
was generally
professional
and safety-conscious;
specific events
and noteworthy
observations
are detailed in the sections
below.
The Seni.or Resident
Inspector
conducted
a review of recent Institute of Nuclear
Power
Operations
(INPO) evaluations. completed during this inspection period.
No additional followup actions
are considered
warranted.
01.2
RCS Draindown to Hidloo
Unit 2
a.
Ins ection
Sco
e
71707
The inspectors
observed
operators
drain the reactor coolant
system
(RCS)
to midloop in preparation for removal of steam generator
nozzle
dams.
The inspectors
reviewed the governing procedure,
OP A-2:III, Rev.
8,
"Reactor Vessel - Draining to Half Loop/Half Loop Operations
With Fuel
in Vessel."
b.
Observations
and Findin
s
Pre-evolution briefing: Procedure
OP A-2:III had
been substantially
revised just prior to the
2R7 refueling outage.
These revisions
included additional prerequisites,
clarifications to the precautions
and
limitations,
and additional details to the procedure
steps that describe
the draindown methodology.
The inspectors specifically focused
on the
effectiveness
of those
procedure
revisions
and evaluated
operator
awareness
of their impact.
'Topical headings
such
as 01,
H8, etc.,
are
used in accordance
with the
NRC standardized
reactor inspection report outline.
Individual reports
are
not expected
to address
all outline topics.
C'
Revisions
were
made to improve the content of the pre-evolution
tailboard.
The tailboards
conducted
by the operations
manager
and the
shift foreman
(SFM) were done well.
The operations
manager
discussed
management
expectations
for conduct of this high risk, infrequent
evolution in accordance
with licensee
administrative
procedures
and
included
an emphasis
on procedure
adherence
and the application of
conservative
decision-making while deemphasizing
schedule.
The briefing
was clear
and expectations
were emphasized
from a safety perspective.
The SFN's tailboard discussed
the specific prerequisites,
precautions
and limitations,
and procedure
steps.
Crew assignments
were delineated
and opportunities
were provided for personnel
to ask questions
about
their roles.
The briefing was,
in part,
combined with the verification
of the procedure prerequisites.
This ensured that operators
were fully
aware of all prerequisites
and
any discrepancies
where prerequisites
had
not yet been satisfied.
The briefing was comprehensive
and operator
discussions
demonstrated
a high level of knowledge of the procedure.
The draindown to midloop (108'levation)
was well controlled.
Associated
equipment
and instrumentation
performed
as expected.
Containment
Fan Cooler Unit (CFCU): During the 'draindown to
a hold point
at 109',
post-maintenance
testing of the
CFCUs revealed that
CFCU 2-5
would not start in slow speed.
CFCU 2-5 was
one of two fan coolers
being relied upon to satisfy
a prerequisite of Procedure
OP A-2:III.
However,
the operator performing the testing failed to notify the
SFN of
the degraded
condition.
The inspector
questioned
how the requirements
of Procedure
OP A-2:III were being met.
The
SFH acknowledged that
CFCU
2-5 could not be relied upon,
but noted that
CFCUs 2-3 and 2-4 were
still available to satisfy the procedural
requirements for the
draindown.
Although both
CFCU 2-3 and 2-4 were available to start in
fast speed,
component cooling water
(CCW) flow to
CFCU 2-4 was less
than
the
1650 gallons per minute
(gpm) minimum required
by Procedure
OP A-
2: III.
The inspector
noted this to the
SFH,
who took prompt action to
raise
CCW flow to
CFCU 2-4.
The requirement for availability of CFCUs during
RCS draindown to
midloop conditions is to assure
continued operability of temporary
service
connections
installed through several
containment
for refueling operations.
The
CFCUs would function to limit containment
pressure
on the loss of the residual
heat
removal
system.
Licensee
calculations
showed that two CFCUs must
be available to operate
in fast
speed with a minimum
CCW flow of 1650
gpm when core decay heat loads
are
greater
than 7.5
MW.
With core decay heat less
than 7.5
HW (as in this
case),
the calculations
showed that only one
CFCU is needed.
Conclusions
Operators
were knowledgeable
on the revised
draindown procedure
and the
evolution was controlled well by the
SFH.
The tailboards
conducted
by
0
02
02.1
the operations
manager
and
SFM were effective in emphasizing
safety
during this high risk evolution.
Weaknesses
in communications
between
the operator
and the
SFM regarding the failure of CFCU 2-5 to start,
resulted
in the
SFM being unaware, until prompted
by the inspector,
that
a prerequisite of Procedure
OP A-2:III was not being satisfied.
Operational
Status of Facilities
and Equipment
Unit 2 Residual
Heat
Removal
S stem Walkdown
a
~
Ins ection
Sco
e
71707
b.
The inspector
performed
a detailed
walkdown of accessible
portions of
the Unit 2 residual
heat
removal
(RHR) system.
Observations
and Findin
s
C.
On May 22,
1996, the inspector
noted that the material condition of
system
components
and area
housekeeping
of the accessible
portions of
the
RHR system
were generally good.
The inspectors
did observe
some
and oil leaks
and informed the licensee.
The discrepancies
were evaluated
by the licensee for repair.
The inspector also performed
a detailed
walkdown of the system. configuration,
reviewed the alignment
verifications for plant startup
(Procedure
OP B-2: 1,
Rev. '12,
"RHR
System Alignment Verification for Plant Startup"),
and Operating
Valve
Identification Diagram
(OVID) 107710,
Revision
18,
and found no
discrepancies.
Conclusions
. 08
08.1
The configuration of the
RHR system
was in accordance
with the
OVID and
system alignment
used for the Unit 2 plant startup
from the Cycle
7
refueling outage.
Material condition of the system
was generally good,
with only minor discrepancies
noted.
Miscellaneous
Operations
Issues
Closed
LER 50-323 96-02
Rev.
0, violation of Technical Specification (TS) 3.9. 12 during crane operations
with loads over the spent fuel pool.
Specifically, the operable train of the Fuel Handling Building
Ventilation
(FHBV) system
was not capable of being powered
from an
emergency
power source.
The violation occurred during 2R7.
The root cause of the violation was
personnel
error.
Specifically,
a senior licensed operator failed to
recognize
the impact
on
TS when
he opened
the supply breaker for the
exhaust
fan to the only FHBV train with an operable
emergency
power
source.
The operator misunderstood
instructions to simply walkdown the
clearance
package
and instead
thought the instructions
were to implement
the clearance.
A similar failure to maintain
an adequate
emergency
0
7
power supply for the
FHBV system occurred during the Unit
1 refueling
outage in October
1995.
The violation is discussed
in
LER 50-275/95-06,
Rev.
0.
In addition,
several
other incidents occurred during the Unit 2 outage
where personnel
moving equipment
and materials
in and out of the fuel
handling building (FHB) improperly propped
open ventilation boundary
doors.
