ML16341E652
| ML16341E652 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 05/05/1988 |
| From: | Johnston K, Mendonca M, Narbut P, Padovan L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341E651 | List: |
| References | |
| 50-275-88-07, 50-275-88-7, 50-323-88-07, 50-323-88-7, NUDOCS 8805230102 | |
| Download: ML16341E652 (36) | |
See also: IR 05000275/1988007
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report
Nos.
50-275/88-07
and 50-323/88-07
Docket Nos.
50-275
and 50-323
License
Nos.
and
Licensee:
Pacific
Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
Cali fornia
94106
Facility Name:
Diablo Canyon Units 1 and
2
Inspection at:
Diablo Canyon Site,
San Luis,Obispo County, California
Inspection
Conducted:
Inspectors:
L.
M. Padovan,
Resident
Inspector
K.
E. Johnston,
Resident
Inspector
P.
P. Narbut, Senior Resident
Inspec or
Approved by:
M.
M. Mendonca,
Chief, Reactor Projects
Section
1
Date Signed
WQ~r EI
Date Signed
Date Signed
~A'"ls s-
Date Signed
~Summer:
Ins ection from March 6 throu
h
A ril 9
1988
Re ort Nos.
50-275/88-07
and
50-323/88-07
Areas Ins ected:
The inspection
included routine inspections of plant
operations,
maintenance
and surveillance activities, follow-up of on-site
events,
open items,
and licensee
event reports
(LERs),
as well as selected
independent
inspection activities.
Inspection
Procedures
30703,
37700,
60710,
61726,
62703,
71707,
71709,
71710,
71881,
73753,
92700,
92701,
93702,
and
94703 were applied during this inspection.
Results of Ins ection:
Three violations were identified.
SS05230i02
SS0505
ADOCK 05000275
9
DETAILS
Persons
Contacted
"J.
D. Townsend,
Plant Manager
"J.
A. Sexton, Assistant Plant Manager,
Plant Superintendent
"J.
M. Gisclon, Acting Assistant Plant Manager,
Support Services
"W.
B. McLane, Acting Assistant Plant Manager,
Technical
Services
C.
L. Eldridge, equality Control Manager
"S.
G. Banton,
Engineering
Manager
- M. E.
Leppke,
Onsite Project Engineer
"K.
C.
Doss, On-site Safety
Review Group
"T. A. Bennett, Assistant
Maintenance
Manager
"0.
A. Taggart, Director, guality Support
M. J.
Angus,
Work Planning
Manager
W.
G. Crockett,
Instrumentation
and Control Maintenance
Manager
"J.
V. Boots,
Chemistry and Radiation Protection
Manager
L.
F.
Womack, Operations
Manager
"T ~
L. Grebel,
Regulatory
Compliance Supervisor
"S.
R. Fridley, Senior Operations
Supervisor
G.
M. Burgess,
Senior
Power Production Engineer
The inspectors
interviewed other licensee
employees
including shift
foreman
(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 April 8, 1988.
0 erational
Status of Diablo Can
on Units 1 and
2
Plant Status
Unit 1 shutdown for its second refueling outage
on March 6,
1988.
The
refueling outage
has proceeded
throughout the reporting period and
included
some problems
such
as
an excessive
pressurizer
cooldown,
overpressurization
of the
RCDT, discovery of a
CROM weld leak,
and hot
particle discoveries
discussed
later in this report.
During this report
period the licensee
performed
a forced oxygenation of the
RCS,
successfully
drained to midloop and installed
SG nozzle
dams,
completed
core offloading, and commenced
s'team generator
eddy cur rent inspection
and tube heat treatment.
Unit 2 restarted
on March 6, 1988 (after a March 3,
1988 reactor trip
discussed
in report 50-323/88-04).
Power operations
continued through
the reporting period except for planned periodic reductions
for turbine
valve testing.
During the report period
NRC activities included inspections
and
examinations
by
NRC specialists
in fire protection, radiological
controls, security,
and
a seismic review team.
Results of those
inspections
and examinations will be reported separately.
3.
0 erational
Safet
Verification
71707
and 71710
~
~
a.
General
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)
Radiation protection controls.
(d)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved procedures.
(e)
Interiors of electrical
and control panels.
(f)
Implementation of selected
portions of the licensee's
physical
security plan.
(g)
Plant housekeeping
and cleanliness.
(h)
Essential
safety feature
equipment alignment
and conditions.
(i)
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.
No violations or deviations
were identified.
4.
Onsite
Event Follow-u
93702
'a 0
Ver
Hi
h Radiation Barrier Doors Unlocked
On March 9,
and on April 1, 1988, the licensee
discovered
very high
radiation barrier doors unlocked.
Technical Specification 6. 12.2
requires that areas
accessible
to personnel
with radiation levels
greater
than
1000 mR/h be provided with locked doors
and that those
doors
remain locked except during periods of approved
access.
Exposure histories of personnel
in the area
were checked
and
no
unusual
exposures
were found.
