ML16341F666
| ML16341F666 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 04/04/1990 |
| From: | Mendonca M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F664 | List: |
| References | |
| 50-275-90-05, 50-275-90-5, 50-323-90-05, 50-323-90-5, IEB-89-006, IEB-89-6, NUDOCS 9004230585 | |
| Download: ML16341F666 (30) | |
See also: IR 05000275/1990005
Text
U.
S.
NUCLEAR REGULATORY
COMMISSION'EGION
V
Report Nos:
50-275/90-05
and 50-323/90-05
Docket Nos:
50-275
and 50-323
License
Nos:
Licensee:
DPR-80 and
Pacific Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
Facility Name:
Diablo Canyon Units 1 and
2
Inspection at:
Diablo'Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
January
28, through March 10,
1990
Inspectors:
P.
P. Narbut, Senior Resident
Inspector
K.
E. Johnston,
Resident
Inspector
Approved by:
en onca,
se
,
eac or
roJec
s
ec
son
~/W4 go
a
e
>gne
Summary:
Ins ection from Januar
28 throu
h March 10
1990
Re ort Nos.
50-275/90-05
an
/
Areas Ins ected:
The inspection
included routine inspections of plant
opera lons,
ma)ntenance
and surveillance activities, follow-up of onsite
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
30702,
30703,
37700,
37702,
40500,
42700,
61726,
62702,
62703,
71707,
92700,
92701,
92703,
92720,
and 93702 were used
as guidance during this inspection.
Safet
Issues
Mana ement
S stem
SIMS) Items:
None.
Results:
General
Conclusions
on Stren th and Weaknesses
Additional
E ui ment Lineu
Problems:
Twice during the inspection period
operators
ma
e sign>>cant
equipment lineup errors which affected the
operation of safety related
equipment
(paragraphs
4e and 4h).
The errors
indicated that operations
management
had not yet been fully successful
in
communicating their expectations
regarding the equipment lineup process
to
operations
personnel.
p0042-"
~~~a
@~i()0027'>
~~g
cyPO404
PI3R
AG~
'gC
Q
Desi
n Mork Concerns:
In this inspection period there were'wo concerns
on design work.
Paragraph
3c describes
a situation where security personnel
designing modifications to
the intake area security barriers
based
design
assumptions
on inaccurate
information regarding the normal configuration of the auxiliary
saltwater'ystem.
Although this did not result in a violation of the licensee's
security plan, it indicated
a weakness
in the communications
between security,
plant engineering
and operations with respect to security design.
Paragraph
4j discusses
the last minute postponement
of the removal of the Unit 2 Boron
Injection Tank due to design
problems discovered
by both design Engineering
and equality Assurance.
Failure to Reco nize and Elevate
Problems
In September
1989, general
construction personnel,
excavating for a design
modification, unearthed
and gouged safety related auxiliary saltwater
piping
without recognizing the significance of the act and did not notify plant
management
or initiate the required problem reporting process
which resulted
in a violation (paragraph
5a).
Timel
0 erator Action
At the start of the Unit 2 refueling outage,
Operators
on Unit 2 recognized
and took corrective actions'to
address
a rather obscure potential
Residual
Heat Removal
system suction valve isolation problem (paragraph
4).
Good Problem Identification
Although also mentioned
as
a design
w'ork concern,
Engineering
and
gA
identified problems with the Boron Injection Tank removal modification and
took conservative
action to postpone
the design
change.
Si nificant Safet
Matters:
None.
Summar
of Violations and Deviations:
One violation was identified
concerning
a) ure
o
a
e cor rec ive action - paragraph
5.a.
0 en Items
Summar
18 open item were closed in this report.
One was opened.
DETAILS
Persons
Contacted
J.
D.
D.
B.
+M. J.
B.
W.
"W.
G.
+W.
D.
~T.
A.
~D.
A.
- 7
H. J.
D.
P."
+R.
C.
- J ~
A.
M.
G.
- S.
R.
+R.
E.
C.