Although personnel
involved with fuel handling operations
in the
FHB responded
promptly to these
incidents,
the incidents did impact the
operability of the
FHBV system until the problems
were noted
and
corrected.
This violation of TS was identified by the licensee
and the licensee's
evaluations of similar past violations determined that the root causes
were
somewhat different.
Notwithstanding those factors,
the multiple
occurrences
of failure to maintain the
FHBV system operable
when
required
by TS indicate that licensee
actions to maintain operability of
the
FHBV system during movement of loads over the spent fuel pool
have
been ineffective.
As such
LER 50-323/96-02,
Rev.
0, will be
dispositioned
through issuance
of a violation of TS 3.9.12
(VIO 50-
323/96009-01).
Corrective actions will be tracked
by this violation.
The Unit
1 event described
in LER 50-275/95-06,
Rev.
0, remains
open
pending further
NRC review.
II. Maintenance
Ml
Conduct of Maintenance
Ml. 1
Maintenance
Observations
a.
Ins ection
Sco
e
62703
The inspectors
observed all or portions of the following work
activities:
R0151677
R0153820
C0139816
C0139232/
C0139230
R0152357
Preventive
Maintenance of Limitorque Motor Operator
for SW-1-FCV-495, Unit
1 Auxiliary Saltwater
(ASW)
Supply to
ASW Cross-tie
Clean,
Inspect,
and Test Unit
1
ASW Pump
12 Motor
Replace
Containment
Pressure
Transmitter
2-PT-935
Installation of 4
kV Breakers
EDG 2-1 Maintenance
b.
Observations
and Findin
s
The inspectors
found the work performed
under these activities to be
professional
and thorough.
All work observed
above
was performed with
0
-10-
the work package
present
and in active use.
Technicians
were
experienced
and knowledgeable of their assigned
tasks.
The supervisors
and system engineers
frequently monitored job progress.
guality control
personnel
were present
when required
by the procedure.
When applicable,
appropriate radiation control
measures
were in place.
The inspectors
have noted continuing material condition problems
and
cleanliness
issues with the Unit
1
EDGs.
Host notably was
EDG 1-2.
Various minor lubricating oil and fuel oil leaks
were readily apparent,
especially
in the areas of the crankcase
exhauster
motors, starting air
motors
and the engine mechanical
overspeed trip mechanism.
Without
adequate
cleanup of these
areas it may be difficult to pinpoint the
exact location of the leak and effect repair,
when necessary.
In
addition, the buildup of oil in these
areas
has the potential to mask
additional
problems.
In addition, selected
maintenance
observations
are discussed
below.
Turbine Driven AFW Pum
2-1 Haintenance
Ins ection
Sco
e
62703
On April 27, the inspector
observed partial
performance of Diablo Canyon
Haintenance
Procedure
(HP) H-4. 14,
Rev 5, "Auxiliary Feedwater
Pump
Turbine Haintenance."
The maintenance
being performed
was the
adjustment of the overspeed
disc.
Observations
and Findin
s
During the set
up of the overspeed trip disc, the inspector
noted that
the maintenance
personnel
were not referring to the procedure.
The
notebook containing the procedure
was nearby,
but was closed.
The
inspector questioned
several
differences
observed
between
the way the
set
up was being accomplished
and that specified in the procedure
(Step
7; 10. 15).
The workers explained that certain portions of the
procedure
were not very well written and specified tasks
were not
necessary
for the work.
The inspector
noted that the bearing
housing
was put in place with 2 of
the
4 bolts installed finger tight to hold the bearing
housing in place
when adjusting the trip throttle valve linkage,
whereas
Step 7. 10. 15 of the procedure
specified the that all of the bearing
housing bolts
be installed
and torqued for the set
up.
When the
inspector questioned this, the workers responded
that it was not
necessary
to install all of the bolts
and that there
was not
a specific
torque requirement for the bolts.
The maintenance
personnel
noted that
the installation of the bearing
housing
was not critical to the set
up
of the linkage
and that it was not necessary
to install
and torque all
of the fasteners.
0
-11-
C.
At the conclusion of the observations,
the inspector notified the
mechanical
maintenance
foreman of concerns
regarding
compliance with the
maintenance
procedure.
In response
to these
concerns
action request
(AR) A0401140
was written.
After reviewing the issues
the licensee
revised
Procedure
MP M-4. 14 to not require the bolts to be torqued
and
reperformed
Step 7. 10. 15.
There
was
no safety
consequence
as
a result
of deviating from the procedure.
Conclusions
The failure to perform work on the turbine driven
AFW pump in accordance
with written procedures
was identified as
a violation of TS 6.8. 1.
This
failure constitutes
a violation of minor significance
and is being
treated
as
a non-cited violation, consistent
with Section
IV of the
NRC
Enforcement Polic
(NCV 50-323/96009-02).
M1.1.2
Re lace Containment
Pressure
Transmitter 2-PT-935
a. 'ns ection
Sco
e
62703
The inspector
observed
a portion of the work to relocate
a containment
pressure
transmitter outside of containment that was being performed in
accordance
with Design
Change
Notice
(DCN) 2-SJ-50102,
"Replace
Containment
Pressure
Transmitters."
Other documentation
reviewed
included:
b.
WO C0139816,
Barton
Rosemount
Changeout
Implement DCP-J-50102,
Unit 2 Containment
Pressure
Transmitter
upgrades
Observations
and Findin
s
C.
The inspector
noted that the work package
was being maintained
up to
date for the work in-progress
and that the individual responsible
for
performing the tubing welds associated
with the
DCN was knowledgeable
of
the requirements.
One inconsistency
existed in the work package
in 'that
the filler material
usage
log incorrectly listed the traceability
number
for the weld filler material
being used for the work.
The weld
inspection
plan indicated the correct weld filler material traceability
number in the remarks.
The personnel
performing the work corrected this
deficiency.
Conclusions
The work observed
was accomplished
in accordance
with the instructions
of the
DCN.
The personnel
involved were knowledgeable
with the
requirements
associated
with the work.
0
~ -12-
EDG 1-3 Mechanical
Governor Mount
Ins ection
Sco
e
62703
During replacement
of the
EDG 2-2 mechanical
governor,
licensee
personnel
identified that the mechanical
governor mounting bracket
had
cracked during installation of the replacement
governor.
The inspector
reviewed the event,
performed
walkdown of other
EDGs,
and reviewed
applicable
references
associated
with the governor replacement.
Observations
and Findin
s
Based
on the identification of the cracked
mounting bracket,
the
inspector walked
down the
EDGs for both Units
1 and
2 for similar
conditions.
The
EDG 1-3 bolting configuration
was similar to that of
EDG 2-2.
All four mounting cap screws
were of insufficient length to
provide full thread
engagement
into the mounting bracket.
A crack
existed in the mounting bracket originating at one of the internally
threaded
holes.
