ML16341G676
| ML16341G676 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 08/13/1992 |
| From: | Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341G675 | List: |
| References | |
| 50-275-92-20, 50-323-92-20, NUDOCS 9209010153 | |
| Download: ML16341G676 (74) | |
See also: IR 05000275/1992020
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report
No:
Docket Nos:
License
Nos:
Licensee:
Facility Name:
Inspected at:
50-275/92-20
and 50-323/92-20
50-275
and 50-323
Pacific
Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
Diablo Canyon Units
1 and
2
Diablo Canyon Site,
San Luis Obi'spo
County, California
Inspection
Conducted:
June
2 through July 13,
1992
Inspectors:
P. Horrill, Senior Resident
Inspector
H. Hiller, Resident
Inspector
D. Corporandy,
Reactor Inspector
Approved by:
Summary:
P. Johnson,
Chief
Reactor Projects Section
1
Date Signed
ns ection from June
2 throu
h Jul
13
1992
Re ort Nos.
50-275 92-20
and
50-323 92-20
Td:Td
f
p
f
f tdd
tt
t
p
f
fpt
t
operations,
maintenance
and surveillance activities, followup of onsite
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
2515/ll5, 41701,
61726,
62703,
71707,
71710,
90711,
92700,
92703,
93702,
and
94600 were used
as
guidance during this inspection.
Safet
Issues
Mana ement
S stem
SIMS
Items:
None
'es
units
General
Conclusions
on Stren ths
and Weaknesses
Stren ths:
The licensee's
immediate
response
to the chemical spill on June
20,
1992,
was prompt
and comprehensive.
It appeared
that Fire Brigade
5'209010153
'720813
ADQCK 05000275
8
e
training and related training had been effective in preparing
Operations
personnel
to deal with emergency
evacuation
and rescue
operations.
Weaknesses:
The
NRC determined that -the Unit
1 and
2 'positive displacement
charging
pumps
(PDPs)
have
been
deemed
by the licensee to have
been
"for emergency
use only," during the past two years.
The inspe'ctors
also identified
a weakness
in the licensee's
assumption that Abnormal Procedure
AP A-17, "Loss of All Charging,"
could be assumed
usable for safe
shutdown in the event of a fire in
the centrifugal charging
pump
(CCP) room.
The licensee's
engineering
organization
had previously concluded that operation of
the positive displacement
charging
pump
(PDP) could cause
cracking
in the charging system.
However, the licensee
had not conducted
a
circuit analysis to determine
whether
AP A-17 could be used
following a fire in the
CCP room,
nor had the licensee
informed the
operators of when,
how,
and
how long the
PDPs could be safely used
to back up the
CCPs.
n
'cant
a et
Matte s:
None.
Summar
o
io at ons:
Two Severity Level IV violations were identified,
applicable to both Units
1 and 2:
1.
The first violation was failure to provide adequate
instructions for
the use of the
PDP.
2.
The second violation involved failure to comply with 10 CFR 50.72.(b)(1)(ii)(B) after three fire protection deficiencies
outside
the design basis of the plant were identified.
The regulation
requires that conditions outside the design basis of the plant be
reported to the
NRC within one hour.
0 en
tems
Summar
Five items were opened.
Two items were closed.
QETAILS
ersons
Contacted
acific Gas
and Electric
Com
an
G.
M. Rueger,
Senior Vice President
and General
Manager,
Nuclear
Power Generation
Business
Unit
<<J.
D. Townsend,
Vice. President
and Plant Manager,
Diablo
Canyon Operations
W. H. Fujimoto, Vice President,
Nuclear Technical
Services
D. B. Miklush, Manager,
Operations
Services
M. J. Angus,
Manager,
Technical
Services
<<B.
W. Giffin, Manager,
Maintenance
Services
W. G. Crockett,
Manager,
Support Services
J.
E. Holden, Instrumentation
and Controls Director
- W. D. Barkhuff, guality Control Director
R.
P.
Powers,
Mechanical
Maintenance Director
H. J. Phillips, Electrical Haintenance Director
J. A. Shoulders,
On site Project Engineer
<<S.
R. Fridley, Operations Director
R. Gray, Radiation Protection Director
J.
V. Boots,
Chemistry Director
"T. A. Houlia, Assistant to Vice President,
Diablo Canyon
Operations
- R. Kohout, Safety,
Health
and Emergency Services Director
- T. L. Grebel,
Regulatory Compliance Supervisor
J. J. Griffin, Senior Engineer,
Regulatory Compliance
- D. P. Sisk, Regulatory Compliance
Engineer
D. R. Stermer,
Power Production Engineer
N.
R. Tresler,
Project Engineer
R. Clark, Assistant Project Engineer
R. Gagne, Acting Radwaste
Foreman
U. A. Farradj,
Fire Protection
Engineer
- R. A. Waltos,
Mechanical
Maintenance
Supervisor
S.
F. Shrefler,
Mechanical'Maintenance
Engineer
B. D. Pogue,
System Engineer
R. Ortega,
System Engineer
R. Watson, guality Assurance
Engineer
- F. J. Bosseloo,
OPEG Project Engineer
- D. A. Hoon, Regulatory Compliance
Engineer
- M. Burgess,
Systems
Engineering Director
- J. S. Bard, guality Control Specialist
inde endent Safet
Oversi ht Committee
William Kastenberg,
Professor of Engineering
8 Applied Science,
Warren
Owen,
Executive Vice President of Duke Power,
Power Group
Operations
uc ear
e viator
Comm ssio
e
o
<<R. A. Scarano,
Director, Division of Radiation Safety
and Safeguards
<<Denotes
those attending the exit interview.
The inspectors
interviewed other licensee
employees
including shift
supervisors,
shift foremen
(SFH), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
and quality
assurance
personnel.
2.
0 erat onal Status of Diablo Can
o
U
ts
and
2
Both units operated
at 100X power 'during the inspection period except for
Unit 2, which curtailed power to 50X on June
13 to clean the condenser
and perform testing of main feed-water
pumps.
3.
0 erational
Safet
Verif catio
707
a.
~Genera
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's
facility.
The observations
and examinations of those activities
were conducted
on
a daily, weekly or monthly basis.
On
a daily basis,
the inspector s observed control
room activities to
verify compliance with selected
Limiting Conditions for Operation
(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 whether regulatory requirements
were satisfied.
Shift
turnovers
were observed
on
a sample basis to verify that all
pertinent information on plant status
was relayed to the oncoming
crew.
During each
week, the inspectors
toured accessible
areas of
the facility to observe the following:
(1)
General
plant and equipment conditions
(2)
Fire hazards
and fire fighting equipment
(3)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved
procedures
(4}
Interiors of electrical
and control panels
(5)
Plant housekeeping
and cleanliness
(6)
Engineered
safety features
equipment 'alignment
and conditions
(7)
Storage of pressurized
gas bottles
The inspectors talked with control
room operators
and other plant
r
0
b.
personnel.
The discussions
centered
on pertinent topics of general
plant conditions,
procedures,
security, training,
and other aspects
of the work activities.
adiolo ical Protectio
co
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 radio-
logical conditions and/or challenges.