Townsend,
Vice President,
Diablo Canyon Operations
and Plant
Manager
Miklush, Assistant Plant Manager,
Operations
Services
Angus, Assistant Plant Manager,
Technical
Services
Giffin, Assistant Plant Manager,
Maintenance
Services
Crockett, Assistant Plant Manager,
Support Services
Barkhuff-, equality Control Manager
Bennett,
Mechanical
Maintenance
Manager
Taggert, Director equality Support
Grebel,
Regulatory Compliance Supervisor
Phillips, Electrical Maintenance
Manager
Brooks, Acting Work Planning Manager
Acting Instrumentation
and Controls Manager
Shoulders,
Onsite Project Engineering
Group Manager
Burgess,
System Engineering
Manager
Fridley, Operations
Manager
Gray, Radiation Protection
Manager
Connell, Assistant Project Engineer
The inspectors
interviewed several
other licensee
employees
including
shift foremen
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general
construction/startup
personnel.
- Denotes those attending the exit interview on March 23,
1990.
Also attending the exit meeting
was Marvin M. Mendonca,
NRC Section
Chief.
2.,
0 erational
Status of Diablo Can
on Units 1 and
2
At the beginning of the report- period, both Units 1 and
2 were at full
power.
On February 20,
1990, operators
manually tripped Unit 1 following
the closure of the feedwater regulating valves which was apparently
precipitated
by surveillance activities in the solid state protection
system cabinets
(see Section 4.b).
.On February
22,
1990, the licensee
. gagged
one of three Unit 2 pressurizer
safety valves, after receiving
an
emergency
Technical Specification
change,
when its leakage
increased
(see
Section 4.c).
On March 4, 1990, Unit 2 shut
down for its third refueling
outage.
At the end of the report period, Unit 1 was at full power and
Unit 2 had just entered
Mode 6; core alterations.
On February 2, 1990,
a team inspection,
which reviewed the corrective
actions
and oversite
programs,
conducted
an exit meeting
(see Inspection
Report 50-275/90-01).
On February
12,
1990, after a temporary injunction
was lifted, random drug screening
began for applicable
union members.
3.
0 erational
Safet
Verification (71707)
a.
Gener al
b.
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 inspectors
observed control
room activities to
verify compliance with selected
Limiting Conditions for Operations
(LCOs) as prescribed
in the facility Technical Specifications
(TS).
Logs, instrumentation,
recorder traces,
and other operational
records
were examined to obtain information on plant conditions,
and
trends
were reviewed for compliance with regulatory requirements.
Shift turnovers
were observed
on a sample basis to verify that all
pertinent information of plant status
was relayed.
During each
week,
the inspectors
toured the accessible
areas of the facility to
observe
the following:
(a)
General plant and equipment conditions,
(b)
Fire hazards
and fire fighting equipment.
(c)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved procedures.
(d)
Interiors of electrical
and control panels.
(e)
Plant housekeeping
and cleanliness.
(f)
Engineered
safety feature
equipment alignment
and conditions.
(g)
Storage of pressurized
gas bottles.
The inspectors
talked with operators
in the control
room,
and other
plant personnel.
The discussions
centered
on pertinent topics of
general
plant conditions,
procedures,
security, training,
and other
aspects
of the involved work activities.
Radiolo ical Protection
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,
including the Diablo Canyon project inspector,
observed
the activities at the access
point for the radiological
controls areas
(RCA) on February 21; 1990, prior to the start- of the
Unit 2 refueling outage.
The inspectors
noted that personnel
leaving the area were not.exercising
good radiological practices,
in
that opportunities for potentially contaminated
personnel
to
contaminate
clean personnel
were being created.
The licensee
uses
personnel
contamination monitors
(PCMs) to monitor
personnel
exiting the
RCA.
The
PCMs are sensitive
and detect
naturally occurring radioactive
and its daughter products.
The licensee
has
had the long-standing
and
common problem of radon
adhering to clothing by electrostatic
charge.
The extent to which
radon is present in the auxiliary and fuel handling buildings is in
large part dependent
on atmospheric conditions.
The inspectors
observed
a situation where,
on a relatively high
concentration
radon day, approaching
lunch time, with one of the
three
PCMs out of service,
approximately half of the people
attempting to exit the
RCA were alarming the
PCMs and
a substantial
line (10-15 people)
had developed.