The inspector
reviewed
Procedure
HP H-21.8,
Rev.
14, "Diesel
Engine
Governor Actuator,"
and noted that the procedure
specified the steps for
removal
and replacement
of the
EDG mechanical
governor.
Work Order
C0137908 replaced
the
EDG 1-3 mechanical
governor in October
1995
and
referenced
Procedure
HP H-21.8 for this activity.
Procedure
HP H-21.8
required the mounting cap screws to be torqued to
a value of 65 ft-lbs
upon installation of the
new governor.
This torque value was derived
from guidance
contained
in HP H-54. 1,
Rev.
10, "Bolt Tensioning,"
and
was based
upon the cap screw material
(SAE Grade 5).
However, that
torque value
assumes
a connection
where the bolt and nut are of similar
material
and strength.
The internally threaded
mounting bracket
was
manufactured
from the American Society for Testing
and Materials
(ASTH)
48 Class
30 cast iron.
As such,
the minimum tensile strength of the
internal
threads
is significantly lower than that of the
SAE Grade
5 cap
screw.
The proper torque for the cap screws threading into ASTH 48
Class
30 cast iron was determined
by the licensee
to be
24 ft-lbs.
This
appears
to be the cause of the cracked
mounting bracket.
Attachment 8. 12 of Procedure
HP H-54. 1 discusses
proper thread
engagement
for internally threaded
components.
As
a guideline,
Attachment 8. 12 recommends
that the thread
engagement
be at least
1 1/8
times the diameter of the bolt to ensure full bolt strength is achieved.
For the mechanical
governor mounting cap screws, full thread
engagement
of the mounting bracket thickness
is needed
to meet this guideline.
EDGs 2-2
and
1-3 were noted to have governor mounting bracket fasteners
with less
than full thread
engagement.
Even though the licensee
made
an initial determination that the
EDG 2-2
mechanical
governor mounting bracket failure was maintenance
induced,
the licensee
did not promptly inspect
the other
EDG mechanical
governors
C.
-13-
for similar problems.
Following the inspectors'dentification
of the
discrepancies
associated
with the
EDG 1-3 mechanical
governor
(cracked
bracket
and less
than full thread
engagement),
the licensee
inspected
the remainder of the
and developed
a prompt operability assessment
(POA) for
EDG 1-3 based
upon the as-found conditions.
The
POA appeared
to appropriately
address
the relevant
issues
and
concluded that the governor mounting would satisfy requirements
with
three of the four bolts with the existing thread
engagement.
The
licensee
subsequently
replaced
the cap screws
on
EDG 1-3 with ones
recommended
in the vendor's
replacement
parts list and plans to replace
the cracked
mounting bracket during the next refueling outage.
Conclusions
Both the improper torquing
and the lack of full cap screw thread
engagement
contributed to the cracking of
EDG 1-3 and
EDG 2-2 mounting
brackets.
The licensee's
failure to identify the degraded
condition of
the governor mounting bracket
on
EDG 1-3 until prompted
by the inspector
is considered
to be
a negative finding.
Hl. 1.4
Class
1E Breaker Failures
a 0
Ins ection
Sco
e
62703
b.
The licensee
informed the inspector that newly installed Unit 2 Class
lE
4 kV breakers
had experienced
certain failures during surveillance
testing.
The inspector interviewed cognizant
personnel
and inspected
some of the breakers.
In addition,
a conference call
was held between
licensee electrical
maintenance
personnel,
the inspector,
and Region
IV
inspectors
on Hay 16,
1996.
Observations
and Findin
s
The inspector
observed that during the current refueling outage
(2R7)
the licensee
replaced
the General
Electric Hagne Blast
4
kV breakers
installed
on the Unit 2 Class
lE 4
kV switchgear,
and the associated
feeder breakers.
The
new breakers
were
Power Distribution Systems
350
HVA Sulfur Hexafluride breakers
and
have
an increased
reactive
load
interruption capacity.
During post maintenance
testing,
several
breakers failed to either
open or close
upon
demand.
The licensee
identified three
problems with the
new breakers
and the breaker cubicle
interface.
The secondary
disconnect
pins
on the breaker
had
been
deformed
by
maintenance
personnel
while using
a test connection.
Corrective
actions
were to re-verify configuration
and install harder pins
during regularly scheduled
preventive
maintenances
(PHs).
~
The gap
between
the plunger rod and the static auxiliary switch
mounted
on the cubicle
had not been properly adjusted
by
maintenance
personnel
during installation
and set
up.
Corrective
actions
were to re-verify the gap
and revise the breaker rack-in
procedure to incorporate
a second
check of the gap following rack-
in of the breaker.
~
The positive interlock roller on the breaker
was out of position
in the V-notch on the cubicle due to closer tolerances
than the
licensee
anticipated.
Corrective actions
were to re-verify the
position
and enlarge
the V-notch on cubicles
as
needed.
The inspector
found that the problem identification was good
and
corrective actions
demonstrated
a level of concern appropriate
to the
circumstances.
The inspector
also found that electrical
maintenance
personnel
did not meet
management
expectations
in setting the plunger
rod gap during initial installation of the breakers.
c.
Conclusions
The licensee
implemented
a prompt investigation of the problem and the
corrective actions
implemented
appear appropriate.
M1.2
Surveillance
Observations
a.
Ins ection
Sco
e
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 the 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.
The inspectors
observed all or portions of the following surveillance:
STP M-9A, Rev.
39, "Diesel
Engine Generator
Routine Surveillance
Test,"
(EDG 2-1)
STP M-SIA, Rev. '7, "Diesel
Engine Generator
Inspection
(18 Month
Intervals),"
(EDG 2-1)
STP M-13G,
Rev.
13,
"4 kV Bus
G Non-SI Auto-Transfer Test"
(Unit 2)
P-ASW-22,
Rev.
2, "Routine Surveillance
Test of Auxiliary
Saltwater
Pump 2-2"
-15-
b.
Observations
and Findin
s
Hl.2.1
The inspectors
found that the surveillance
reviewed and/or observed
were
being scheduled
and performed at the required frequency.
The procedures
governing the surveillance tests
were technically adequate
and personnel
performing the surveillance
demonstrated
an adequate
level of knowledge.
The inspectors
also noted that test results
were appropriately
dispositioned.
In addition, selected
surveillance
observations
are discussed
below.
Emer enc
Core Coolin
S stem
Flow Balance Test
a
~
Ins ection
Sco
e
61726
b.
The inspectors
observed
portions of the
ECCS flow balance test that
measure
the charging injection flow into the reactor coolant
system cold
legs
and safety injection flow into the cold leg
and hot leg portions.
The procedure utilized for the test
was Procedure
STP V-15,
"ECCS Flow
Balance Test."
The inspector
also reviewed
which specifies
the requirements
for ECCS flow testing, following modifications which
alter
ECCS subsystem
flow characteristics.