ALARA considerations
were
found to be
an integral part of each
RMP {Radiation Work Permit).
Zhhil
S
hK
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 integrity.
Exterior lighting was checked during backshift inspections.
No violations or deviations
were identified.
4.
ns te
ve t
o
owu
93
0
a.
hr ou h-Wall Cor rosio
and
Leaka
e of Auxil ar
Salt Mater Pi in
i
On June 18,
1991,
a leak of about
50 ga11ons
per minute occurred in
the annubar riser on the 2-2 auxiliary salt water
{ASM) system.
The
annubar riser,
used for ASM system flow measurements,
is
a 4-inch
diameter
PVC-1ined carbon steel
pipe rising about five feet above
the buried
ASW piping traveling under the turbine building.
The
riser travels
up through
a covered trench before it extends
above
ground.
The leak occurred in the portion of the piping in the
trench.
The licensee
clamped
a pipe patch
around the pipe as
a
temporary measure
to stop the leak.
The leak appeared
to have
been
caused
by through-wall corrosion
initiated on the outer wall of the piping, in the trench.
Later
ultrasonic testing indicated that significant corrosion
had also
occurred
on the l-l ASM riser.
The 1icensee's
preliminary
evaluation
determined that the corrosion was due to degradation
of
the coal tar epoxy coating
on the carbon steel
piping combined with
alternate wetting and drying.
Once any moisture got under the coal
tar epoxy, the pipe rusted
and flaked off additional
coal tar epoxy.
The alternate wetting and drying caused
the exposed
pipe to rust
rapidly.
The licensee
plans to replace all four annubar risers with
corrosion resistant material.
Chronolo
of Events:
The inspectors
examined the licensee's
documents listed below and
discussed
the corrosion problems with licensee
engineering
and
maintenance
personnel.
Action Requests:
A0269002,
A0269111,
A0269118,
A0269152,
A0269215
Mork Orders:
C0101129,
C0101131
NCR:
DC2-92-TN-N028,
Rev.
00
Operability Evaluation:
92-14,
Rev.
0
The inspector
observed that, starting with the annubar leak, the
following chronology of recent
events
had occurred.
June 18
June 19
June 20
The leak in the 2-2 annubar pipe was found by
the licensee.
A temporary soft patch
was
installed
and
a prompt operability evaluation
(POA) was completed.
Licensee
engineering
confirmed the
POA.
Other
annubar piping was visually inspected.
Significant corrosion of annubar
1-1 was
documented.
An, event response
plan
(ERP 92-6)
and nonconformance
report
(NCR DC2-92-TN-N028)
were initiated.
June 21
June 22
June 23
An acid and caustic spill occurred in the
buttress
area of Unit 2.
Some overflow appears
to have entered
the trench containing carbon
dioxide fire suppression
(CARDOX) and diesel
fuel oil
(DFO) piping.
The annubars
also go
through this trench approximately
70 feet from
the acid/caustic spill.
While cleaning
up the acid/caustic spill,
licensee
personnel
found significant corrosion
on the
CARDOX piping.
One of the pipes thought to be
CARDOX with
significant. corrosion
was identified as diesel
fuel oil transfer piping.
The preliminary
inspection
plans for the
CARDOX lines were
developed.
DFO line 4537 was
removed from service at 5:45
a.m. to allow tie-in to the
new emergency
diesel
generator
(EDG 2-3).
The corroded spot
on
DFO
train 0-2 was examined
and found to be approxi-
mately
120 mils (nominal pipe wall is 203 mils).
The minimum wall requirement for this location
was calculated
by the licensee to be 75 mils.
No leakage
was observed
during
a pressure test
to 68 psig.
June
24
Detailed plans were prepared to inspect
DFO
lines.
At 1220 the 0-2
DFO line was returned to
service.-
June 25
July
2'FO
0-1 line was taken out of service at 5:05
a.m. for tie-in to
EDG 2-3.
Visual inspection
of 0-1 piping was conducted,
and areas of
concern were identified.
At 7:15 a.m.,
0-1
piping was returned to service.
DFO 0-1 was taken out of service for ultrasonic
examination.
One portion was found to be less
than or equal to 40 mils thickness.
8ecause
this was below required
minimum wall,
a twelve
foot portion of pipe was replaced.
July 4
0-1
DFO piping was placed
back in service at
2:00 p.m..
July 5
DFO 0-2 was taken out of service from 4:00 to
11:00 a.m. to conduct ultrasonic examinations
on
the Unit 2 side.
No areas
were found below
minimum wall thickness.
July 6 ,
DFO 0-2 was taken out of service from 4:00 a.m.
to noon to conduct ultrasonic examinations
on
the Unit
1 side.
No areas
were found below
minimum wall.
July 8-13
CARDOX piping visual
and ultrasonic examinations
were conducted.
No areas
were found below
minimu~ wall.
SW 0 erabilit
Determination:
The license determined that the 2-2
ASW train was operable
during the leak,
because
the leak flow rate
was about
50 gpm, while the
ASW flow rate allowed about
200 gpm
design margin
(OE 92-14,
Revision 1).
The licensee initiated
a
conditional surveillance to monitor ocean temperature
to ensure
continued
design margin.
Re lacement of ASW Annubar Pi in
The licensee
plans to replace
the piping during plant operation.
At the time of writing this
inspection report, the annubar
connections to the main
ASW line had
been unburied,
and the l-l and 2-2 annubar piping had
been
rem'oved
and capped with flanges.
Diesel
Fuel Oil Pi in
The licensee
determined that the corrosion
of the
DFO piping in train 0-1 was not immediately reportable,
but
was reportable
as
a licensee
event report.
The licensee's
preliminary evaluation
concluded that the corrosion of the
DFO
piping was most likely due to incomplete application of coal tar
-6-'poxy
on the underside of-the pipe,
combined with an environment
where moisture could condense
and accumulate
on. the underside of the
pipe.
At the end of the reporting period the licensee
was
'valuating
how long the existing piping would be satisfactory
and
how to replace the
DFO piping with more corrosion resistant
material.
The inspector
asked licensee
personnel if they'had
considered
the prudence of taking the 0-2 fuel oil train out of
service during the period June
23 - 24,
1992, to complete the tie-in
to a new emergency diesel generator.
The inspector also asked if
the licensee
had recognized that,.due-to
the finding six days later
that part of the 0-1 train was below minimum wall, both trains of
fuel oil were out of service at that time.
Licensee
personnel
stated that events
were developing rapidly when
the corrosion problems were found and that they had to have time to
formulate inspection plans.
Taking the 0-2 piping out of service
was consistent
with the need to examine
and repair this line if the
highly rusted
spot found on June
22 was below minimum wall thick-
ness.
Since visual inspections
had already
been
completed,
licensee
personnel
believed they had found the worst case of corrosion.
After the completion of this inspection,
the licensee
completed
an
engineering
analysis
which concluded that the as-found wall
thickness for the
DFO piping would have
been acceptable.
ioxide Su
ression
Cardox
S stem Pi in
The licensee
inspected
the Cardox system with ultrasonic test equipment,
and
found no locations
below minimum required wall thickness.