As corrective action,
the licensee
has initiated independent verification of very high radiation
barrier locking following entry and exit.
The resident inspector
notified regional specialists
for followup.
This issue will be
addressed
in a separate
inspection report.
Unit 1 Pressurizer
Cooldown
On March 10,
1988,
the Unit 1 pressurizer
was inadvertently cooled
down at a rate exceeding
Technical Specification 3.4.9.2
maximum
cooldown of 200
F in any one hour period.
The event occurred
when
the licensee
injected the 20,000
ppm boron Boron Injection Tank
(BIT) inventory.
The root cause for the cooldown was determined to
be that Operations
Procedure
L-5, "Plant Cooldown from Minimum Load
to Cold Shutdown" did not restrict the injection flow rate.
Without
the flow rate restriction,
the pressurizer
heaters
were not able to
maintain
a cooldown of less
than
200
F with the temperature
difference
between
the
RCS and pressurizer
greater
than
200
F.
As corrective actions,
in addition to revising
OP L-5 and reviewing
other operating procedures
and surveillance tests for similar
concerns,
the licensee
requested
to perform an
evaluation of the above event to demonstrate
pressurizer operability
as required
by TS 3.4.9.2, prior to entry into Mode 4 (Hot
Shutdown).
Preliminary information indicates that there is adequate
mar gin.
An action plan was established
for this event which appeared
to the
inspector
to be comprehensive.
This event
was determined
not to be
reportable
under
10 CFR 50.73 since the licensee
remained inside the
action statement
associated
with TS 3.4. 9. 2.
Initiation of Auxiliar
S ra
on Unit 1
On March 10,
1988, the licensee initiated Unit 1 Auxiliary Spray,
with a differential of less
than 320~F, to terminate
a pressure
transient initiated during cold shutdown
when Reactor Coolant
Pump
(RCP) 1-2 was secured
due to vibration.
The vibration was not
unexpected
since the
RCP's are "tuned" for normal operating
temperature
conditions.
Operators
shut
down
RCP 1-2 on the
recommendation
of the
RCP vibration engineer
although
OP L-5
recommends
that
RCP 1-2 be left in operation to accommodate
spray
f1 ow.
Normal spray
can
be initiated off loops
1 and
2 although the loop
2
spray valve was manually isolated
due to excessive
body to bonnet
leakage.
Spray was being provided from loop 1.
However,
when
1-2 was secured,
flow through the loop reversed
as designed.
Since
the pressurizer
is between
the Steam Generator
and the Reactor
Vessel
on loop two, pressure
at the surge line increased with
reversed
flow.
This made
normal spray ineffective for controlling
0
the pressure
and auxiliary spray from the charging
pumps
was
used.
Following the transient,
the Shift Foreman
determined that the
differential temperature
between
the spray nozzle
and the
pressurizer
vapor space
was approximately 290'F and definitely less
than 320~F.
TS Table 5.7-1 requires that
a differential temperature
of greater
than 320'F
be logged
as
one of twelve allowable auxiliary
spray actuation cycles.
As corrective actions,
the senior
operations
supervisor
committed to
enhance
OP L-5 to clarify the purpose of leaving
RCP 1-2 in service.
In addition,
an incident summary will be written to address
the
event.
The inspector
noted that event
and proposed corrective
actions
were not being formally tracked
on the licensee's
Action
Request
system
one month following the event.
Although this event
did not result in an auxiliary spray (thermal) actuation cycle, the
corrective actions
needed to prevent
a possible actuation cycle
warrents
formal actions.
These findings were discussed
with the
licensee.
Over ressurization
of the Unit 1 Reactor Coolant Drain Tank
On March 11,
1988, with Unit 1 in mode
5 during the second
week of
the refueling outage,
operations
personnel
were draining down the
safety injection accumulators
in preparation
for maintenance
activities
on accumulator valves.
Normally, during shutdown the
are depressurized
and the accumulator contents
are
drained through the reactor coolant drain tank
(RCDT) to the liquid
hold up tanks
(LHUTs) in accordance
with plant operating procedure
(OP) B-3B: III.
In lieu of this prescribed
evolution, since
personnel
were working inside containment,
the decision
was
made to
not vent the accumulator nitrogen to containment,
and to drain the
in a pressurized
condition.
Since the
RCDT vent line
was cleared for containment
leak rate testing,
RCDT level indication
was rendered
inaccurate.
During draining, the
RCDT was pressurized
to its relief valve setpoint,
the relief valve failed open,
and
about
140 gallons of water discharged
to the reactor cavity sump
before the evolution was suspended.
A more detailed
evaluation
follows.
As previously mentioned,
drain
down during shutdown is
normally accomplished
in accordance
with OP B-3B: III "Accumulators-
Shutdown
and Clearing."
Clearance
Number
10411 was issued for this
activity, but the
OP was not referenced
on the clearance.
However,
the clearance
did require accumulator venting and draining.
Operations
personnel
decided it would not be
a good idea to vent the
accumulator pressurization
nitrogen into containment
since personnel
were working in the area
near the accumulators.