The radiation protection
(RP)
technician responsible
for monitoring personnel
and equipment
leaving the
RCA appeared
to be overwhelmed with responding to the
alarms
and performing other tasks
such
as frisking equipment.
As a
result,
personnel
were performing self analysis of their alarms
and
loitering in line to allow radon to decay.
This presented
the
opportunity for personnel
who had alarmed the
PCMs,
and who might
have
been genuinely contaminated,
to potentially contaminate
uncontaminated
personnel.
The inspectors
presented
these findings to the
RP manager.
The
manager
stated that radon
was not a health risk in the levels
existing in the auxiliary and fuel handling buildings but the number
of resultant
alarms at the
RCA exit area
tended to reduce
employee
sensitivity to alarms.
He noted that
PG8E had plans to reduce the
radon levels, possibly including the capping of a well used to
evaluate
water conditions at the containment
base.
Also, the
licensee
is considering
reducing the frisker s sensitivity to radon.
However, the
RP manager
agreed that
RP technicians
need to control
RCA exits to ensure all alarms
are adequately
assessed.
The
inspectors will observe
the licensee's
actions
regarding this matter
in future inspections.
Ph sical Securit
71707
Security'activities
were observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative procedures.
On January
30, 1990, the inspector
examined the seawater
intake area
including recently completed modifications to the security
boundaries.
The inspector identified two apparent
examples of vital
auxiliary saltwater
system
(ASWS) equipment located outside
a vital
area
boundary.
The specifics
are not discussed
here
because
they
are security safeguards
information.
These findings were discussed
with the security manager
who
initiated a review of the findings and
an evaluation of the intake
security modifications.
Subsequently,
a third apparent
example of
vital
ASWS equipment located outside
a vital area
boundary
was
identified by the licensee.
~
~
The licensee's
analysis of the potential
consequences
of the three
findings assumed
the worst postulated
challenge
in accordance
with
the security plan and the effects
on
ASMS operation,
In all cases
it was found that existing control
room annunciation
and
proceduralized
response
would successfully mitigate event
consequences.
Although the potential
consequences
of the findings were not
signifscant
when
a security analysis
was performed,
they pointed to
a weakness
in the security design process.
In the two examples
identified by the inspector,
the design decisions to not include the
equipment in a vital area
were based
on faulted assumptions
of
normal
system operation.
No changes
to the security boundaries
resulted
from the licensee's
.
evaluations.
However the uncertainty which existed indicated
a
weakness
in the'ommunication
between security designers,
who have
in-depth
knowledge of the security plan but not of system operation,
and operations
and engineering
personnel,
who have in-depth
knowledge of system operation
and design but not of the security
plan.
The inspector discussed
these
concerns with the security manager
who
agreed that the interface
between security and operations
required
improvement
and committed to do
a thorough evaluation of the cause
and pursue appropriate corrective actions.
The inspector will
follow the licensee's
actions
in the course of routine .inspection.
No violations or deviations
were identified.
4.
Onsite
Event Follow-u
93702
a e
b.
Minor Earth
uake Near Diablo Can
on
On February 6, 1990,
an earthquake
of approximate
magnitude 3.6 to
3. 9 occurred '30 to 60 miles south-southwest
of the plant.
Although
most plant personnel
did not feel the earthquake,
the earthquake
triggered sensitive monitoring devices.
A plant individual did feel
physical motion and notified the control
room.
Consequently
an
Unusual
Event was declared
and plant walkdowns were initiated in
accordance
with procedures.
No damage
was identified by the
walkdowns.
Ground acceleration
was later measured
to be 0.002 g.
Unit 1 Manual Reactor Tri
Followin
Re ulatin
Valve
osure
At 5:30 a.m.
PST on February 20,
1990, Unit 1 reactor operators
manually tripped the reactor
from 100K power in response
to the loss
of both main feedwater
pumps.
All safety systems
responded
.
normally.'he licensee
made
a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency
report to the
NRC and documented
the event in a written report in accordance
with
The licensee's
LER (Licensee
Event Report) 1-90-02 provides
an
accurate
description of the event and detailed explanations
of the
licensee efforts to identify the cause of the event.