However,
significant corrosion
was observed,
and the licensee is reviewing
the frequency of inservice inspection.
asteners
on
a
.
The licensee
uncovered
portions of
the buried
ASW piping to support
annubar
replacement.
The fasteners
on both the four-inch and 24-inch piping flanges
showed significant
corrosion.
The licensee
determined that further inspection
was
required,
and is currently determining the appropriate
scope of
investigation.
Sco
e of Corrosion Investi ation:
In addition to the piping and
fasteners
discussed
above,
the licensee is reviewing additional
buried
and entrenched
piping and components,
including electrical
connections
in covered trenches.
The review is being tracked
by
DC2-92-TN-N028.
~Summar
Since licensee
actions
are not complete,
the inspectors
will continue to follow the licensee's
corrective actions
(Followup
Item 50-275/92-20-01).
b.
Chemical
S ill and Noxious Gases
in the Turbine Buildin
On June
20, at 5:35 p.m., the licensee
declared
a Notice of Unusual
Event
as
a result of a spill of hazardous
material
and associated
noxious gases
entering the turbine building.
Caustic
and acid tanks in the 85 foot elevation
condensate
polisher
area adjacent to the Unit 2 side of the turbine building were
inadvertently overfilled.
About 300 gallons of 93K sulfuric acid
and 500 gallons of 50X sodium hydroxide were simultaneously
.discharged
to a common drain line, to an approximatel'y
10 ft by 25
ft bermed
area containing chemical transfer equipment.
The
resulting exothermic reaction
splashed
caustic liquid and released
a
cloud of acidic vapor which operators
observed
expanding
above the
bermed area.
Operators
recognized the tanks were overfilling and shut off the
pumps.
The fire brigade responded
and determined that the spill had
stabilized.
Search
and rescue activities were performed
immedi-
ately, which determined that no personnel
had
been injured in the
spill. 'Assistance
was requested
from California Department of
Forestry hazardous
waste response
personnel.
The hot gases
had entered
the turbine building and traveled
up the
crane
bay to the
140 foot elevation.
Operators
promptly shifted the
control
room and technical
support center ventilation to the pressu-
rization mode.
Vital equipment in the turbine area
was verified to
be accessible
by operators
and security personnel
using self-
contained breathing apparatus.
By about 10:30 p.m., initial testing of some of the turbine building
areas
showed reduction of noxious gas concentrations
to safe
.
habitability levels.
Final confirmation of habitability for all
turbine building areas
was completed at 2:IO a.m. on'une
21, at
which time the Unusual
Event was secured.
The resident
inspector
responded
to the site.
It appeared
that
licensee
response activities were carried out in a timely and
conservative
manner.
Cleanup of the bermed
area
and the other areas
where the gas cloud
deposited
acidic precipitates
was initiated June
21,
and was
essentially
completed
by the end of the report period.
The licensee initiated
NCR DC2-92-OP-N029
and
an investigation
(ERP
92-7) to determine the cause of the spill.
The spill was initiated
by an operator
who violated procedures
by filling both the, acid
and
caustic
day tanks simultaneously.
The licensee initiated corrective actions to prevent recurrence,
including counseling
the operator
who filled both tanks at once,
circulating
an Incident Summary to other operators,
making design
improvements in the condensate
demineralizer
regeneration
system,
determining if other areas of the plant were vulnerable to similar
events,
and evaluating whether this event
was covered
by the plant
design basis.
The inspector questioned
the licensee
regarding the design basis of
the three
chemical
storage
tanks (sulfuric acid,
sodium hydroxide,
and ammonia) located in the Unit 2 turbine building buttress
area.
Licensee
personnel
stated that the tanks were not safety related
and
c
had been designed to the Uniform Building Code requirements
using
the Design Earthquake
(0.2
G horizontal
and 0.13
G vertical
accelerations).
The ammonia tank had been design to slightly higher
standards
of 0.3 and 0.2
G respectively.
An analysis of the effects
of the failure of each tank had
been done.
The installation of the
ammonia tank
(DCP H-39122)
had
been completed after
safety evaluation
was completed.
This safety evaluation considered
the complete rupture of the
ammonia tank.
The inspector questioned
whether the design
was adequate
to preclude rupture of all three
tanks at once during
a large earthquake
and whether this effect had
been considered
in accident planning.
Licensee
personnel
stated that the safety factors to design allow-
able stresses
in the tanks .varied from 1.5 to 2.2 for the Design
and that the factor of safety to failure from the
allowable stresses
was at least 2.2, which would make simultaneous
tank ruptures very unlikely.
The inspector
asked the licensee if
they had considered
the effects
on accessibility to the Technical
Support Center,
which is in the
same plant area.
The inspector
and
the licensee will review existing documentation of the tanks'esign
bases
before reaching
a final conclusion.
arth uake
Fe t at the Site
on June
8
992
On June 28,
1992, at approximately 4:59 a.m., plant personnel felt
seismic activity and declared
an Unusual'vent.
It was subsequently
determined that the event
was
an earthquake
measuring
7.4 on the
Richter scale,
approximately
260 miles southeast
of the plant.
The Senior Resident
Inspector
responded
to the site.
The licensee's
seismic monitoring instrumentation registered
a horizontal
acceleration
of 0.002
G at the containment
base.
The only other
indication was
a one-inch level oscillation in the pressurizer
relief tank for a period of several
minutes.
Licensee
and inspector
, walk-downs did not identify any other effects
on the plant.
5.
aintenance
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 that maintenance activities were
performed
by qualified personnel,
in accordance
with fire protection
and
housekeeping. controls,
and that replacement
parts
were appropriately
certified.
These activities included:
Work Order C0100716,
Investigate
High D/P Indication on
CCW Heat
Exchanger
2-1
Wor k Order C0100647,
Clean Saltwater Side,
CCW Heat Exchanger
2-1
Work Order C0100669,
Implement
DCP E-47538
(Remove
Surge Protectors
from HVAC air solenoids
in Auxiliary Building)
Work Order C0101129,
Remove Tar and Inspect Piping (Cardox)
Mork Order C0101131,
Inspect Unit 2 Diesel
Fuel Oil Header Line 4534
The inspector
observed that
CCW Heat Exchanger
2-1 was taken out of
service for cleaning
on June 8, 9,
10,
and ll.
Licensee
personnel
stated
that this was intended
and expected
due to sea growth being killed by
continuous chlorination of that
ASM train.
The licensee
had previously
eliminated
sea growth (barnacles
and mussels)
from. the l-l ASW train
using continuous chlorination
and felt this was
a prudent measure to
preclude
unexpected unavailability of the
CCW heat exchangers.
The
- inspector
aske'd if,the licensee
had considered
the level of plant risk
associated
with taking the
CCM heat exchanger
out of service
so
frequently.
Licensee
personnel
subsequently
determined that the increase
in risk was
dependent
upon
how the
CCW heat exchanger
was taken out of service,
and
reportedly, that the increase
was noteworthy and warranted consideration.
In the meantime,
the licensee
had stopped
continuous chlorination due to
the leak found in the 2-2 annubar piping and did not plan to restart
chlorination until the annubar piping was repaired.