Observations
and Findin
s
The tailboard briefing prior to the
commencement
of the testing
was
thorough with close
involvement of the
SFH and the cognizant Test
Director leading the discussion.
The briefings stressed
communications,
data gathering,
system configuration,
and clearance
status.
The testing
observed
was performed
in
a controlled manner
and the Test Director and
operations
personnel
involved with the test were knowledgeable of the
system alignment for testing
and the test requirements.
Data gathering
and calculations for the safety injection (SI) portion of
the test indicated the cold leg flow values
were very close to those
predicted,
with all flows within about
2 gpm.
The cognizant test
engineer
had supporting calculations
done both manually
and with a
dedicated
computer program.
The hot leg flows exceeded
the acceptance
criteria by 4 gpm, the flows were subsequently
balanced.
The resulting
flow confirmed the proper sizing of the replacement orifice (installed
during the
pump replacement).
During the charging portion of the test,
flow was initiated into the
refueling cavity.
Prior to initiating flow, the Test Director requested
that the control operator
(CO) adjust chemical
and volume control
system
(CVCS) flow control valve
(FCV)
128 to obtain
a charging flow rate of
approximately
60 gpm.
The inspector questioned
the Test Director, since
the flow rate
was less
than the
78 to 80 gpm specified
by the procedure.
The Test Director indicated
concern that the centrifugal
charging
(CC)
pump would exceed
the
pump runout flow rate limit if FCV-128 was
-16-
adjusted
as specified in the procedure.
The
CO initially adjusted
the
charging flow to 60 gpm.
The Test Director informed the
SFH that the
flow had
been
adjusted
to 60 gpm vice the
78 to 80 gpm specified in the
procedure.
The inspector questioned
the
SFH whether it was acceptable
to adjust charging flow to 60 gpm vice the 78-80
gpm specified
by the
procedure.
The SFH,then directed that the charging flow be increased
to
78-80
gpm as directed
by the procedure
and provided guidance for the
CO
to closely monitor the
CC pump flow to ensure that it did not exceed
the
run-out flow rate limit.
The SFH's oversight of the evolution failed to
note that the Test Director was deviating from the procedure prior to
the inspector questioning
the actions.
Subsequently,
when charging
injection was aligned to the reactor cavity and total charging flow, the
increase
in flow did not cause
the
pump to approach
the
pump run-out
limit.
The initial test results
indicated
a differential flow between
the cold
legs of approximately
8 gpm.
The acceptable
difference specified in
Procedure
STP V-15 is less
than
5 gpm.
The surveillance
acceptance
criteria was established
below the
TS limit of 20 gpm to allow for
inaccuracies
in flow measurements
and to provide additional
conservatism
in the analysis.
After verifying the fill and vent of the flow
measurement
instrumentation,
the licensee initially considered that the
line-to-line flow imbalance
was
caused
by the partial
blockage of ECCS
throttle valve (SI-2-8810D).
After throttling open SI-2-8810D test
results
indicated
a cold leg flow differential of less
than
5 gpm.
When
reverifying cold leg flow after locking SI-8810D, the flow through the
valve increased
above the acceptance
criteria requiring that the valve
be somewhat throttled down.
The licensee
investigated
the change
in flow and attributed the change
to the valve throttling characteristics.
Valves SI-2-8810A-D are globe
valves that have
been severely throttled with approximately
0. 13 inches
between
the disc
and seat.
This configuration results in high
cavitation loads
on the valve disc.
Since the valve disc is not rigidly
attached
to the stem,
the disc can
move
and reposition with flow through
the valve.
The licensee
reviewed past test results to assess
the impact
of the change
in flow caused
by the limited amount of valve disc
movement.
Changes
in line-to-line imbalance
between
the beginning
and
end of cycle have
been
as
much
as 4.9
gpm after accounting for
instrument uncertainty.
The variation in flows noted
between
the
beginning
and
end of cycle has not resulted
in exceeding
TS limits.
The
licensee
performed radiography of the valves which did not reveal
any
degradation
of the valves.
The licensee
plans to install'a pressure
reducing orifice in the individual branch lines upstream of the valves
(SI-8810A-D) to lessen
the
amount of throttling necessary
to meet the
flow requirements.
c.
Conclusions
-17-
The inspector
concluded that the portions of Procedure
STP V-15 that
were observed
were performed appropriately.
The conduct of the testing
was controlled
and the test activities
had close oversight
by the
operators.
The Test Director exceeded
his authority when
he failed to
consult with the
SFH, prior to deviating from the procedure.
This is
a
negative finding which is indicative of a lack of sensitivity to
procedural
compliance.
N2
Haintenance
and Material Condition of Facilities
and Equipment
M2. 1
Auxiliar
Pum
1-2 Bearin
Oil Rin
a.
Ins ection
Sco
e
62703
On Hay 21, operations
declared
AFW pump 1-2 inoperable
when engineering
personnel
identified that the pump's outboard bearing oil ring had
become misaligned.
The inspectors
reviewed the licensee's
actions to
restore
pump operability and their evaluation of the root 'cause of the
problem.
b.
Observations
and Findin
s
The deficiency was identified through engineering
walkdown of the
pump.
This walkdown was conducted
by engineering
personnel
based
upon
similar conditions
found during maintenance
of AFW Pump 1-2 during
outage.
1R7.
Based
upon the ring misalignment,
the
pump was declared
and
WO C0145063
was issued to replace
the oil ring.
Inspections
of the other motor-driven
AFW pump bearings did not identify
any similar deficiencies.
The licensee
determined that mispositioning of the oil ring was likely
caused
by small deformations
in the locking nut located just inboard of
the oil ring retainer.
During pump operation,
the oil ring rides along
the retainer
and
has incidental contact with the outboard
surface of the
locking nut.
The deformations
in the locking nut were hypothesized
to
be sufficient to disengage
the oil ring from the retainer.
The licensee
determined that the
damage to the locking nut was caused
by
the use of improper tools to tighten the nut during installation.
The
locking nut is manufactured
with notches
and is specifically intended to
be tightened with a spanner
wrench.
Maintenance
personnel,
however,
had
used
a piece of bar stock
and
a hammer to tighten the locking nut.
The
use of the bar stock in the notches of the locking nut deformed the
edges of the notches.
4
c.
Conclusions
-18-
The initial discovery of the problem
and subsequent
followup actions
by
engineering
personnel
were considered
to be positive findings.
The use
of improper tools which deformed the locking nut and potentially
affected the operability of AFW pump 1-2 was considered
a poor
maintenance
practice.
This was considered
as
a maintenance
preventable
failure .and
a quality evaluation
has
been written on the problem.
M2.2
Load Shed
Rela
Failure
a.
Ins ection
Sco
e
61726
The inspector
observed that during performance of Unit 2 surveillance
test procedure
(STP)
M 13G, Revision
13A, "4 kV Bus
G Non SI Auto
Transfer Test,"
on Class
1E 4 Kv Bus
G on May 13,
1996,
a load shed
relay failed to reset.