Therefore
those facts will not be repeated
here.
The resident inspectors
observed
licensee
management
actions in the
event analy'sis
and attended
the plant staff review committee meeting
which approved restart of the unit.
Licensee investigative actions
were observed to be well planned
and conservative.
LER 1-90-02 is
considered
closed.
Unit 2 Leakin
Pressurizer
Safet
Valve Ga
ed
On February 21,
1990, the licensee installed
a gagging device
on one
of three safety valves
on the Unit 2 pressurizer.
The safety valve
(8010B)
had been
observed to leak on February
20.
Operators
had
observed
elevated pressurizer tail pipe temperature,
spikes in the
pressurizer relief tank (PRT) pressure,
increased
PRT level,
and
acoustic monitor alarms
on Unit 2.
These
were the
same
leakage
characteristics
that were observed
on Unit 2 safety valve 8010A
in March 1989 which ultimately resulted in a plant shutdown for
repair.
Prior to these
events,
in anticipation of such
an occur rence,
on
January
25,
1990, the licensee
submitted
a license
amendment
request
to allow continued operation with one inoperable
and gagged
pressurizer
safety valve.
On February 20,
1990 in response
to the
valves condition, the licensee
requested
an emergency
Technical
Specification
(TS) change for a one time exemption to allow
continued operation with one inoperable,
gagged pressurizer
safety
valve.
In their analysis,
the licensee
considered
the possible
consequences
on affected design basis
accidents
and concluded that
over-pressure
protection limits of the accident analysis
could be
met with two of three safety valves operable.
For conservatism,
the
licensee
included in their revised
TS a requirement to have
one
and available pressurizer
power operated relief valve.
On
February 21, the
NRC approved the emergency
TS amendment
and the
safety valve gag was installed.
On February 26, operators
noted
a partial return of the symptoms
described
in the first paragraph.
Maintenance
personnel
inspecting
the valve observed that the gag
had loosened.
The licensee
consequently
obtained
a torque value for the gag from the safety
valve manufacturer
and tightened the gagging device.
Following the shutdown for the Unit 2 refueling outage,
the
inspector
noted that the gag was again loose.
This was discussed
with the maintenance
manager
who discussed
plans to have
a gag
designed with a locking mechanism for any future use.
Movement of Hi
h Radiation Material
Causes
Control
Room Ventilation
s
em
a ia son
etector
c ua ion
On February
22,
1990, the Unit 1 control
room ventilation system
shifted from normal
mode to pressurization
mode when radiation
monitor 1-RE-25 actuated.
1-RE-25, the
CRVS radiation monitor,
which actuates
at approximately 1.6 mr/hr, actuated
when radioactive
material
was transferred
from the Unit 1 spent fuel pool to a
shipping cask.
The radiation protection review prior to movement of the radioactive
material identified the fuel handling building radiation monitors
1-RE-58 and 1-RE-59 as potentially actuating,
but did not identify
the control
room radiation monitors, which are located outside
the
fuel handling building but are separated
only by sheet
metal walls.
The licensee
made
a four hour non-emergency
report after identifying
the event
as
an unanticipated
engineered
safety features
actuation.
The licensee will submit
a licensee
event report (LER).
The
inspector will review the
LER in a future inspection to evaluate
the
licensee's
actions.
Valve Line
U
Error Isolates
Boric Acid Transfer
Pum
1-1 Suction
On February 26, 1990, boric acid transfer
pump l-l was found running
in low speed with its suction valve closed.
It was subsequently
determined that the valve had been inadvertently isolated following
a boric acid batching operation approximately five to six hours
earlier.
At the time of this event,
the other boric acid transfer
pump (1-2) was out of service for seal repair but an alternate
boration flowpath was available
from the refueling water storage
tank through the charging
pumps.
The boric acid transfer
pumps are required in Technical
Specification
(TS) 3. 1.2.2 to support
a boration flow path from the
boric acid tanks to the reactor coolant system
(RCS).