The inspector
asked
what measures
would be used to minimize the core
damage risk for cleaning the 1-2 and 2-2
ASW system piping.
Licensee
personnel
stated that Operations
had been consulted
on this issue,
but no
final decision
on how to proceed
had been reached.
The inspector stated
that he would follow up this item during a subsequent
inspection.
No violations or deviations
were identified.
6.
ailure of Motor 0 crated
Va ve Caused
b
Loose Set Screw
90711
Baka
d
On June
2,
1992, motor operated
valve
(MOV) SI-2-8923A failed to
open fully during surveillance testing.
The license
inspected
the
Limitorque SHB-00 actuator
and found that the worm cartridge bearing
locknut setscrew
was loose,
and the locknut had unscrewed
from the
worm.
This caused
the torque switch to displace to its contact
open
setpoint
even though the spring pack had not deflected.
The limit
switch, which bypasses
the torque switch,
opened
as required at
approximately
30% of the open stroke.
This enabled
the open torque
switch,
hence tripping the motor and stopping valve motion at
30% of
open stroke.
(Refer to
NCR DC2-92-EH-N026).
The licensee
reviewed plant maintenance
history and found that
a
similar failure had occurred
on
HOV SI-2-880SB during post-
maintenance
testing during Unit 2's fourth refueling outage.
HOV SI-2-8805B also
has
an SHB-00 operator.
b.
etermination of Sco
e
The licensee
determined that
a loose
worm cartridge bearing locknut
could only cause
premature
torque switch actuation in an
SHB-00
-10-
operator.
Furthermore,
the licensee
determined that only the
opening direction was affected.
For the closing direction, the licensee
determined that
a 'loose
locknut could cause
the torque switch on the 'SHB-00 operator to
actuate
1-ate or not at all.
This type of failure would not prevent
a valve from closing but could potentially overtorque or overthrust
MOVs.
Furthermore, failure of the torque switch to actuate
could
cause the motor to stall
and overheat at the end of the valve
stroke.
The licensee
reviewed the other types of Limitorque actuators
used
in their two units
and determined that torque switch operation would
not be adversely affected
by a loose
worm cartridge bearing locknut.
Consequently,
the licensee
focused their investigation
on the
SMB-00
.
operators.
~am colin
Units } and
2 contain
98 HOVs with SMB-00 operators.
The licensee
inspected
locknut tightness
on
18 of these.
The
18 MOVs were
selected,
in part,
based
on safety significance
and vulnerability in
the opening direction.
Of the inspected
found to have loose
worm cartridge bearing locknuts.
Work on all
five HOVs had
been
performed
by one particular craftsman.
The
licensee
accounted for work performed
by this craftsman.
In addi-
tion,
13 assemblies,
which had previously been in service in the
plant,
and later replaced,
were inspected
and found to have tight
locknuts.
Root Cause
Eva uat
o
The licensee
concluded that the premature
actuation of the
HOV
SI-2-8923A torque switch had resulted
from the loose
worm cartridge
bearing locknut.
The licensee
was able to duplicate this failure
mechanism in their laboratory.
The licensee identified three
potential
causes:
(I)
lack of specific instructions for tightening the locknut and
locknut setscrew; i.e.,
a reliance
(2)
inadequate
locknut and setscrew tightening by one particular
indivi'dual.
(3)
harder material in replacement
worm gear shafts possibly
exacerbating
the problem of setting the locknut setscrew.
Because
the actuator vendor had supplied harder
worm gear replace-
ment shaft material without prior notification to the licensee,
the
licensee
also considered
10 CFR Part 21 reportability.
After
discussions
with their vendor,
the licensee
concluded that the form,
fit, and function of the part had not changed
and that it was not
reportable
under
IO CFR Part 2I.
e.
0 erabilit
Considerations
The SHB-00
MOVs inspected
were determined
by verifying that
the locknut was tight.
SMB-00 MOVs that were not inspected
were
reviewed
by the licensee
as follows:
. Operating procedures,
emergency
operating
procedures
(EOPs)
and
functional recovery procedures
(FRPs)
were reviewed to determine
which direction{s) was required to perform each valve's safety
function(s).
MOVs with a closing safety function were checked to
ensure that maximum torque
and thrust conditions would not exceed
valve and operator limits for
a single application of the load.
'OVs with a safety function to close were also verified to have
thermal'verload protection.
For valves with an opening safety function, motor trip at the point
at which the limit switch no longer bypassed
the torque switch was
assumed.
If flow was inadequate
at this position, the licensee
performed
a temporary modification to:pumper out the torque switch
in the opening direction.
The licensee
also verified that their
SHB-00
HOVs had sufficient capability at degraded
voltage conditions
to unseat
a valve disk which might have
been
wedged into the s'eat at
maximum overthrust conditions.
Valves which were locked open in the
required safety position with power removed did not undergo
any
further operability evaluations.
Conclusions
The inspectors
considered
the licensee's
determination of scope,
sampling,
and root cause
evaluations to be adequate.
The licensee's
operability considerations
appeared
to progress
in a logical
sequence
to address
mayor concerns.
However, at the time of the
inspection,
the licensee
h'ad not addressed
the ability of SHB-00
MOVs with loose locknuts to recover from inadvertent valve misposi-
tioning.
Consideration of valve mispositioning is
a recommendation
of Generic Letter 90-10 to which the licensee
has committed.
No violations or deviations
were identified.
7.
SU veillance
6
7
6
By direct observation
and record review of selected
surveillance testing,
the inspectors
checked
compliance with TS requirements
and plant
procedures.
'The inspectors verified that test equipment
was calibrated,
and that test results
met acceptance
criteria or were appropriately
dispositioned.
These tests
included:
~
STP V-301, Revision 7, Exercising Block Valves to the Pressurizer
PORVS,
Valves
RCS-SOOOA,
RCS-SOOOB,
and
RCS-SOOOC.
~
STP G-15B, Revision 2, Determination of Valve Stroke Times with
Equipment Timers.
No violations or deviations
were identified.
12-
'
a.
9.
n ineerin
Sa fet
Feature
Ver ificati on
7 710
During the inspection period, selected
portions of the residual
heat
removal
system for Units
1 and
2 were inspected to verify that system
configuration,
equipment condition, valve and electrical lineups,
'and
local breaker positions
were in accordance
with plant drawings
and
Technical Specifications.
No violations or deviations
were identified.
e
c
on o
Pla
Re
o ds
T
5 5
5
.
The objective of this Temporary Instruction (TI) is to determine whether
practices of individuals performing surveillance
and log entries
are such
that there is
a potential for record falsification to occur.
The inspector utilized the subject TI and
NRC Information Notice 92-3,
Falsification of Plant Records, to conduct this inspection effort.
The,
inspector determined that the licensee
had implemented
two self-
monitoring programs to audit daily and shiftly surveillance test
procedures
(STPs)
and radiological surveys
associated
with entry into
various areas of the plant.
The inspector discussed
the scope
and
'rogress
of the audits with licensee
gA personnel,
who were scheduled
to
finish by September
1992.
a.
erator
Readin
s Ver'ficat
The licensee's
guality Assurance
Surveillance
(gP&A 92-0020,
Operator
Readings Verification) examined
55 STPs
and the associated
168 area entries
made during the month of March 1992.