Since the
RCDT was
normally used at power to lower level in a pressurized
a decision
was
made, without shift foreman involvement, to "drain"
the accumulators
under pressure.
An operator at the auxiliary
control board verified the
RCDT was available
and properly aligned
to a
LHUT.
All r emote operated
control valves were observed to be
5
'orrectly
positioned,
and
some water from the
RCDT was
pumped to a
LHUT to verify correct system alignment.
draindown
was initiated,
and
a
RCDT pump was started.
RCDT level appeared
constant,
so
a second
draindown
began.
The auxiliary operator
then noticed that
RCDT level
was
rising rapidly and started
a second
RCDT pump.
At that time, it was
noted that reactor cavity sump level
was increasing
and the
accumulator drain operation
was
suspended.
Shortly afterward,
the
shift foreman directed the draindown to continue in accordance
with
the
OP.
After depressur izing the accumulators,
draindown
was
re-initiated
and reactor cavity sump level
began to again increase,
requiring another
draindown termination.
Subsequent
investigation determined
the
RCDT relief valve had failed
open during the initial accumulator drain attempt.
Additionally,
the
had been manually isolated for containment
leak
rate testing.
This resulted in an accurate
level indication on the
RCDT, such that level never appeared
greater
than
75K.
The
clearance
for the leak rate testing did not affect remote operated
valves, therefore clearance
tags indicating the unavailability of
the
RCDT vent line were not provided
on the auxiliary control board.
The licensee's
evaluation
determined
operators
failed to follow the
established
draindown procedure,
and that tagging or
other indications
on the auxiliary control board were not specified
or provided when the
RCDT vent path was cleared.
At a minimum, the
RCDT pumps should
have
been tagged,
indicating the vent path was
cleared.
Corrective actions
are under evaluation
by the licensee.
Failure to drain the accumulators
in accordance
with the established
operating procedure
is an apparent violation.
(Enforcement
Item
50-275/88-07-01).
Leak on Unit 1 Control
Rod Drive Mechanism
CROM
On March 12, 1988, during
CRDM ventilation removal the licensee
discovered
a boric acid crystal formation on a spare
CROM
The size of the crystal formation was visually
estimated
to be 1 inch wide and five inches
long and appeared
to be
coming from the area of a canopy seal
weld.
The licensee
was aware
of the similar leaks described
in Information Notice 86-108 and its
supplements
and
had planned
a detailed inspection after reactor
vessel
head
removal during the refueling.
This discovery preceded
that action,
however.
On March 16 the licensee
performed additional inspections with
television
cameras
and identified what might be an additional
leak.
The licensee
also
made entry in Unit 2 and performed
swipe surveys
of exhaust ventilation from the
Based
on comparison of the
swipe surveys
from Unit 1 and the post refueling outage
surveys of
Unit 2, the licensee
concluded that
no measurable
leakage
had
started
on Unit 2.
0
The licensee
developed
an action plan in response
to the situation.
The action plan included contacting other sites
and the
supplier (Westinghouse),
investigating
enhanced
leak detection
systems for future use,
and identification of the cause,
and
evaluation of fixes.
Design
Change
Package
(DCP) Number M-39666 was issued
by the
licensee
to cut and
remove
CROM L-5 and J-5
head adapters
(containing the leaking canopy welds)
and butt weld pipe caps
on the
cut head penetrations.
Action Request
A0104552
was issued to
implement the
DCP,
and work was to be accomplished
in accordance
with work order
(WO) C0030719
and Westinghouse
procedure
¹SP 2.7. 1
PGE-1
Modification at Diablo Canyon."
SP 2.7. 1
PGE-1 was ver ified to contain
a sign-off space for the Authorized
Nuclear Inspector
(ANI) after verification of satisfactory
work
completion.
The inspector
observed that work was being performed in
accordance
with these
documents,
except that activity 2 of the
contained
a gC hold point which had not been
signed off on the
even though work had progressed
beyond that point.
The hold point
required
gC verification of procedural
compliance with special
procedure
SP 2. 7. 1 PGE-l."
In discussing this oversight with the guality Control Manager,
the
inspector ascertained
that quality control personnel
were verifying
work was being performed in accordance
with the
SP 2.7. 1 PGE-l,
as
gC signoffs were being provided
on the special
procedure.
Accordingly, the unsigned
gC hold point on the
WO was
determined to be redundant
and did not adversely affect the work.
In order .to observe
work activities from a location above the
reactor
head,
the inspectors
entered
a temporary access
platform
installed
on the cable tray area
above the reactor
head.
This area
above the reactor
head
was designated
a Zone
3 "Housekeeping,
Tool
Control/Foreign Material Exclusion" area in accordance
with
Administrative Procedure
(AP) C-10S2 "Housekeeping - General."
C-10S2 specified that for a Zone
3 area, tools, support equipment
and detached
material
inside the zone must be logged in and out.