This caused auxiliary saltwater
(ASW) and
component cooling water
(CCW) loads to trip free when re-sequenced
on
the bus.
The inspector interviewed cognizant
personnel
and
a conference
call
was held
on May 16,
1996,
between
the inspector, electrical
maintenance
personnel,
and Region
IV personnel.
b.
Observations
and Findin
s
The licensee utilized diagnostic
equipment
and attempted to repeat
the
failure with the original components
installed.
The failure did not
recur.
The licensee
successfully
performed
Procedure
STP M-13G and
a
subsequent
surveillance test of this relay found no failures.
The
licensee
informed the inspector that this load
shed relay did not have
a
history of failure.
The licensee
did not replace
any components
and
declared
the load shed relay operable
based
on the successful
completion
of the surveillance.
c.
Conclusions
The inspector
concluded that the licensee
had taken
adequate
actions to
attempt to repeat
the problem
and
had
been
unable to do so.
The
licensee
appeared
to have sufficient rationale to declare
the relay
even though
a definitive root cause
was not determined
due to
the inability to repeat
the problem.
H8
Miscellaneous
Maintenance
Issues
MS. 1
Pum
2-2
92902
pump 2-2 was replaced
in February
1996,
when
a
loud noise
from the
pump occurred during surveillance testing.
Testing
of the replacement
pump revealed
no unusual
noises.
Subsequent
surveillance testing
and refueling outage testing of the
new SI
pump has
shown normal
response
characteristics.
0
-19-
The
pump that
was
removed
from the system
was sent to the Westinghouse
Service
Center in Spartanburg,
South Carolina to perform inspections
to
determine if there
were
any anomalies with the
pump.
The evaluation
report documented
the results of the
pump disassembly
and inspection.
In general,
the report indicated that the
pump was in very good
condition
and
showed
no sign of damage or obvious wear.
The inspection results
were determined to be representative
of normal
pump wear
and usage;
however,
there were out of tolerance
readings
obtained for the
pump shaft run-out.
Additionally, although Locktite
had not been applied to the impeller lock-nuts during the previous
assembly,
the locknuts were found to be tight.
The lower half of the
drive end bearing
had
a round spot approximately I/2 inch in diameter
that
was attributed to friction; however, there
was
no sign of
deformation.
The inspection did not reveal
any readily apparent
cause
for the abnormal
pump noise.
The inspector
concluded that the licensee
had closely monitored
the performance of the SI
pump to determine
the appropriate
time
for pump replacement
and took conservative
actions to evaluate
the
cause of noises
in the vicinity of the
pump.
Closed
Violation 50-275 95014-01, failure to properly perform
surveillance testing required
by TS.
TS 4.8. 1. 1.2a.2 requires,
in part,
periodic surveillance testing that verifies that
EDGs start from ambient
conditions
and accelerate
to at least
900 rpm in less
than or equal to
10 seconds.
The inspector previously identified that the licensee
was
conducting
TS required
EDG testing with elevated
diesel
lube oil and
jacket water temperatures
at the start of the test.
The licensee's
procedures
for
EOG testing did not define diesel
generator
ambient conditions.
Further review revealed that several
surveillance tests
had
been initiated with elevated
jacket water temperatures.
In all cases,
with the exception of EDG 1-2,
testing
conducted
at elevated
temperatures
had
been
superseded
by more
recent
EDG testing initiated from ambient conditions.
At the time of
the inspection,
the most recent
6-month surveillance test for
EDG 1-2
had
been initiated with elevated
lube oil and jacket water temperatures.
After identifying this discrepancy,
the licensee
was slow to take
corrective actions to reperform
EDG 1-2 surveillance testing.
The
Technical
Review Group assigned
to review the issue
concluded that the
previous
EDG testing
had not satisfied
TS requirements
and
as
a result
EDG 1-2 was declared
inoperable until the surveillance testing
was
satisfactorily completed.
The surveillance results
demonstrated
that
EDG 1-2 in fact met
TS operability requirements.
The licensee
documented
the failure to properly perform
TS required surveillance
testing in LER 50-275/95-10,
Rev.
0 and
1.
-20-
The inspector
reviewed the corrective actions 'delineated
in the
licensee's
response
to the violation. The inspector
reviewed Revision
39
to STP M-9A, "Diesel
Engine Generator
Routine Surveillance Test."
The
revision specified the required
engine lube oil and jacket water
temperatures
for testing initiated from ambient conditions.
The
procedure
specified
a temperature
band of 90 to 120
F which is within
the range of lube oil and jacket water temperatures
normally maintained
by the associated
keep
warm systems.
This corrective action provided
specific guidance for the performance of testing
and addressed
the
inspector's
concerns.
The licensee
also performed
a review of other
TS
requirements
to verify proper implementation of testing requirements
and
did not identify any other discrepancies.
The inspector
reviewed
case
study ¹55 initiated in response
to the
violation.
The case
study documented
the lessons
learned to be shared
with the personnel
as they apply to their specific jobs
and
responsibilities.
The case
study concluded that although the
TS ambient
condition requirements
were not clear,
the licensee
had not previously
questioned
how the testing complied with TS.
The case
study also
concluded that improved communications
between the inspector
and
engineers
could have led to
a better understanding
of the issue
and that
the actions
taken to comply could have
been initiated 'much earlier.
The
inspector generally
agreed with the case
study conclusions,
but noted
that although the
TS did not clearly define ambient conditions,
other
regulatory
documents
referred to ambient
as the temperature
maintained
by keep
warm systems.
In addition, the inspector's initial concerns
regarding testing at greater
than ambient conditions
had
been
communicated
to the licensee.
Regulatory services
concluded that
corrective actions
were not necessary.
This was later determined to be
incorrect'he
inspector
concluded
subsequent
corrective actions that
were initiated in response
to the violation were appropriate.
Based
upon the
above discussion,
LER 50-275/95-10,
Rev.
0 and
1 are
closed.
Closed
Violations 50-275 94027-01
and 50-323 94027-01,
preconditioning
of molded
case circuit breakers prior to surveillance testing.
The
licensee
uses
(MCCBs)
as containment
protection for 120-volt AC, 480-volt AC, and 125-volt
circuits.
TS 4.8.4.2 requires periodic verification that containment
overcurrent protection is operable.
Surveillance testing of
overcurrent protection is accomplished
at
a refueling outage
frequency
by performing functionality testing
on
a representative
sample of at
least
10 percent of the associated
breakers.
The licensee's
procedures
for surveillance testing
and maintenance
of
MCCBs exercised
the breakers
manually
and lubricated pivot points prior
to performing the
TS required trip current testing.