Five apparent
findings were identified wherein the assigned
individual did not
enter the required zone for one step of the subject
STP.
In three of the five identified findings
a different member of the
crew did enter the required area.
The auditors
observed that in the
past it has
been
accepted
practice for someone
on watch in an area
where
known checks
are to be made, to offer to perform those checks.
This practice is not currently required to be documented
in any way.
In one of the five identified findings, subsequent
investigation
revealed that the necessary
observations
(observe
backup air bottle
pressure
to the
10% atmospheric
dump valves in the pipe rack) could
be and
on occasion
were
made without entering the area.
The last discrepancy
found was for a verification of no leakage
from
the Unit 2 reactor vessel
level indication system,
which is only
required for Unit 2 until
a design
change is implemented.
The
licensee
also found that the individual responsible for that reading
entered
what would have
been the correct data for the
same
area for
Unit 1.
At the end of the report period, the licensee
was
evaluating
whether this could have
been
a case of looking at the
wrong unit.
-13-
'
The licensee
also investigated
the time that operators
spent in the
area for six activities which required
95 observations.
Based
on
timed runs for completing these activities, the time licensee
personnel
spent in the subject
areas
appeared
acceptable.
The audit team's initial conclusions
were that there
was
no generic
problem of falsifying records at Diablo Canyon,
but that additional
auditing should
be conducted to determine if some individuals may
not be completing activities properly.
The licensee anticipated
that additional future audits of plant activities would be
conducted.
The Operations Director had determined that the
surveillance test procedures
(STPs)
needed to be revised to ensure
that specific individuals are accountable for STP check-offs.
The
licensee is tracking this activity through action. request
A0264320.
b.
adiolo ical Surve
s
n-Secur t
on
s
The licensee's
guality Assurance
Surveillance
(gP&A 92-0022,
Radio-
logical Surveys in Security Zones)
was scheduled
to be completed in
July 1992.
This audit's objective was to verify that radiological
surveys
had
been performed.
In Hay 1992, licensee
personnel
had
identified an individual who had falsified surveys.
That individual
was suspended
and subsequently
dismissed.
As of the end of the
reporting'eriod,
no other examples of record falsification had
been
identified.
c ~
0cus
s'he
inspector
concluded that the licensee
has
an adequate
plan to
determine
whether
logs
and surveys
were being falsified.
The
3icensee
appeared
to be dealing vith the preliminary findings in an
appropriate
manner.
This item will remain open until the subject
audits are concluded
and the licensee
has determined
any necessary
corrective actions.
(50-275/92-20-02)
No violations or deviations
were identified.
10.
ack of Criteria for Locked Valves Othe
Than Those Listed In Techn cal
S ecifications
92 00
The inspector noted'hat
the valves in the
EDG air start
system were not
sealed valves,
nor was there indication of the valve position.
These
valve's positions
appear to be important to safety,
since
EOG start
during
a design basis
event could be prevented
.by mispositioned
valves.
The inspector
noted that valves listed in TS appeared
to be sealed.
However,
no criteria existed for selection of other valves which should
be sealed.
The licensee
agreed to review and document the criteria for
determining which valves should
be sealed,
and initiated
an Action
Request.
No violations or deviations
were identified.
-14-
d
ll.
nade
uate
0 erabilit
valuation for Char in
Ca abilit
Durin
Safe
~dk kd
dkk
~kd
Both centrifugal charging
pumps
(CCPs)
are located in the
same fire
area,
with about
seven feet of separation.
The Fire Hazards
Analysis requires that, if a fire were to occur in the
CCP room, the
positive displacement
charging
pump
(PDP)
be used
as
a source of
charging to achieve
In 1989, the licensee
determined that operation of the
PDP caused
cracking of its piping,
and performed extensive troubleshooting
and
maintenance
work on the
PDPs in both units, without recognizing the
safe
shutdown function of the pump.
As a result of the
pumps'xtended
time out of service,
the
NRC issued
(Inspection Report No. 89-33), which addressed
the lack of admini-
strativee
controls
on the
PDP operability, since the
PDP would have
been required to operate
during
a fire in the centrifugal charging
pump
(CCP)
room.
k. ~ddi
On August 29,
1990, the licensee
issued
Revision
1 of JCO 90-17,
which stated that the
PDPs were inoperable,
and that Abnormal
Procedure
AP A-17, "Loss of Charging" could be used for plant
shutdown
and cooldown if a fire occurred in the
CCP room.
Five
additional revisions to the
JCO have
been
made
as
a result of
inadequacies
identified by the
NRC and by the licensee.
'Revision
6 of JCO 90-17 relied on:
1.
he
Use Of the
PDP fo
Safe
utdown.
At the time of this
inspection,
the positive displacement
charging
pumps
had
been
declared
inoperable for nearly two years.
Plant Operations
was
informed that the
PDPs
are available for emergency
use only.
At high speeds,
the
PDP suction lines have exhibited high
vibration, resulting in pipe cracking.
The suction lines have
been replaced;
however, the vibration can still occur.
quar-
terly surveil1ances
(STP P17-8)
have
been
run to demonstrate
that the
pumps produced rated pressure
and flow.
However, the
length of time at high speed
before pipe cracking will occur
has not been established.
This is significant because
the
design basis fire, involving loss of offsite power, will cause
the
PDP speed control to fail high.
2.
Houri
Fire Watches
Su
ression
and Detection
and
imited
Combustibles
in the
CCP Room.
The centrifugal charging
pumps
and their associated
circuits are not separated
by 20 feet
distance
or by a fire barrier.
The licensee
has stated that
temporary compensatory
measures
in place
comply with the intent
of a fire barrier impairment.
The inspectors
noted that
between June'8
and July 6,
1992,
2 bags containing anti-
contamination clothing were placed
between
the Unit 2 CCPs,
-15-
'
thereby providing intervening combustibles
which could
propagate
an oil fire.
3.
Use
o
OP AP-17
P
t Shutdown Durin
Loss
o
A
1 Char in
.
Revision
6 and earlier revisions of JCO 90-17 stated that, in
the event all charging
pumps were unavailable,
AP-17 would be
used.
The inspector determined that
a circuit analysis
had not
been
accompli'shed to determine whether circuits associated
with
the safe
shutdown equipment required
by that procedure
were
protected
from the effects of a design basis fire in the
fire area.
Additionally, OP AP-17 noted that level
may be lost
in the pressurizer
during shutdown,
and required
in that case.
This appeared
inconsistent with 10 CFR 50,
Appendix R, Section L.2.b. which requires that the reactor
coolant
makeup function be capable of maintaining level within
the indicating band of the pressurizer.
The licensee
revised
AP-17, based
on using the procedure
during this particular fire
scenario.
Later, the licensee
stated that AP-17 would not be
referenced
by the next revision of JCO 90-17,
since the
JCO
would rely on prevention of a fire in the
CCP room by the
compensatory
NRC Inspection
Report 92-05 documented that the licensee
planned to
issue Revision
7 of the
JCO by April 1992.