The
TS allows
the boric acid tanks flow path to be out of service for up to 72
hours.
The boric acid transfer
pumps are also required to
recirculate
12X weight boric acid through the boron injection tank
(BIT).
Surveillance
requirements
are that this flow be verified
every seven
days.
In summary, while the loss of both boric acid
transfer
pumps resulted in a loss of BIT recirculation flow and
required entry into a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement, it had limited
safety consequences.
Additionally, although it had operated for
almost six hours with its suction valve closed, boric acid transfer
pump 1-1 was tested
on February
27 and found to be undamaged.
The suction valve was closed
due to operator error.
The licensee's
analysis of the event found the following contributing factors which
ultimately resulted in the closing of the
pump suction valve:
o
The boric acid batching job was being performed without
properly using the available procedure.
The auxiliary operator
(AO) was using the procedure
located at the auxiliary control
board and did not have
a copy for use in the field.
After
reviewing the procedure at the auxiliary control board,
the
made
a note to himself of the appropriate
valve to close,
he
left the note in his pocket
when
he dressed
to enter the
surface
contaminated
area to manipulate
the valve.
The
procedure
was not followed verbatim.
The
AO elected
not to
perform certain valve lineups to isolate
normal
pump suction
while draining the batch tank.
o
The
pump suction valve was probably not properly sealed.
The
valve seal
was subsequently
found broken but might have
been
broken by the A.O.
The licensee's
analysis
recognized
other minor contributors,
such
as
poor lighting and the absence
of a valve identification label, but
the root cause
was attributed to a lack of formality in performing
the job.
-In review of the event,
operations
management
determined that the
valve lineup program,
requirements
were adequate.
However, licensee
management
determined that management's
expectations
had not been
successfully
conveyed to the operators
performing the lineups.
As corrective action, in addition to the usual
event
summary
discussed
during turnover with all operation
crews,
the operations
manager
issued
a memorandum to all operations
personnel
which
restated
the elements
of the valve lineup program
and reemphasized
the necessity
to follow the program.
The memorandum
required that
all operators
read the memorandum,
sign that it had been understood,
and return
a signed
acknowledgement
to the operations
manager.
The
licensee
stated that this approach
was taken to successfully
communicate
the importance of valve lineups with all personnel
performing lineups.
The licensee's
corrective actions
seem
appropriate.
The inspectors will continue to evaluate
the adequacy of the
licensee's
equipment lineup programs.
RHR Suction Isolation Valve 0 erabilit
On March 6, 1990, through discussion with operators
in Unit 2, the
inspector
became
aware of a jumper which had been prepared
which
would allow the Residual
Heat
Removal suction valves to be opened if
for some
reason
they were inadvertently closed.
The operators
discovery of this rather obscure fact that due to the combination of
clearances
for outage
work the suction valves could be powered
closed but not powered
open again demonstrated their indepth
knowledge
and insight into plant operations.
This unlikely
circumstance
was
due to the work clearance
on the solid state
protection
system
(SSPS)
which was consequently
depowered.
Since
the
SSPS interlocks opening of the
RHR suction valves
under certain
conditions,
the operators
were precluded
from opening the valves if
they had inadvertently shut.
The operators
had prepared
jumpers
and
'arked
up electrical
schematics
to open the valves if the need
arose.
The inspector discussed
the situation with the assistant
plant
manager
(APM) for maintenance
and suggested
that
a more appropriate
solution would have
been to revise the work procedure for the
SSPS
to add the installation of the jumper as
a procedural
requirement to
de-power
SSPS.
The
APM agreed
and stated that the procedure
would
be so revised for future outages.
An action request
was issued to
track this action.
g.
Unit 2 Fuel Handlin
Buildin Ventilation Mode Shift Due to
na
e ua
e
roce ure
h.
On March 7, 1990, while performing a design
change
on the Unit 2
spent fuel pool radiation monitor,
2 RM-58, the fuel handling
building ventilation system
(FHBVS) transferred
from normal to
iodine removal
mode.
The transfer occurred
when the "high alarm"
relay associated
with RM-58 actuated.,
It actuated
when technicians,
following steps
in the design
change
package, lifted a lead which
supplied
power to the relay.