The
inspector
observed
loose materials within the zone
(such
as
a pocket
knife, razor blade type cutting tool, open allen wrench set,
masking
tape,
and
an air sample
pump) were not entered
on the log provided
at the area.
Each of these
items could have
been accidentally
dislodged
from the Zone
3 tool control area into the refueling
cavity.
This is an apparent violation of AP C-10S2 (Enforcement
Item 50-275/88-07-02).
The inspectors
are following the licensee's
corrective actions.
Subsequent
to the repair of the
CROM L-5 and J-5
head adapters,
the
licensee
made similar repairs to other spare
head adapters
on
L-11 and L-9.
Revisions to the
DCP and
WO were
made to control
these repairs.
Sto
Work on Use of Vendor Technical
Manuals
On March 14,
1988
gC personnel
put a stop work in effect precluding
use of vendor technical
manuals
which had not been verified as
up-to-date.
The stop work was
a result of gC followup of long
standing
commitments to insure the vendor technical
manuals
were
up-to-date.
Cracked
Weld on Diesel Generator
2-2 Lube Oil Filter Su
ort
On March 18,
1988
a maintenance
engineer
discovered
a cracked weld
on one of the three Unit 2 Diesel Generator
filter support feet.
At the time of the discovery,
0/G 1-3, the
swing 0/G,
was out of service for maintenance.
The Plant Safety
Review Committee
(PSRC) determined
based
on the professional
opinion
of the Onsite Project Engineer that
D/G 2-2 would remain operable
during a seismic event.
Subsequently,
the licensee's
corporate
engineering
confirmed the initial determination
by analysis.
As immediate corrective action the licensee
performed
a design
change
by welding a bracket to the existing foot.
In addition
a
visual inspection of the other
D/G lube oil filters was performed.
The licensee
determined
the cause of to be vibration at the lube oil
filter resulting in fatigue failure.
The licensee
is analyzing the
vibration for further corrective actions.
Securit
Event
On March 18,
1988
a reportable security event report was
made.
The
residents
notified regional specialists
for followup.
Hot Particle Identified as Unit 1 Fuel Particle
On March 23,
1988
a hot particle was found on a worker exiting the
Radiological Control Area.
Ho overexposure
was involved per the
licensee's
estimates.
The licensee
temporarily
suspended
work in
the area the particle was suspected
of originating from (the steam
generator
manways).
The licensee
performed surveys
and implemented
additional controls.
Analysis of the particle indicated it to be
a
fragment of Unit 1 fuel.
Regional Specialists
were notified for
followup as necessary.
Diesel Generator
2-2 Fuel Oil Da
Tank Overflow
On March 22,
1988
D/G 2-2 fuel Oil Day Tank overflowed spilling
. approximately
50 gallons of fuel oil onto the pavement outside the
0/G rooms.
The spill was stopped rapidly and the oil was contained
and quickly cleaned
up precluding
a reportable violation of the
Waste Discharge
Permit or a fire.
Earlier, the chemistry department
had requested
that Diesel
Fuel Oil
Storage
Tank Ol be placed
on recirculation.
An Auxiliary Operator
was instructed to place the tank in recirculation in accordance
with
the appropriate
procedure.
The procedure
required
him to "check in
Auto and Closed" all day tank level control valves in order to
isolate the day tanks
from the storage
tank during recirculation.
Since the valves
have
no position indication near their control
switches,
the procedure
implies that the operator verify that the
controller is in automatic
and by visual observation of the valve
which is under floor panels to determine if it is closed.
The
misinterpreted
the statement
and in most cases
to the controllers
from "auto" to "closed" (the controllers
have
a spring return to
"auto").
In the case of 0/G 2-2 he inadvertently took the
controller to "open" without immediately realizing his mistake.
When the
AO turned
on the transfer
pump to initiate recirculation
the day tank for 0/G 2-2 filled and overflowed and cause
a spill.
The operations
department,
as
a result of the spill, issued
an
incident
summary which concluded
by stressing
the maintenance
of the
highest attentions
to operating duties.
In addition the licensee
plans to re-label
the level control valves
and will consider
a
design
change to add position indication at the controllers.
The
inspector finds the licensee's
actions acceptable.
Unit 2 Vital Batter
Seismic Restraint Bracin
Missin
On April 1, 1988, the onsite vital electrical
systems
system
engineer,
during a review of system action requests,
discovered that
a battery surveillance
performed in 1987 found a number of seismic
restraint
braces
and bolts missing from the Unit 2 batteries
2-2 and
2-3.
At 4:30 p.m., the engineer
brought this to the attention of
his management
who recognized
the battery operability implications.
The licensee
took two immediate actions.
First, the Onsite Project
Engineering
Group
(OPEG)
was requested
to take
as built data to
facilitate a seismic evaluation.
Second, efforts were initiated to
procure bracing
and bolts from a Unit 1 battery not required to be
(Unit 1 was defueled at the time).
By 6:30 p.m.,
OPEG
had
made
a preliminary determination,
without
having completed calculations,
that the batteries
would survive
a
seismic event.