The revision had not
been
issued
as of the end of this inspection, raising concern
about
the continuing lack of resolution of this issue.
C.
Conclusions
The licensee
has established
neither that the
PDP will operate to
fulfillits design
b'asis fire protection function, nor that any
charging will be available in the event of a fire in the
CCP room.
Additionally, no circuit analysis
has
been
conducted to demonstrate
that AP-17 could be used to complete
a safe
shutdown after
.a fire in
the
CCP room.
The licensee
had initiated temporary compensatory
measures,
however,
have
now been in effect for nearly
2 years.
The
inspector concluded that the licensee
had failed to provide adequate
instructions to the operators
regarding the use of the
PDP.
Although the
PDP was tagged for emergency
use only, no instructions
were provided regarding precautions
to take to prevent pipe cracking
or the circumstances
under which it should or should not be used.
This is considered
a violation (50-275/92-20-03).
12.
Simulator Observation
41701
On June ll, 1992, the inspectors
reviewed simulator scenarios for annual
operator licensing requalification testing,
observed
operator
examina-
tions at the simulator,
and attended
the associated
critiques
by the
licensee.
The scenarios
used included (1) steam break with inadvertent
containment
spray,
(2) gas decay tank rupture,'3)
letdown heat
exchanger
leak with steam generator
tube rupture,
and (4) bus
G undervoltage with
LOCA..
The four accident
scenarios, for the simulator appeared
to have
-16-
been well prepared
and appropriately challenging to the operators.
The
operators
appeared
to complete required actions,
communicated effective-
ly, and performed well as
a team.
The associated
evaluator critiques
appeared
factual
and adequately critical.
The licensee's
Operations Di-
rector observed
the evaluations
and provided
an appropriate
verbal cri-
tique to the operators
and the evaluators
at the conclusion of the
testing.
No violations or deviations
were identified.
ensee
vent
Re ort
ollowu
92700
0 CFR 50
A
endix
R
Safe
Shutdown Circui
Se aration Defic encies
R 50-
3
9 -
ev'sio
osed
In addition to Unit 2 .EDG field circuit separation
concerns identified in
Revision
0 of this
LER, the licensee identified eight additional condi-
tions of inadequate circuit separation.
Each
appear
to have
adequate
temporary compensatory
measures
in place,
and appropriate corrective
action scheduled
or under review.
Four of these
were reported
as one-
hour non-emergency
reports,
and four conditions of lesser significance
were only documented
in the
LER, but were not reported
as one-hour non-
emergency reports.
The lack of the latter four being reported
as one-
hour non-emergency
reports
according to 10 CFR 50.72 is discussed
below
in Unresolved
Item 50-275/91-01-01.
e
tern
ol
owu
92703
a.
nade
uate Determination of Re ortabil t
Of Licensee-Identified
ire
P otect
o
e icie c es
50-2
5 91-0 -01
0 en
This open item follows ongoing actions
by the licensee to review
safe
shutdown circuit separation
and other fire protection
requirements.
As a result of this effort, eight deficiencies
have
been identified which the licensee
considers
outside design basis.
The licensee
reported four of the items with I-hour non-emergency
reports,
discussed
earliet
in the Follow-up of Licensee
Event
Reports section of this inspection report.
However, the licensee
determined that the other four conditions were not reportable,
because
they were of low safety significance.
The inspector
concluded that three of those
items are significant to safety,
and
meet the requirements of 10 CFR 50.72 to perform
a one-hour non-
emergency report to the
NRC.
These
are
as followsi
{1)
Auxiliar Saltwater
Pum
and Associated Ventilation Circuitr
The licensee identified that circuits from both of the
auxiliary salt water
{ASW) pumps,
as well as circuits of the
associated
ventilation systems,
did not have the required
three-hour fire barrier,
although they were located in the
same
fire area.
The redundant circuits are
on opposite sides of a
vault, in the
same fire area.
There is no area-wide
suppres-
sion or detection.
However, combustible loading near the
circuits is light, and the main combustible
loading in the fire
- 17-
(2)
area,
the circulating water
pump oil supply,
has
a cardox
suppression
system in a partially enclosed
area,
and is at
a
slightly lower elevation.
Also,
smoke detectors
are installed
at the
ASH pump vault entrance.
The licensee
considers
the likelihood of a fire in the area
which wo'uld travel around'he vault to destroy both trains to
be unlikely.
iesel
Generator
Emer enc
Sto
and
CO
Sw tch Thermola
n
osu
s
~Bk
d: ttttt ttt
d
y td Itt
dtt
Cardox actuation .switches,
each of which can disable
an
EDG,
were enclosed
in Thermolag without the required structural
support for this type of fire barrier.
On November 15,
1991,
the licensee
recognized the deficiency,
and
initiated work to correct the fire barrier.
Removal of F'
arr er:
After portions of the, inadequate fire
barrier were removed during corrective actions,
technicians
stopped
work because
materials
were not available to finish the
job.
The circuits were left without a fire barrier,
and
without an evaluation of the safety of the condition.
The
licensee later recognized
the removal of the fire barrier.
The
CO, switches
are separated
by less than three feet.
The
EDG emergency
stop switches
are separated
by about
20 feet.
Hourly fire watches
have
been in place since
commercial
operation'.
The combustible loading of the area is light, and
suppression,
but not detection,
is installed.
These switches
control redundant
EDGs used for safe
shutdown,
and therefore
are not in compliance with Appendix R.
The licensee
considers that the basis for reportability is
Generic Letter 86-10, requiring postulation of only a single
spurious actuation in a given fire area,
since the failure mode
- is
a hot short.
The licensee
considers that, according to
a fire near the unprotected
EDG or CO, switches
would
result in only one spurious actuation,
and therefore disable
no
more than
one of the three
EDGs.
Therefore,
the licensee
considers that even without fire wrap enclosures,
the plant
design basis
has
been met,
and therefore the condition is not
reportable.
The inspector noted that the rationale
above would imply that
no circuit separation
deficiency involving hot short
vulnerability would be reportable.
Power
0 crated Relief Valve and Auxiliar
S ra
Valve Circuitr
The licensee
determined that safe
shutdown
equipment required
for transition from hot shutdown to cold shutdown
may be
vulnerable to fire damage if a fire occurs in containment
or in
-18-
the motor generator
set
room.
Specifically, circuits for the
PORV and auxiliary spray valves
do not have required protection
in four fire areas,
one being containment.
Combustible loading in the areas
outside containment consists
mostly of cable.
Two areas
are provided with detection
and'utomatic
suppression,
and the other two areas
(one being
containment)
have detection only,
and
PORV and auxiliary spray
cables
routed in metal conduit.
All areas
except containment
have
had hourly fire watches.
The licensee
considers that the vulnerability would have
been
recognized,
and repairs could have
been successfully
developed
using similar temporary jumper procedures
while the plant was
in hot shutdown,
before attempting transition to cold shutdown.
For each of these
above conditions outside design basis,
the
inspector considers
that the lack of appropriate circuit separation,
and the need for previously unidentified operator actions,
are
outside the design basis.
Therefore, this appears
to be
a violation
of the requirements
to make
a 1-hour non-emergency
report pursuant
to 10 CFR 50.72.{b)(2)(ii)B {50-275/92-20-04).