The relay, which actuated
on loss of
power, initiated the
FHBVS mode transfer to iodine removal.
The licensee
made
a four hour non-emergency
report since the
FHBVS
transfer
was classified
as
an unanticipated
engineered
safety
feature actuation.
A nonconformance
report
(NCR DC2-90-TI-N010)
was initiated.
The
NCR stated that
a licensee
event report (LER)
was required.
The inspector will review the licensee's
actions
during review of the
LER.
Isolation of Unit 1 Feedwater
Pressure
Transmitters
On March 9, 1990, Unit 1 was at 100K power,
and Unit 2 was shut
down
and in a refueling outage.
A senior control operator
(SCO)
performing valve lineups for a work clearance
on Unit 2, erroneously
isolated three Unit 1 steam generator
pressure
transmitters.
One of
the isolated pressure
transmitter outputs drifted from approximately
800 psig to 540 psig.
This resulted in alarms in the Unit 1 control
room.
The Unit 1 control
room operator
asked the Unit 2 operator if
they had
an evolution in process
which would produce
such
an
indication and the possibility of the isolation of steam generator
pressure
transmitters
on the wrong unit was quickly suspected.
An auxiliary operator
(AO) was dispatched
to intercept the
SCO.
The
Unit 1 transmitters
were then valved back in, seven minutes after
they had been isolated.
Two of the three transmitters
had not begun
to drift low. If one other transmitter
had drifted low, a reactor
trip and safety injection could have
been experienced.
The isolation of all three
pressure
transmitters
on
one
steam generator is not allowed by the Technical Specifications.
The licensee
made the appropriate
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
non-emergency
report
regarding the inadvertent entry into technical specification 3.0.3.
Although this was another
example of valve lineup problems,
the
inspector
was encouraged
with the self critical tone in the review
performed
by operations
management
and the individual involved.
The
inspectors will review the event following receipt of the licensee
.
event report.
j.
Unit 2 Boron In'ection Tank (BIT) Removal
Post
oned
One of the planned licensee modifications for the Unit 2 refueling
outage
was the removal of the boron injection tank BIT.
Shortly
following the
commencement
of the Unit 2 outage,
the licensee
decided not to proceed with the BIT removal.
Just prior to the
outage,
the license
amendment authorizing removal of the BIT had
been
issued
by the
NRC.
At the close of the report period the
licensee
was pursuing
a countermanding
license revision to postpone
the BIT removal.
The decision to postpone
the BIT removal
was primarily due to
questions
raised
by the engineering organization
and
a
guality
Assurance
(gA) audit regarding the adequacy of the design
change.
The identified problem area
concerned
the identification of
additional
components
whose environmental qualifications might not
be adequate
for the slightly harsher
post accident
environments that
would be experienced with the boron injection provided by the BIT.
The inspectors will follow the gA review and subsequent
licensee
actions during routine activities.
5.
Haintenance
62703)
The inspectors
observed portions of, and reviewed records
on, selected
maintenance activities to assure
compliance with approved procedures,
technical specifications,
and appropriate
industry codes
and standards.
Furthermore,
the inspectors verified maintenance activities were
performed
by qualified personnel,
in accordance
with fire protection
and
housekeeping
controls,
and replacement
parts
were appropriately
certified.
a 0
Auxiliar Saltwater
S stem Pi in
Gou ed Durin
Excavation
During a review of modifications to the seawater
intake area the
inspector discovered that on September
21, 1989, during excavation
for power and telecommunication lines,
a buried portion of safety
related auxiliary saltwater piping was struck and gouged
by a
backhoe
bucket.
This event
was documented
in an "action evaluation"
or AE which was
a portion of a general
action request for
installation of the non-safety telephone
and power lines.
The
response
to the problem included
non destructive
examination of the
pipe for wall thickness
and recommendations
by the onsite project
engineering
group
(OPEG) for the recoating
and reburial of the pipe.
However,'ecause
of the "non-safety related" status of the=-original
action request,
root cause
mechanisms
were not put in place to
determine
why the pipe was inadvertently uncovered in the first
place.