By performing the
maintenance
activities prior to testing,
the licensee failed to
demonstrate
the operability of the breakers
in the as-found condition,
0
-21-
Since only a fraction of the circuit breakers
are required to be tested
each refueling outage to justify the operability of the remaining
circuit breakers,
preconditioning prior to testing
does not provide the
expected
assurance
of the operability of the remaining breakers
which
are not tested.
The licensee's
assessment
of the impact of the preconditioning of the
HCCBs included
a review of industry standards
and vendor circuit breaker
manuals.
The assessment
concluded for HCCBs with non-interchangeable
instantaneous
trip units that mechanical
cycling of the
HCCB does
not
affect the instantaneous
portion of the trip unit portion of the
HCCB
since it is independent
from the handle. mechanism.
The assessment
also
indicated that the mechanical
exercising of the breakers
had the
potential to influence the
common contact operating
mechanism that opens
the
HCCB load contacts;
however,
the conclusion
was that this would not
have
a significant effect
on the instantaneous
fault clearing time of
the
HCCB.
The inspector
reviewed the licensee's
response
to the violation, the
associated
maintenance
procedure revision
(HP E-64. 1A,
"AC and
DC Holded
Case Circuit Breaker Test Procedure" ),
and the associated
nonconformance
report
(NCR) N0001882.
The sequence
of testing
was revised to require
electrical testing prior to intentional
mechanical
cycling of HCCBs in
order to allow more accurate testing of the circuit breaker
operating
mechanisms.
In addition, for HCCBs with removable
instantaneous
trip
devices
the procedure revision ensures
that electrical testing is
performed prior to the removal
and lubrication of the trip unit.
The
inspector
concluded that the licensee's
corrective actions
were
appropriate.
III. En ineerin
Conduct of Engineering
S ent Fuel
Pool
Pum
Power
Su
l
Ins ection
Sco
e
37551
During
a routine plant tour on April 16, the inspector
noted
a temporary
jumper installed
between
a Unit 2 480V non-vital
bus
and the line side
of the supply breaker for SFP
pump 2-1, located in 480V vital bus
F.
The inspector
reviewed the
ECG for the
pumps
and the associated
sections of the
The inspector also reviewed the licensee's
safety evaluation
associated
with the license
amendment
request
to
increase
the storage
capacity of the
(License
Amendments
22/21).
Observations
and Findin
s
In support of license
amendments
(LAs) 22
and
21 for Units
1 and
2
respectively,
the licensee
committed to and installed
a second,
-22-
redundant
SFP cooling
pump powered
from Class
1E power.
As described
in
Section 8.3 of the
UFSAR, both
SFP cooling
pumps
are supplied
from
separate
vital 480V busses.
The spent fuel pool cooling
pumps
are not covered
by TS.
To
administratively control these
pumps,
the licensee
developed
an
equipment control guideline
(ECG).
ECG 13. 1 states
that "two spent fuel
pool cooling pumps
and their associated
heat
exchanger
and flow path
shall
be
One
pump shall
be powered
from its vital power
supply.
The other
pump may be powered
from a non-vital
power supply
'hrough
an approved jumper."
This
ECG applies
whenever
spent fuel is
stored in the spent fuel pool.
Thus,
ECG 13. 1 authorizes
the
installation of the temporary jumper observed
by the inspector.
However, the
ECG,
as written, is inconsistent with the
UFSAR with
respect
to the
pump power supplies.
The inspector discussed
with the licensee's
engineering staff the impact
of using
a temporary jumper for the
SFP cooling pumps
on the plant
licensing basis,
as described
in LAs 22 and
21
and Section 8.3 of the
The inspector determined that the licensee
had not performed
an
adequate
licensing basis
impact evaluation
(LBIE) when
ECG 13. 1 was
developed
and implemented.
Specifically,
an inadequate
screening
had
been
performed
and
a safety evaluation
was not documented
to address
the
deviation from the facility description in the
Subsequent
to the
discussion,
the licensee
performed
an LBIE for the use of a temporary
jumper to supply the
SFP cooling pumps with non-vital power.
The
licensee
also developed
a revision to Section 9.1.3 of the
UFSAR to
clarify the power supply requirements
for the
SFP cooling pumps.
There
was
no adverse
safety
consequences
as
a result of the licensee
not
performing
a safety evaluation.
The licensee's
initiatives to install
temporary non-vital power to spent fuel pool
pumps during vital bus
outages
is considered
to be of safety benefit;
however,
the failure to
follow the formal process for reviewing and documenting
changes
to the
facility is
a concern.
The licensee's
process for establishing
an
ECG
does involve
a review to determine the impact
on the equipment's
licensing basis.
Conclusions
The licensee's
failure to document
a safety evaluation
on the impact of
supplying the spent fuel pool cooling
pumps with temporary non-vital
power was determined to be
a violation of 10 CFR 50.59
(VIO 50-
323/96009-03).
Failure to Track Commitment
From Res
onse to Notice of Violation
Ins ection
Sco
e
37551
The inspector
reviewed the licensee's
followup to an issue involving the
failure of main steam isolation valves
(HSIVs) to fully close
when
0
-23-
shutting
down for .an outage.
In response
to
a violation
(NRC Inspection
Report 50-275/95-15),
the licensee
stated that the actuator pins for the
HSIVs would be replaced.
b.
Observations
and Findin
s
During the Unit
1 refueling outage
conducted
in October
1995, following
core offload, the licensee identified that the HSIVs had failed to fully
seat.
Consequently,
containment
closure
had not been
adequately
established
for the core offload.
Although this event
was identified by
the licensee,
a violation was issued for the failure to establish
containment
closure during core alterations
based
upon the occurrence of
a similar event
on Unit 2 in October
1994.
In its response
to the
NOV, dated
December
21,
1995, the licensee
described
the corrective actions to prevent recurrence
of the violation.
The licensee identified corrosion of the HSIV actuator pins to be
a
potential contributing factor in the failure of the MSIVs to fully seat.
One of the corrective actions
was to replace
these
pins in Unit
1 HSIVs
with stainless
steel
pins during the
2R7 outage.
The licensee
also
indicated their intention to replace
the actuator pins
on Unit 2 HSIVs
during 2R7.
During the
2R7 outage,
the inspector questioned
whether the pins
had
been replaced
on the HSIVs.
The commitment to replace the actuator pins
on Unit 2 had not been entered
into the licensee's
tracking system
and
therefore at that time there
were
no plans for replacement
of the HSIV
actuator pins.
Consequently,
the pin replacement
was not incorporated
into the scope of work for the refueling outage.
Subsequent
to the
inspector's
identification of this issue,
the licensee initiated and
completed
the replacement
of all Unit 2 HSIV actuator pins during the
2R7 outage.
In addition, licensee
personnel
reviewed other licensing
correspondence
to determine if there were other commitments that were
not being properly tracked.
None were identified.
c.
Conclusions
The licensee's
failure to properly track its commitment to replace
the
MSIV actuator
pins
on Unit 2 is considered a'egative
finding.