Continuing followup
of the licensee's
program to identify Appendix
R deficiencies
and
evaluation of the significance of the findings will be tracked under
Unresolved
Item 50-275/91-01-01.
b.
orrosion
o
Outdoo
Com onent
50-323 89-
-05
C osed
C.
This item was opened to follow the licensee's
action concerning .the
corrosion of components
in outdoor environments.
As a result of the
corrosion discovered
on
ASW and
.EGG fuel oil system piping,
and the
associated
.followup item 50-275/92-20-01,
the licensee's
actions
concerning corrosion of outdoor components will be followed as part
of the routine resident
inspection activities associated
with
Unresolved
item 50-275/92-20-01.
Therefore,
Followup Item 50-323/
89-21-05 is closed.
Corroded Auxiliar Saltwater Trai
Crosstie
Valves
Unreso
ved Item
50-275 90-30-02
Closed
This unresolved
item addressed
the degradation of the auxiliary
saltwater
(ASW) train crosstie
valves
due to corrosion
and the
licensee's
failure to take adequate
corrective actions to prevent
recurring degradation.
The inspector
reviewed the nonconformance
report associated
with
this issue
(NCR OCl-EN-009)
and the licensee's
design basis for the
ASW valves.
The inspectot
noted that the licensee
has taken action to ensure
that the reliability of the
ASW crosstie
valves
has
improved.
However,
NCR DC1-EN-N009 did not address
the timeliness of
corrective action or missed opportunities.
In addition, the
inspector
asked questions
regarding the use of a non-safety related
-19-
actuator
on
a safety related valve.
The licensee
committed to
address
the questions,
which, will be reviewed in a future
inspection.
lstor
Each unit has
two ASW pumps
and two ASW heat exchangers
which supply
normal
and ultimate heat sink cooling for the component cooling
water system.
The two ASW trains are crosstied
at the
pump
discharge.
Each crosstie line has two normally open motor operated
isolation valves
(1-FCV-495,
1-FCV-496, 2-FCY-495,
and 2-FCY-496).
Between crosstie valves is a line which crossties
the units.
The
unit crosstie
valve 0-FCV-601 is normally closed.
The crosstie
valves were designed
as safety related for purposes of
maintaining
ASW system integrity.
The crosstie
valves are required
in the
Emergency Operating
Procedures
(EOPs) to be closed to isolate
ASW trains- in the event of the failure of the pressure
boundary of
one train.
However, the licensee
concluded in their design analysis
that there is no design basis failure of one train which would
require that the trains
be isolated.
Therefore,
the crosstie valve
motor operators
were considered
non-safety related.
On Hay 23,
1989,
1-FCV-496 would not close
when operated
from the
control
room and could not be manual.ly operated
due to excessive
corrosion.
A quality evaluation
{gE, a lower level of non-
conformance
review) was initiated
(when it was recognized that the
EOPs required the valve to be operated)
to provide root cause
review
and initiate corrective action (Inspection
Report No. 50-275/89-14).
In June
1990, the licensee
again discovered that the valve could not-
be manually operated.
After an initial attempt to free the
'andwheel,
the job was put on hold.
In January
)991, the inspector
noted the action request
tag on the valve and questioned
why
maintenance
had not been performed
and whether the corrective
actions following the Hay,
1989 event
had
been
adequate.
The licensee
was able to free the handwheel
using lubrication and
considerable
force.
Non-conformance report NCR-DC1-91-EH-09 was
initiated to review this problem.
NCR-DC 1 -91-EH-09
The inspector
reviewed non-conformance
report
(NCR) DC1-91-EH-09.
The resolution of the
NCR provided two corrective actions to prevent
recurrence:
The quarterly crosstie
valve surveillance tests
{STP V-3F1 and
V-3F2) were revised to require that the handwheel
be rotated.
~
The frequency of preventive maintenance
was increased.-
-20-
These actions
should increase
the reliability of the crosstie valve
operators.
However, the inspector did not find any action which
would have addressed
the untimely licensee
action to resolve the
degradation
of the operators.
~
The
NCR did not address
why the
gE initiated in 1989 did not
provide for timely action to prevent recurrence.
Inspection
Report
No. 90-30 stated that the
NCR chairman would include
a
review of the
1989
gE in the
NCR review.
~
, The
NCR did not provide any administrative
means to ensure that
corrective maintenance
would be performed in a timely manner.
The inspector reviewed this issue with the individual in work
planning responsible for establishing
the priority of
corrective maintenance.
Since January
1991, the licensee
has
initiated two administrative procedures for ensuring that
important equipment receives priority attention.
Neither
procedure
was applied to the
ASW crosstie valves.
The Equipment Control Guidelines,
(Administrative Proce-
dure A-58) required priority attention for equipment which
was required for system operability but which was not
specifically called out in the Technical Specifications.
In 1991, the inspector
w'as informed that the
ASW system
crosstie
valves would be considered
under this program.
k
The balance-of-plant reliability program
(AP C-55) listed
important non-safety related
equipment that should receive
quality review and priority assignment.
The
ASW crosstie
valves were not included in this list.
~
The
NCR failed to address
why an operations policy regarding
the maintenance of equipment called out in Emergency Operating
Procedures
was not implemented.
Operations
Policy. C-9,
"Control of Safety Related
Equipment
Not Required
By Technical
Specifications,"
stated that this equipment
would be treated
the
same
as Technical Specification equipment.
The inspector
discussed
these findings with the licensee
on July 10,
1992.
Although the resolution of the
NCR provided increased
reliability of the
ASW valve operators, it did not thoroughly
address
why they had not received higher priority attention.
The
licensee
committed to review these
issues..
esi
n Anal sis
The inspector
reviewed the crosstie
valve operator design analysis.
The inspector raised the following questions:
~
FSAR chapter 3.6.1 discussed
the moderate
energy pipe crack
analysis for the
ASW system.
It indicated that the
ASW system
could withstand
a moderate
energy pipe crack
and that the
consequences
were mitigated by ASW pump room floor drains.
The
-21-
'
inspector
observed
on
a walk down that the room floor drains
were small
and only slightly larger in diameter than the
pump seal leakoff line hose which ran through it.
The
inspector also noted that the
ASW Design Criteria Memorandum
did not discuss
design for a moderate
energy pipe break.
~
The inspector questioned
whether
an analysis
had been performed
to determine if the crosstie operators,
which were not
seismically qualified, could stroke to a non-conservative
position during
a seismic event.
Additionally, he questioned
whether this had been
analyzed for other non-safety related
operators
on safety related valves.
~
The inspector determined,
through discussions
with a licensee
motor-operated
valve specialist,
that the auxiliary crosstie
valve operator,
with its to} que and limit switch settings
misadjusted,
could not malfunction in a way which would breach
the
ASW pressure
boundary.
The inspector questioned if this
was the case for other non-safety related operators
on safety
related valves.
The licensee
indicated that these
issues
would be reviewed
{Followup
Item 50-275/92-20-05).
ormat on Heetin
Mith the I de endent Safet
ev'ew Committee
94600
On June
25, the resident
inspectors
attended
the meeting of the
Independent
Safety Review Committee in Arroyo Grande,
CA.