Secondly,
neither
management
nor operations
personnel
were
notified to address
operability concerns of the gouged pipe.
10
Administrative Procedure
C-12, "Identification and Resolution of
Prob1ems
and Nonconformances,"
establishes
guidelines for the
initiation of Action Request
(ARs).
Action evaluations
(AEs) are
associated
with individual
ARs and are
used to request
assistance
in
the resolution of the
AR.
However,
AP C-12 does not allow AEs to be
used to document
new problems.
The procedure
requires
a new
AR to
be created
for
a new problem
so that the problem receives
appropriate
review from gC and plant supervision.
Since the
existing non-safety related
AR, for the installation of utilities to
the intake,
was
used to document the safety related
ASW pipe damage,
appropriate
reviews were not performed.
The inspector brought this finding to the attention of the system
engineer,
who was
unaware of the event
and initiated an appropriate
AR.
The inspector also discussed
the event with plant and
gC
management.
A non-conformance
report was subsequently written. It
was determined,
at that time, that based
on the non-destructive
examination
and burial instructions
contained in the AE, the
ASW
piping was operable.
Four issues
were focused
on in nonconformance
report; the
administrative
aspects
as to why a new AR was not generated,
the
technical
aspects
of the
ASW pipe operability, the lack of security
measures
while the piping was exposed,
and the work control aspects
which allowed inadvertent excavation of the
ASW pipe.
The
nonconformance
report review determined that the General
Construction
(GC) excavation permit did not identify the location of
ASW pipe.
Although drawings indicated that the
ASW pipe was five
feet underground,
GC uncovered
the pipe at 18 inches.
With respect to the administrative aspects,
the
NRC maintenance
team
of July 1988 (Inspection
Report 50-275/88-15)
issued
a Notice of
Violation for failure to implement
AP C-12 and initiate an
AR for a
new problem.
Although actions
were taken to clarify AP C-12 and
training was conducted for all required to implement the procedure,
the corrective actions
were apparently
not successful
in this case.
The failure to establish
an appropriate
AR in a timely manner is an
apparent violation (50-275/90-05-01).
The roots of this event appear similar to the Notice of Violation
issued in Inspection
Report 50-275/89-34,
where
GC personnel
erected
scaffolding over the Unit 2 vital batteries without obtaining the
required engineering
review.
These
events
seem to indicate
a lack
of sensitivity toward operating units
on the part of GC personnel.
Additionally plant management
was slow to react to this problem.
The problem was brought to the attention of plant management
on
March 1,
1990 and security issues specifically discussed.
It was
not until March 22 that the security department
was notified to
perform an evaluation for compensatory
measures.
The licensee
should address
in their response
to the Notice of
Violation; the issues
of ASW security
and operability while the line
was excavated,
the adequacy of work control, the adequacy of repairs
11
performed,
actions to increase
the sensitivity of construction
personnel
and any improvements
planned in timely response
to
identified problems.
Check Valve Ins ection
The inspectors
examined
and were satisfied with the licensee
actions
pursuant to the discovery of minor check valve internal
interferences
(rubbing).
During planned inspection of check valves
in Unit 2 during the refueling outage
the licensee
examined valve
SI-2-88188 which was
>n the emergency
core cooling
system.
The valve and other similar Velan check valves
had their
internals
replaced in the last refueling outage
due to a disk
rotation and cocking problem.
During the current outage the
licensee
sampled
one valve for freedom'of motion and noted slight
rubbing of the end of the hinge
arm against the valve body.
The
rubbing resulted in a burnished
area estimated
to be several
mi ls
deep.
Check valve movement
was not significantly hampered
according
to engineering
personnel.
Three other similar valves were then
disassembled
and
no additional
rubbing was found.
The licensee
planned to increase
the existing chamfer
on the hinge
arm ends to eliminate the interference
in accordance
with vendor
instructions.
This problem is not considered
to be
a generic issue
because
of the minor amount of rubbing.
Significant rubbing would
have
been observed at original assembly.
Poor Cleanliness
Controls for Tem orar
S stems
On March 8,
1990 the licensee
experienced difficulty and delay in
attempting to drain
down the reactor vessel
for head
removal.