Early in the morning of April 2, the parts
had been
procured
from Unit 1.
The batteries
were never
determined to be
Had this determination
been
made,
entry into Technical Specification 3.0.3 would have
been required.
The inspector
found
the licensee's
immediate actions to be prudent
and timely.
On April 4 the engineering analysis
determined that the as-found
condition would have
been seismically acceptable.
A subsequent
analysis
performed determined that the Unit 1 battery
used to supply
parts
was also acceptable.
On April 4, the licensee initiated a Non Conformance
Report
(NCR).
The
NCR intends to address
how the braces
and bolts were
removed
and
why when they were identified to be missing were the seismic design
implications not considered.
The licensee
was in the process
of this investigation at the time of
this report.
The inspectors will follow the licensee's
NCR process
to confirm that the above questions
are acceptably
addressed.
Two violations and
no deviations
were identified.
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.
Diesel Generator
1-3 Fuel In ection Tell-Tale
On March 20,
1988 while performing return to service testing of
Diesel
Generator
1-3,
a maintenance
engineer
observed
fuel "misting"
from the fuel injector tell-tale port on the number
5R cylinder
head.
The engineer
determined
and documented
on an action request
that the misting condition did not represent
a fire hazard
and that
an earlier engine analysis
had proven acceptable
engine performance.
On March 21,
1988 the
D/G 1-3 was
removed
from service to trouble
shoot the tell-tale indication.
Cylinder head
5R had been replaced
during the previous
D/G outage
due to a leaking jacket water to fuel
injector sleeve fitting.
The work order to trouble shoot the fuel
oil leakage
required the removal of the cylinder head cover and
disassembly
of the fuel injector.
A maintenance
mechanic
discovered that the original fuel injection
rod was not sealing completely against
the
new cylinder head.
With
the concurrence
of gC and mechanical
engineering
the work order
was
revised to include
a step to lap the fuel injection rod seat of the
cylinder head.
The inspector
observed
the performance
of this
activity.
The 0/G was returned to service
on March 23,
1988 following testing
in which no evidence of tell-tale "misting" was observed.
b.
Unit 1 Containment
Personnel
Hatch
On March 26, 1988, the inspector
observed portions of a preventive
maintenance activity performed
on the containment
personnel
hatch.
It was performed to return the door to service prior to lifting the
reactor vessel
head.
During the performance
of this activity it was
discovered that an interlock lever was not falling into a slot on a
disc which rotates with the inner door when the handwheel
on the
inner door is taken to the closed position.
The inter lock provides
mechanical verification that the inner door is closed
and allows the
outer door to be opened.
The disc
had
somehow rotated out of
position and the slot. would not line up to the lever.
A maintenance
mechanic,
in frustration took a pipe, approximately
three feet long, staged to be used for scaffolding,
and hit the disc
in order to rotate it back into position.
This was
done in the
10
presence
of his foreman
and
a number of other mechanics,
radiation
protection
(RP) technician,
in-service inspection (ISI) technicians,
and guality Control
(gC) inspectors.
To have adjusted
the disc
correctly, the mechanic
should
have
loosened
the set screw holding
it in place,
rotated the disc,
and retightened
the set screw.
The inspector discussed
the mechanics activitieswith both the
mechanic
and his foreman.
Both the foreman
and the mechanic stated
that the
use of the pipe was not correct.
They expressed
that
mitigating circumstances
existed in that the personnel
hatch
had
become
a critical path maintenance
item, tools were not readily
available (they were in containment in an SCA), and that
a
differential pressure
existed across
the outer door which created
a
potential
hazard if it was opened.
In addition, the mechanic
was
very familiar with the personnel
hatch
and determined that his
actions
would not harm the door.
In review of these
circumstances
the inspector
determined that the
adjustment
could have
been
done correctly.
Furthermore,
the use of
excessive
force on the door displayed poor practices.
As follow-up, the inspector discussed
these
events with the
maintenance
manager,
the
gC manager,
and the Unit 1 outage
manager.
Based
on these
discussions
and independent
actions initiated by
mechanical
maintenance
and gC, the following actions
were taken:
The individual was counseled.
Maintenance
held a tailboard to discuss
the event
and proper
maintenance
practices.
An incident summary
was issued to maintenance.
gC inspectors
discussed
the importance of responding to events
such
as this.
The door was inspected
and
no damage
was identified.
Although immediate corrective actions
appeared
to be limited, the
licensee's
follow-up was acceptable.
c.
Other Maintenance Activities
Other maintenance activities were observed
during the course of
event follow-up, the control rod drive mechanism
seal
weld repair
(see Section 4.e),
and inspection of'nstrumentation
and Controls
activities (see Section 12).
No violations or deviations
were identified.
6.
Surveillance
61726
By direct observation
and record review of selected
surveillance testing,
the inspectors
assured
compliance with TS requirements
and plant
0
11
procedures.
The inspectors verified that test equipment
was calibrated,
and acceptance
criteria were met or appropriately dispositioned.