Without
the inspector questioning
whether the modification had
been
completed,
it appears
the pin replacement
would have
been missed
due to poor
tracking of the commitment.
E1.3
Inadvertent
Prom t 0 erabilit
Assessment
POA
a.
Ins ection
Sco
e
37551
The inspector
reviewed the licensee's
POA that addressed
the concerns
raised in Westinghouse
Nuclear Safety Advisory Letter
(NSAL) 93-13.
The
inspector
reviewed the following documents
and attended
a meeting in
which this issue
was discussed:
which documented
the licensee's
POA
NCR N0001973,
Untimely and Incomplete
Response
to
NSAL 93-13,
Inadvertent
ECCS Actuation at Power
UFSAR Chapter
15, Section
15.2. 14, Spurious
Operation of the
Safety Injection System at Power
Observations
and Findin
s
NSAL 93-13 identified that previous analyses
performed
by Westinghouse
for a spurious
Safety Injection System
(SIS) event
had several
nonconservatisms
(e.g., failing to account for decay heat
and the
contribution of the positive displacement
charging
pump flow).
The
concern
associated
with a spurious
SIS event is the potential to
overfill the pressurizer
and discharge
water through
a pressurizer
safety valve
(PSV) which in turn may cause
the
PSV to fail open
and
create
an unisolable leak path (i.e. small
break loss of coolant
accident
(LOCA)).
Hased
upon the issues
raised
in NSAL 93-13 the
licensee
re-evaluated
the validity of their existing spurious
analyses.
The licensee
determined that the existing safety analysis
was non-
conservative.
The existing analysis
concluded that the spurious
SIS did
not present
a hazard to the integrity of the
RCS.
The licensee's
evaluation indicated that the pressurizer overfill would occur slightly
greater
than
12 minutes after the initiation of a spurious injection.
The licensee
conducted
spurious
SI scenarios
in the simulator to time
operator
response
to the event.
Operators
in the simulator terminated
the SI in approximately
13.5 minutes.
Since this was greater
than the
time the analysis
indicated that it would take to overfill the
pressurizer
the licensee
concluded that operator action could not be
credited for preventing pressurizer overfill.
Calculations
were
performed that indicated
under normal conditions
an inadvertent
would result in pressurizer overfill in approximately
17 minutes.
The
licensee
has initiated actions to revise the
UFSAR Chapter
15 analysis.
The licensee
performed
a
POA which credited
the automatic actuation of
the pressurizer
power operated relief valves
(PORVs) in preventing
overfill of the pressurizer.
The
PORV automatic actuation circuitry is
Class II and
as
such is not normally credited
in safety analyses.
The
POA documented
the similarities of the circuitry with Class
I circuitry.
The inspector
attended
a Technical
Review Group meeting that addressed
this issue
and questioned
the licensee
as to the differences that
prevented
the automatic actuation circuitry from being classified
as
Class I.
Further investigation
by the licensee
revealed
that the
previous
POA assumption
that the automatic control circuitry was
0
-25-
installed to Class
lE standards
was incorrect.
Of the differences
noted
the more significant revealed that the controller associated
with
automatic
PORV actuation
was not purchased
as Class
I but had
been
obtained
as controls grade
equipment.
In addition, the circuitry is not
isolated
from other Class II circuits.
A conference
call
was conducted
on May 8 with the licensee
and
NRC
personnel
(Region
IV and
NRR).
The conference call identified that. the
crediting of Class II circuitry for automatic
PORV actuation to prevent
lifting the
PSVs during
a spurious
SIS event
was not
an acceptable
approach.
Following the conference call the licensee initiated
an
approach
which credited the
PSVs for passing
water at greater
than
600
F without concern for the valves sticking open.
The licensee
reperformed
the analysis crediting the
PSVs
and demonstrated
that the
spurious
SIS event would be terminated prior to the
PSVs passing
water
at less
than
600 'F, therefore providing protection for a spurious
event.
This approach
was similar to that taken
by other licensees.
c.
Conclusions
The licensee's
POA contained
non conservative
assumptions
concerning
the
quality standards
associated
with the automatic
PORV actuation
circuitry.
These
assumptions
were inappropri ately utilized to justify
crediting the automatic actuation of the
PORVs to mitigate
an spurious
SIS.
Although subsequent
analysis
showed there
was not
a problem,
the
weaknesses
of the earlier approach
and analysis
are considered
to be
a
negative finding.
E2
Review of Final Safety Analysis Report
(FSAR) Commitments
A recent discovery of a licensee
operating their facility in a manner contrary
to the
UFSAR description highlighted the need for a special
focused review.
that compares
plant practices,
procedures,
and/or parameters
to the
description.
During
a portion of the inspection period (February
1 through
March 2,
1996), the inspectors
reviewed the applicable sections of the
that related to the inspection
areas
discussed
in this report.
The following
inconsistencies
were noted
between
the wording of the
UFSAR and the plant
practices,
procedures,
and/or parameters
observed
by the inspectors.
The
deficiencies
are discussed
in the sections
in the report that are referenced
below:
Licensee
connected
non-vital temporary
power to vital component
described
in UFSAR without performing
a safety analysis
(Section
El.l)
E8
Miscellaneous
Engineering
Issues
E8. 1
Closed
Follow-U
Item 50-275 95014-01,
40 percent
steam
dump valve
plug cracking.
During refurbishment of a valve trim set plug removed
I
0
-26-
from a 40 percent
steam
dump valve during
2R6, the licensee
found cracks
on the sides
and across
the top of the valve plug into the stem boss.
Cracking
was also noted
on another valve plug in the licensee's
warehouse
stock, that
had
been installed
and subsequently
removed
from a
Group II 40 percent
steam
dump valve.
Based
on the potential for having
cracked valve plugs installed in in-service valves,
the licensee
inspected all Unit
1 40 percent
steam
dump valves,
as well
as
one
35
percent
and
one
10 percent
steam
dump valve.
During the inspections
liquid samples
were obtained
from the 40 percent valve balancing
chambers
in order to perform chemical
analyses.
Of the additional
valves that were inspected
two 40 percent
valves were noted to have
cracked valve plugs.
The cracked
plugs were replaced prior to returning
the valves to service.
The largest crack found was 6.5 inches
long and
up to 2.04 inches
deep.
The 35 and
40 percent
steam
dump valves
are Class II, not safety-related
and
do not have
an explicit function to mitigate the effects of an
analyzed
accident.
The
10 percent
steam
dumps
are Class
I, valves with
material specifications similar to the 35 and
40 percent valves;
however,
they differ in plug size
and shape.
In addition,
both the
10
and 35 percent
steam
dumps vent to the atmosphere,
whereas
the
40
percent
valves exhaust to the condenser.
There
have
been
no instances
of valve plug cracking noted with 10 or 35 percent
steam
dump valves at
Diablo Canyon.