The purpose of
attending the meeting
was to ensure that the resident
inspectors
were
aware of the issues
discussed
by the committee.
16.
ana
ement Heetin
to Discuss Resolution of Nonconformance
Re ort
On June
22,
1992,
members of licensee
management
met with NRC management
representatives
in the Region
V Office to discuss their resolution of
deficiencies
involving qualification of equipment for an earthquake
on
the Hosgri fault.
The following persons
were in attendance:
acific Gas
8 Electric
Com
an
M. Fujimoto, Vice President,
Nuclear Technical
Services
H. Tresler,
Diablo Canyon Project Engineer
J. Tompkins, Nuclear Safety
and Regulatory Affairs Director
RC
Re ion
V
R. Zimmerman, Director, Division of Reactor Safety
and Projects
S. Richards,
Chief, Reactor Projects
Branch
L. Hiller, Chief, Reactor Safety Branch
P. Johnson,
Chief, Reactor Projects Section
1
M. Ang, Project Inspector
D. Corporandy,
Reactor Inspector
-22-
RC Office of Nuclear Reactor
Re ulation
b
hone conference
H. Rood, Project Hanager
G. Bagchi, Chief, Structural
and Geosciences
Branch
The licensee
representatives
stated that the extensive
review was
including an update of documentation relating to Hosgri commitments to
ensure
document clarity and compatibility.
They stated that the review,
which would be completed
by the end of 1992,
had identified no findings
which involved safety significance or which required plant modifications.
A copy of the materials provided by the licensee
during the meeting is
enclosed with this inspection report.
17.
t
eet
n
An exit meeting
was conducted
on July 15,
1992, with the licensee
representatives
identified in Paragraph
1.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.
The licensee
did not identify as proprietary any of the materials
reviewed by or discussed
with the inspectors
during the inspection.
Enclosure:
Copy of discussion materials
provided by the licensee
during the
June
22,
1992 meeting
{paragraph 16).
PRESENTATION TO NRC
NONCONFORMANCE ON
HOSGRI
COMMITMENTS
JUNE 22, 1992
WALNUT CREEK
M. R. Tresler
Diablo Canyon Project Engineer
NCR 90-EN-N027
Problem:
Cause:
Solution:
Configuration Control
Hosgri Seismic
Qualification Files Not Maintained
or Controlled
for Some
Plant
Equipment
Hosgri Commitments
Not Adequately
Transferred
or Maintained
in Design
Documents
and
Some
Incorrect Interpretations
were
Made Related
to Seismic
Qualification of Equipment
Licensing Documents
Reviewed
to Assure
Equipment
Requiring Qualification to Hosgri is Qualified
and Files
in Place
Establish
or Reestablish
Qualification Files
when
Required
Update
Engineering
Documentation
and
USAR when
Required
MAT2A
t
+c
NCR 90-EN-N027
~
Hosgri Background
~
Discovery
~
Findings/Status/Schedule
~
Summary
~
Significance
Configuration Control Closure
No Plant
Modifications Required
~ p
BACKGROUND
~ Original Design:
DE/DDE
~ Hosgri:
1976-1978
Special
Rules
Scope
Methodology
Material Properties
. Allowables
- HotlCold Shutdown
Path
Class
II Seismic
Upgrade
OISCOVERY
~
November
12,
1990:
SSIP
Walkdown
.
~
Boric Acid Storage
Tank
Level Indicator
Investigation
Hosgri Seismically
Induced
System
Interaction
Manual
Target.
Class
II Non Seismic
on Schematic
But Required
for Cold Shutdown.
Level Indicator Now Qualified
Review
Hosgri Report
Complete
~
Qualification
Instrumentation
Valves
Electrical Equipment
.
Battery
Operated
Lights
~
Configuration
Control
Plant
Configuration
Control
Qualification Requirement
Identification
USAR Update
~
Licensing
Documentation
Hosgri Report
Correspondence
I
ty ~
FINOINGS QUALIFICATION
~ Instrumentation
for Cold Shutdown - July
1991
indicated
as
Class
IB, Cat.
II- and
ill {Non-Setsmic}
Reg.
Guide
1.97
Downgrade
Qualification Classification
Hosgri Report
16 Specific Variables
System
Function
Resolution
15/16
Identical to Others
CCW Low Lube Oil Interlock Acceptable
Fire Water Storage
Tank
Level
DCN/Verify EOP
MRT6
t'/ALIFIICATIONS VALVES
~
Actions
Determine
Qualification Requirements
of
Valves'Active/Passive)
Perform
Analysis
Safety
Impact - No Plant
Modification
Required
to Date
MATdA
t q
QUALIFICATIONS- VALVES
(CONTINUEO ~~)
~ Scope
of Active Qualifications
- Hosgri Report
All Glass
I Qualified
All Active Valves Qualified
. Qualification Criteria Table
Active
Passive
Valve Lists
- -
Active
HS/GS
Passive
-'GGS
SSER
7
For active
valves that may be required
to
function to mitigate accidents,
functional
operability must
be assured.
(Refers
to
table 7-7 which is. titled GS/HS
only and
lists CS/HS
only.}
0
QUALIFICATION VALVES
(CONTINUED 4'2)
~
Status
USAR -
1986
Designed
to Function
Following Hosgri
Tables -- Same
as
Hosgri
Conclusion
Passive:
Practice
Interviews
Active Not Analyzed .-- 23/Unit - All Qualified
No Modification Required
Passive
Not Analyzed -- 130/Unit -
14
in Progress,
116
Complete
No Plant Modification Required
HVAC/Passive -- 11/Unit - Qualified
No Plant Modification Required
MRT7
~c
QUALIFICATIONELECTRICAL
EQUIPMENT/BATTERYOPERATED LIGHTS
~
Electrical Seismic
File Deficiencies
Reactor
Coolant
Loop Temperature
Transfer
Switch
Aux Spray
Transfer
Switch, Selector
, Switch,
and
Fuse
Holder
Now Qualified - No Modification Required
~
Battery. Operated
Lights
Qualified Ni-Cad
in 1978
Substantial
Addition and
Downgrade
of Existing
Lights
in 1983
per Appendix
R
Added
Lead - Acid to be
Qualified by Shake
Test
Complete
by September
1992
MATSA
0
r
CONFIGURATION CONTROL
~
Plant
Configuration Control
Class
ll Valves
Class
II instrumentation
To be
Design
Class
II/Seismic Cat
Special
Procurement
Maintenance
Program
Drawings/PlMS/Program/Procedures
-
Nov
Sample
Maintenance
Activities
~
Qualification Requirement
Identification
instrumentation
- Cold Shutdown
Electrical - Seismic
Qualification List
Complete
Sept
~
Add Cold Shutdown
Path
Update
Active Valve List
I
0'
g I'
SUMMARY
~
Update
Licensee
Documentation
~
Update
Records
and
Document
Clarity/Compatibility
~
No Safety
Significance
-
No Modification Required
~
Complete
this
Year
~
Qualify ECCS
Valves
as
Active
MRT10A
(.r
0'