Unit 1 Auxiliar Salt Water
Pum
1-1 Inservice Testin
The inspector
observed portions of the Auxiliary Salt Mater System
(ASW)
Pump l-l Inservice Testing (IST) performed prior to the return
to service of the
pump following motor maintenance.
In followup of
this surveillance,
the inspector
reviewed the system design
bases
and compared
them to operational
practices.
At the
end of the
inspection period the inspector
had posed
two questions
to the
licensee
concerning the effects of allowable biofouling in the
ASW
side of the Component Cooling Water
(CCW) Heat Exchanger
on the heat
removal capacity of the heat exchanger.
Inservice Test
The test,
to comply with the requirements
of ASME Section XI, has
the operators
establish
greater
than 11,000
gpm
ASW flow and then
confirm that the differential across
the
ASW pump is within minimum
and
maximum valves.
The
ASW flow measurement
was
made using
a
temporary annubar inserted
in the flow upstream of the heat
exchanger.
It was discovered,
when flow measurements
were
substantially
less
than 11,000
gpm, that the annubar
had failed.
A
circumferential
weld joining the extension
rod to the flow element
had failed apparently
due to flow induced vibration.
The licensee
determined
the annubar to be
a temporary instrument
and
made
an on
the spot change to Surveillance Test Procedure
(STP)
P-7B to have
the instrument
removed following testing.
In addition,
an effort
was initiated to install
a mounting bracket to store the annubar
following testing.
Following replacement
of the annubar,
the test
was again attempted
and 11,000
gpm was not achieved.
The heat exchanger
was cleaned
and
rated flow was achieved,
however differential pressure
across
the
pump remained at the alert level.
As a result,
the engineering
department
made the decision to disassemble
and rebuild the
pump.
Desi
n Basis
uestions
The inspector
reviewed the design basis for the
ASW system.
Diablo
Canyon
FSAR Chapter 9.2 states that the system is designed for the
post-design
basis
loss of coolant accident
(LOCA) instantaneous
heat
rejection
assuming
the loss of one diesel
generator.
The postulated
peak heat rejection rate is 2.52 x 10 8 Btu/hr.
Witn an ocean
temperature
of 70 degrees
F. this would have required 10,580
gpm
through
one heat exchanger.
The inspector
asked
two questions:
1.
If the
pump test
STP-P7B
was performed
on with clean heat
exchanger
and
ASW flow of exactly 11,000
gpm was established
what would be the flow achieved with the delta pressure
across
the heat exchanger at its alarm setpoint of 167 inches of
water?
12
2.
The design basis
heat
load is 2.52 x 10 8 Btu/hr and the vendor
heat exchanger
specifications
indicate
a heat
exchange
rate of
2.588 x 10 8 Btu/hr,
a margin of less
than
3X.
What amount of
fouling was
assumed
in the heat exchanger
design?
This is an
Open Item (follow-up Item 50-275/88-07-03).
The licensee
committed to respond to the inspectors
questions
during
a telephone
conference
call
on April 13,
1988.
b.
Other Surveillance Activities
Other surveillance activities were observed
by the inspectors
as
a
part of inspection of inservice inspection activities (see Section
13) and inspection of Instrumentation
and Controls activities (see
Section 12).
No violations or deviations
were identified.
7.
En ineerin
Safet
Feature Verification
71710
a.
Unit 2 Hi
h Head In ection
S stem Walkdown
The inspector performed
a walkdown of the physically accessible
portions of the Unit 2 High Head Injection System including
electrical
breakers
and control
room indication.
No violations or deviations
were identified.
8.
Radiolo ical Protection
71709
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 generally
aware of significant plant
activities, particularly those related to radiological conditions and/or
challenges.
ALARA consideration
was found to be an integral part of each
Radiation
Work Permit.
No violations or deviations
were identified.
9.
Ph sical Securit
71881
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.
10.
Licensee
Event
Re or t Follow-u
92700
and 92701
4
13
Status of LERs
Based
on an in-office review, the following LERs were closed out by
the resident inspector:
Unit 1:
88-07
Unit 2:
88-01, 88-02
The
LERs were reviewed for event description,
root cause,
corrective
actions taken,
generic applicability and timeliness of reporting.
No violations or deviations
were identified.
11.
Inde endent
Ins ection
37700
60710
and 92700
a.
Reactor
Vessel
Refuelin
Level Indicatin
S stem
RVRLIS
In preparation for the licensee's
planned drain to midloop condition
for the Unit 1 refueling outage the inspector
examined
and walked
down the installation of the
RVRLIS system for Unit l.
Subsequent
to the Unit 2 loss of RHR event
on April 10,
1987 the
licensee
had implemented
many improvements
in the control of mid
loop operation.
One of the improvements
was the installation by
design
change of a dedicated
temporary
system for measuring reactor
vessel
level during the drain
down to and at midloop conditions.
The licensee's
system consists of permanently installed equipment;
narrow range;, wide range
and tygon tube level indicating systems
connected
to independent
location in the reactor hot and cold legs.