The
temporary system,
the reactor vessel
refueling level indicating
system,
RYRLIS was discovered to have
a blocked line which precluded
venting the reactor vessel
head freely.
Subsequent
disassembly
showed that
a tape cleanliness
barrier was
left installed
on a subassembly.
The cleanliness
barrier (tape)
was
not removed
when the subassembly
was installed in the system
and
became
a blockage.
The licensee
documented
the problem
on a quality evaluation to
ensure
a root cause
is determined.
There were
no safety
implications directly applicable
from this event.
The licensee
is
very interested
in successfully preventing recurrences
due to the
cost of schedule
delays.
Modification Work Observed
The inspector
observed portions of the Unit 2 modification work in
progress
on the following modifications:
installation of digital feedwater control system
installation of a revised seismic trip
12
modification to,the
AMSAC (accident mitigation system actuation
'ircuitry)
system annunciation
replacement
of the plant process
computer
P-250
Gammametrics
cable replacement
due to a 10 CFR Part 21 report
Rosemount pressure
transmitter replacement
due to'an
NRC
bulletin
The inspector also observed solid state protection system work on
suspect electrical
connections
which had to be checked for tightness
in accordance
with a vendor technical bulletin (Westinghouse
technical bulletin 89-06).
One violation and
no deviations
were identified.
6.
Sur vei 1 lance
(61726)
By direct observation
and record review of selected
surveillance testing,
the inspectors
assured
compliance'with
TS requirements
and plant
procedures.
The inspectors verified that test equipment
was ca'librated,
and acceptance
criteria were met or appropriately dispositioned.
a.
Dail
Heat Balance
The inspector
reviewed the performance of a daily heat balance
on
Unit 2 prior to the refueling outage.
The heat balance
was
performed in accordance
with surveillance test procedure
R-2B
without the use of the plant process
computer which had been taken
'ut of service for replacement.
The inspector.
reviewed the data
and the procedure
and found the
licensee's
actions acceptable.
No violations or deviations
were identified.
7.
Licensee
Event
Re ort Follow-u
92700
a.
Status of LERs
The
LERs identified below were closed out after review and follow-up
inspections
were performed
by the inspectors
to verify licensee
, corrective actions:
Unit 1:-'8-29 (Revision 1), 88-30 (Revision 1), 88-18, 88-34,
89-07, 89-08, 89-09, 89-10, 89-11,
89-17
Unit 2:
88-16 (Revision 1), 89-06, 89-08, 89-09,
89-11
No violations or deviations
were identified.
13
8.
0 en Item Follow-u
(92703
92702)
a.
(Closed) Unit 1 Enforcement
Items 50/275/89-23-01'2
and
03
The inspector
reviewed the licensee's
January
2, 1990,
response
to
three violations contained in Inspection
Report 50-275/89-23
(dated
December
1, 1990).
The cause
and corrective actions described
for
the violations concerninq the application of the equality Assurance
(gA) program to boric acsd heat tracing (50-275/89-23-03)
and the
control of the hydrogen
purge containment isolation valves
(50-275/89-23-02)
were found to be acceptable.
The items are
considered
closed.
With respect
to the overtime violation, the inspector
reviewed the
January
2, 1990, letter,
LER 50-275/89-17,
and
a February 21,
1990,
supplemental
response
provided in response
to an
NRC information
-request.
The February 21, 1990,
response clarified the root cause
to include a."...programmatic
breakdown
and
a lack of procedural
guidance
including plant management
oversite."
The letter also
discussed
in greater detail the scope of overtime violations and to
whom the licensee will apply the overtime restrictions
in the
future.
Additionally, the licensee
committed to have equality
Control monitor the effectiveness
of corrective action
implementation during the Unit 2 refueling outage.
The inspector
found these
actions
acceptable
(Enforcement
Item 50-275/89-23-01,
.
and Licensee
Event Report 50-275/89-17,
closed).
10.
Exit
30703
On March 23,
1990,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspectors
summarized
the
scope
and findings of the inspection
as described
in this report.