The steam
dump valve plugs were manufactured
using
a hardened
ASTH A-276
Type 420 stainless
steel material.
Type 420 is
a higher carbon version
of a more
common Type 410 martensitic stainless
steel.
The licensee's
evaluation
determined
the valve plug cracking
was caused
by
intergranular stress
corrosion cracking
(SCC)
and 'hydrogen
embrittlement.
Other factors
are believed to have contributed to the
cracking include: machining
and original forging process
flaws,
corrosive fluids, material residual
stresses,
and the heat treatment to
high strength levels performed
on the material.
The principle difference
between
the
40 percent
and the other steam
dump
valves is the operating
environment the valves
are subjected.
Chemical
analysis of water samples
obtained
from the
40 percent
steam
dump valve
balancing
chambers
during disassembly
indicated that there
were chloride
and sulfite concentrations
of up to 4.5
ppm and 5.8
ppm respectively.
The 35 and
10 percent
valves vent to the atmosphere
and the potential
for similar concentration of chlorides
and sulfates
does not exist.
The
licensee
determined that the Type 420 stainless
steel
is extremely
susceptible
to
SCC when exposed
to chloride or sulfur containing
environments.
Based
upon the analysis
and inspection results,
the
licensee
has initiated actions to replace
the valve trim set in the
40
percent
steam
dump valves with replacement
trims sets of a material
less
susceptible
to
SCC.
-27-
Conclusion:
The licensee
conducted
a thorough evaluation of the cracking
and
has developed
a plan for replacement
of the 40 percent
valve plugs
with plugs manufactured with a different material.
IV. Plant
Su
ort
Fl
Control of Fire Protection Activities
a.
Ins ection
Sco
e
71750
The inspectors
conducted
frequent
walkdowns of plant areas
with an
emphasis
on those
areas
impacted
by the Unit 2 refueling outage.
Areas
were evaluated for appropriate
storage of materials,
cleanliness
and
avai.lable lighting.
b.
Observations
and Findin
s
In general,
material
storage
and cleanliness
were good.
Storage of
materials,
including transient
combustibles,
appeared
to be in
accordance
with licensee
procedures.
Although housekeeping
was 'a
strength during the Unit 2 refueling outage,
several
notable material
deficiencies
were identified in Unit
1 areas.
Available lighting in the 140'level of the Unit
1 fuel handling building
was poor.
The inspector
noted that
8 of the
15 overhead lights
illuminating the spent fuel pool area
were out.
However,
no action
request
had
been initiated to the technical
maintenance
group to replace
these lights.
Although the inspector identified this deficiency to the
individual responsible for lighting in that area,
actions to replace
the
lights were slow.
Prior to actual
replacement
of the lights, subsequent
failures
had left only 2 of the
15 overhead lights functioning.
The
concern is that the low lighting level could hinder personnel
access
to
the area
and created
a personnel
safety hazard.
c.
Conclusions
In general,
housekeeping
during the Unit 2 refueling outage
was
a
strength.
Materials were staged
in pre-approved
laydown areas
and work
sites
were adequately
maintained.
Housekeeping
in the
EDG 1-2 room'as
deficient in that lube oil and fuel oil leaks
were not corrected
or
cleaned
up thus creating
the potential to mask other potentially
significant problems
should they occur.
-28-
Xl
fxit Meeting Summary
V. Mana ement Neetin
s
The inspectors
presented
the inspection results to members of the licensee
management
at the conclusion of the inspection
on May 30,
1996.
The licensee
acknowledged
the findings presented.
The inspectors
asked
the licensee
whether
any materials
examined during the
inspection
should
be considered
proprietary.
No proprietary information was
identified.
-29-
PARTIAL LIST OF
PERSONS
CONTACTED
Licensee
J.
R.
D. F.
S.
G.
C.
D.
D.
B.
R.
P.
R. A.
Becker, Director, Operations
Brosnan,
Director, Regulatory Services
Chesnut,
Sr. Engineer,
Primary Systems
Engineering
Harbor,
Engineer,
Regulatory Support
Miklush, Manager,
Engineering
Services
Powers,
Manager,
Operations
Waltos, Director, Balance of Plant
Systems
V
-30-
IP 37551:
IP 61726:
IP 62703:
IP 71707:
IP 71750:
IP 92901:
IP 92902:
IP 92903:
~0ened
INSPECTION
PROCEDURES
USED
Onsite Engineering
Surveillance Observations
Maintenance
Observations
Plant Operations
Plant Support Activities
Followup
Plant Operations
Followup
Maintenance
Followup
Engineering
ITEMS OPENED,
CLOSED,
AND DISCUSSED
50-323/96009-01
50-323/96009-02
50-323/96009-03
Closed
50-275/95014-01
50-275/94027-01
50-323/94027-01
failure to meet Technical Specifications for fuel
handling building ventil ation
failure to perform steps
as written when performing
maintenance
on
AFW pump 2-1
failure to document
a 50.59 evaluation for providing
non-vital
power to the spent fuel pool cooling pumps
failure to properly perform emergency diesel
generator
surveillance testing required
by TS
preconditioning of molded case circuit breakers prior
to surveillance testing
50-275/95014-01
IFI
40 percent
steam
dump valve plug cracking
50-323/96-02-00
50-275/95-10-00
50-275/95-10-01
Discussed
50-275/95-06-00
LER
Technical Specification 3.9. 12 Not Met Due to
Personnel
Error
LER
failure to properly perform emergency
diesel
generator
surveillance testing required
by TS
LER
Technical Specification 3.9. 12 Not Met Due to
Personnel
Error
2R7
1T8
ASTH
ASW
DCN
CFCU
CO
ECG
FHB
FHBV
LA
LBIE
LER
HCCB
HSIV
OVID
PH
POA
PSV
SFH
TS
LIST OF ACRONYHS USED
Unit 2 Seventh
Refueling Outage
Unit 1, Cycle 8, Transformer
Outage
action request
American Society for Testing
and Haterials
auxiliary saltwater
design
change notice
centrifugal
charging
component cooling water
containment
fan cooler unit
control operator
chemical
and volume control
system
emergency
core cooling system
equipment control guideline
emergency
diesel
generator
fuel handling building
fuel handling building ventilation
final safety analysis report
Institute of Nuclear
Power Operations
license
amendment
licensing basis
impact evaluation
licensee
event report
loss of coolant accident
maintenance
procedure
nonconformance
report
Non-Cited Violation
Nuclear Safety Advisory Letter
operating
valve identification diagram
public document
room
preventive maintenance
prompt operability assessment
power operated relief valve
pressurizer
safety valve
system
residual
heat
removal
Society of Automotive Engineers
stress
corrosion cracking
shift foreman
spent fuel pool
safety injection
safety injection signal
Technical Specification
Updated
Final Safety Analysis Report
work order
l