The system
includes
readouts
and alarms in the control
room,
a
television monitor (of the tygon tube scale)
in the control
room and
level recorder traces.
Prior to the inspectors
walkdown, involved licensee
engineer
technicians
and management
had performed exhaustive
walkdowns to
ensure
an adequate
system.
b.
Insufficientl
Detailed
Se uencin
of Mork for Drain Down to
Midloo
Conditions
In reviewing the licensee's
commitments
made in response
to the
April 10,
1987 loss of
RHR event
and the licensee's
response
to
Generic Letter 87-12 dealing with operations
at midloop, the
inspector
determined that the licensee
did not have plans to
carefully control the sequence
manway removal
and
nozzle
dam installation.
Likewise the inspector
determined
the licensee
had not sequenced
reactor vessel
head work
to insure
a sufficient vent path
was available prior to installing
the last hot leg nozzle
dam.
The possible
consequences
of improper sequencing
could be the
sudden
expulsion of the already
reduced
RCS inventory (at mid loop
14
operation)
through
cold leg nozzle.
This could
occur with the loss of the
RHR system for any appreciable
length of
time.
This situation
was brought to the attention of licensee
management
and the licensee
revised the sequence
of operations
appropriately.
Im ro er Desi
n Calculation
To provide sufficient venting area in the reactor vessel
head,
the
licensee
performed calculations
to demonstrate
sufficient vent area
would be available
from the process
of opening the incore
thermocouple ports (mechanical
"connoseal"
connections)
and from
detensioning
the head.
The licensee's
calculation, File 880311-0,
dated
March 11,
1988
showed that removal of the connoseal
head connections
would provide
2.5 square
inches of vent area for each of five connections
or 10.5
square
i'nches total.
The inspector
examined the connoseal
removal job in progress,
measured
the actual
gaps
between the thermocouple stalk and the head
and found the actual
values to be quite different than
those
used in the calculation.
The actual outer diameter
as measured
by the mechanics
at the
inspectors
request
was 2-5/8 inches
(2.625) whereas
the calculation
was based
on an erroneous
value of 2.09 inches.
The net result of
the error was that the
head vent area available
from the connoseal
work was 2.6 square
inches total vice the calculated
10.5 sq. in..
The design calculation, File 880311-0
had
been prepared
by one
engineer verified by another
and approved
a Senior
Nuclear
Generation
Engineer.
Subsequent
to the discovery of the error the licensee
revised the
sequence
of work to perform reactor vessel
stud removal prior to
installing the last hot leg nozzle
dam thus precluding the rapid
ejection of RCS inventory (if RHR cooling were lost).
The calculational error was caused
by the engineering
acceptance'of
informal information over the telephone for the critical dimensions
of the items involved in the calculation.
The dimensions
informally
provided were incorrect but neither the engineer performing the
calculation,
the verifier or the approver proper ly verified the
important input dimensions.
Pacific Gas
and Electric Company,
Engineering,
Nuclear,
Procedure
No.
3. 3 Revision
No.
9 dated 4/13/87,
"Design Calculations"
establishes
how Engineer ing will prepare,
check,
approve
and
document design calculations.
Paragraph
4. 1.2 states
in part
that..."All,design input data...shall
be documented
in the
calculation"
and "assumptions
requiring verification at a later
15
design
stage shall
be identified as 'Preliminary'ntil the
verification is completed...."
Paragraph
4.2 "Checking" states
in part "Checking of the
calculations
shall include...reviewing calculation inputs to verify
conformance with project conditions."
The fai lure to verify the dimensional
inputs received
over the
telephone
as preliminary assumptions
on the part of the preparer
checker
and approval
led to an erroneous
calculation which is an
apparent violation of 10 CFR 50 Appendix
B Criterion III Design
Control (Item 50-275/88-07-04).
Im ro er Cleanliness
Controls
During the observation of the connoseal
removal work on 3/21/88 the
inspector
observed that the opening to the reactor vessel
created
by
the work was left open at the completion of work.
Since the work left a 1/8 inch annular opening to the reactor
and
since cleanliness
had not been established
in the areas
above the
opening (i.e. the
head area cables,
the area
around the refueling
cavity or on the polar crane)
the inspector
was concerned for the
cleanliness
of the reactor since at a different reactor site
a 1/8
inch piece of foreign material
had caused
a stuck control rod.
The inspector identified his concern to the mechanics
and the
gC
inspector in attendance
in the refueling cavity.
On exiting the
cavity the inspector
informed the mechanic
foreman
and the outage
manager of his concern.
They stated
they agreed with the inspectors
concern
and would have the
head
openings protected.
The following day 3/22/88 the inspector
determined that the opening
had not been covered
and informed the plant manager
who agreed that
head openings
should
be covered
anti determined that
a nonconformance
report would be written to document the problem.
The next day 3/23/88 the inspector
determined that the
head vents
had not been covered
and informed the outage
manager
who
investigated
and determined that the order to cover the openings
had
been
countermanded
by a maintenance
general
foreman but that
he
would ensure
the openings
were covered.
The
gC Manager informed the
inspector that the requirements
to cover the
head opening were not
clear and therefore
a nonconformance
report was not warranted.
The openings
were covered late in the day on 3/23/88.
A nonconformance
report was written on 3/24/88
(DC1 88 MM-N027).
The problems
encountered
in this series
of events
are:
The mechanics
and
gC involved in the generation of the work
order
and the execution of work did not implement
a fundamental
cleanliness
precept which is to exclude foreign. material
from
16
the reactor vessel
by covering the opening or establishing
clean conditions
around
and above the opening.
The plants correction of the problem was not timely.
Plant managements
direction to correct the problem was
countermanded
at lower levels without feedback to management.
Plant procedures
do not adequately
prescribe cleanliness
requirements
of ANSI 45.2. 1.
Once the problem was recognized,
plant staff did not inform
craft and
gC personnel
of the problem (to preclude repetition)
in a timely way.
The inspectors will followup the licensee's
corrective actions to
the above
problems through the licensee's
NCR process.
The licensee
committed to implement Regulatory Guide 1.37 and ANSI
N 45 2. 1.,
1973 in the
FSAR Table 17.2.
ANSI
N 45.2. 1 "Cleaning of Fluid Systems
and Associated
Components
of Water Cooled Nuclear
Power Plants" is applicable "during the
operation
phase".
ANSI
N 45.2. 1. paragraph
3. 1.2 describes
"Class
B" cleanliness
as
applicable to reactor coolant systems.
The standard
provides
guidance
in the flushing criteria as to the
maximum size of foreign
material
allowed specifically "there shall
be
no particles larger
than 1/32 inch in any direction".
The standard
gives further guidance in paragraph
6 "Maintenance of
Installation Cleannes" (sic) that "seals
must. be installed" or
"prior to opening surrounding
should
be cleaned.
It is noted that the licensee's
cleanliness
implementing procedures
NPAP-C-10 "Housekeeping
General"
an NPAP-D-6 Cleanliness
Controls
for Corrosion Resistant
Alloys do not address
many details of ANSI
N45.2. 1Property "ANSI code" (as page type) with input value "ANSI</br></br>N45.2. 1" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. nor do they invoke the basic definitions of cleanliness
classes
"A" "B" "C" and "D".
Procedure
NPAP 0-6 (for corrosion
resistant alloys only) does
invoke ANSI N45.2. 1.
by reference,
but
the lack of understanding
experienced with the mechanics,
gC
inspectors
and higher levels of plant staff indicate the procedures
and training dealing with cleanliness
are not adequate.
The implementation of ANSI N45.2. 1 into plant procedures
and the
emphasis
to plant workers of the fundamental
precepts
of cleanliness
around the reactor coolant system should
be addressed
by the
licensee
in response
to the apparent violation described
in Section
4.e. of this report.
Revisions to the Action Re uest
Pro
ram
The inspector
reviewed the licensee's
ongoing program to address
Action Request
(AR) program deficiencies
and backlog.
In July 1987
a task force concluded
by providing management
suggested
enhancements
to the Action Request
program.
Examples of proposed
changes
include the
use of component
ID should
be implemented
by the
Work Planning Center
and not the initiator as is currently required.
In the past, initiators not familiar with the comprehensive
component
I.D. system
have attributed problems to the wrong
component.
Concurrent with implementing
AR formal changes,
the licensee
plans
to implement
a revised prioritization program.
The program,
based
on one established
at Florida Power and Light's Turkey Point,
provides
a priority number
and required completion time.
As an
example,
a priority 1A would describes
work required to ensure
personnel
safety or prevent license violations within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The
licensee is confident that implementation of this program will
better categorize
work activities.
The revisions to the
AR program,
at the
end of this report period,
were
up for Plant Safety
Review
Committee
and Plant Manager review.
The inspector also reviewed the licensee's
AR and Work Order backlog
tracking system.
As of March 31,
1988 the licensee
had 1279
corrective maintenance
Action Requests
open excluding lowest
priority, "nice-to-do", work.
In the previous quarter the licensee
had completed
1,082 corrective maintenance
work orders.
Over the
last six months the licensee
has
improved its method of categorizing
and understanding its work backlog.
The inspector will monitor the implementation of AR program
revisions in a future inspection.
One violation and
no deviations
were identified.
12.
Instrumentation
and Controls
De artment Activities
Inspections
were conducted for two weeks
by a contractor to the
NRC,
INEL.
The area
examined
was Instrumentation
and Controls.
The results
will be reported in a future inspection.
13.
Inservice Ins ection
73753
In accordance
with the NRC's ISI work observation
procedure,
the
inspector
examined
ASME Code replacement activities
on the reactor vessel
head.
These activities included cutting leaking spare control rod drive
mechanism
head penetrations
and welding caps
on the cut ends.
Details of
the inspector's
examination
are provided in section 4.e. of this report.
14.
Exit
30703
On April 8,
1988 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.