ML16341F223
| ML16341F223 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 06/19/1989 |
| From: | Mendonca M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F224 | List: |
| References | |
| 50-275-89-14, 50-323-89-14, NUDOCS 8907070249 | |
| Download: ML16341F223 (40) | |
See also: IR 05000275/1989014
Text
'
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
50-275/89-14
and 50-323/89-14
Docket Nos:
50-275
and 50-323
License
Nos:
DPR-80 and
Licensee:
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:
April 23 through June 3,
1989
Inspector:
Approved by:
K.
E. Johnston,
Resident
Inspector
c~
M.
M. Mendonca,
Chief
Reactor Projects
Section
1
Date Signed
Summary:
Ins ection from A ri 1
23 throu
h June
1
1989
Re ort Nos.
50-275/89-14
and
50-323/89-14
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,
40500,
61726,
62703,
71707,
71710,
92700,
92701,
and 93702 were used
as guidance during this
inspection.
% p.
Results of Ins ection:
No violations or deviations
were identified.
Areas of Stren th
On May 4, 1989,
the Assistant Plant Manager for Maintenance
Services
on a
routine walkdown of the plant identified problems with a Unit 1 feedwater
control valve (section 4b).
Conservative
action was taken in that the
unit was taken to 25K power to repair the valve operator.
Areas of strength
were noted in the licensee's
response
to the grassland
fire (section 4h).
The fire fighting effort was successful
in that
no
structures
were
damaged
and despite
high winds the fire was contained to
118 acres
of grassland.
Additionally, the licensee
took conservative
89070
o
00275
ADOCK 0
pNU
6
action in reducing the power of both units in anticipation of a potential
loss'f load which could have re'suited
when the fire burned
under the
Unit 2 500
KV output lines.
Areas of Weakness
o
On May 23,
1989,
two motor operated
valves for the Unit 1 Auxiliary
Saltwater
System failed to close
when operated
from the control
room.
Weaknesses
identified as
a result of the failures were the degrading
material condition of equipment
exposed to the salt environment
and the
adequacy of the maintenance
program for the manual
operators
of motor
operated
valves.
Although the licensee
has taken steps to address
both
concerns
(see sections
5a
8 5b), continued attention is warranted.
Further examples
of previously identified weaknesses
include the following:
o
Equipment lineup problems resulting from the inadvertent operation of
plant equipment
by individual in training (section 4e).
o
Equipment lineup problems resulting from procedures,
performed subsequent
to system alignment,
which have inadequate
or inconsistent return to
service instructions (section 7).
o
Design basis
implementation
weaknesses
associated
with containment
combustible
gas control
systems
(section 7).
Although these
are identified as continuing weaknesses, it should
be noted
that these
items were reviewed prior to the implementation of planned
corrective action programs
and therefore
a statement
as to their effectiveness
cannot
be made.
0
DETAILS
1.
Persons
Contacted
"J.
D. Townsend,
Plant Manager
"D.
B.
Miklush, Assistant Plant Manager,
Maintenance
Services
- L. F.
Womack, Assistant Plant Manager,
Operations
Services
"B.
W. Giffin, Assistant Plant Manager,
Technical
Services
"M. J.
Angus, Assistant Plant Manager,
Support Services
"C.
L. Eldridge, guality Control Manager
R.
G. Todaro, Security Supervisor
T.
A. Bennett,
Maintenance
Manager
D.
A. Taggart, Director guality Support
W.
G., Crockett, Instrumentation
and Control Maintenance
Manager
H. J. Phillips, Work Planning
Manager
- T. L. Grebel,
Regulatory Compliance Supervisor
J.
A. Shoulders,
Onsite Project Engineering
Group Manager
"M.
E.
Leppke,
Engineering
Manager
S.
R. Fridley, Operations
Manager
"K. Doss,
OSRG
- W. Kelly, Regional
Compliance
"K. J.
Condron,
NECS
R.
P.
Powers,
Radiation Protection
Manager
M.
R. Tresler, Project Engineer
E.
C. Connell, Assistant Project Engineer
PGKE Personnel
at Meetin
on June
13
1989
S.
M. Skidmore,
Manager, guality Assurance
D. Taggart,
Supervisor, guality Support
C. Coffer, Supervising
Engineer,
Nuclear Regulatory Affairs
C. Dogherty, guality Support
NRC Personnel
at Meetin
on June
13
1989
R.
P.
Zimmerman, Acting Director, Division of Reactor Safety
and Projects
D.
F. Kirsch, Chief, Reactor Safety Branch
M.
M. Mendonca,
Chief, Reactor Projects I
J.
L. Crews,
Senior Reactor
Engineer
The inspector 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 personnel.
"Denotes
those attending the exit interview.
0 erational
Status of Diablo Can on Units 1 and
2
During the inspection period,
both units remained at full power with a
few exceptions.
Unit 1 entered
the report period at 50X power to perform
extensive
cleaning .of the circulating water tunnels.
Unit 2 reduced
power to 50'n the weekend of April 28 to repair
a condensate
booster
pump and to investigate
a ground detected
on the breaker to a main
pump.
Unit 1 power was reduced to 25K on May 4 to repair the
valve operator for a main feedwater control valve.
On May 23 a wildfire,
caused
by a downed
12
kV power line, burned
118 acres
adjacent to the
plant and burned
under the Unit 2 500
kV output lines.
An Unusual
Event
was declared
and both Unit 1 and
2 initiated power reductions to 50K
power
as
a conservative
measure
in anticipation of a possible
loss of
load.
Unit 1 reached
approximately
75K power before its ramp was
terminated.
Unit 2, which reached
50K power,
remained curtailed for the
following two days to allow the investigation of the trip at 50K power of
one of the circulating water pumps.
0 erati onal Safet
Verification
71707
During the inspection period, the inspector
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
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 inspector 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)
Engineered
safety feature
equipment alignment and conditions.
(i)
Storage of pressurized
gas bottles.
The inspector 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'he
involved work activities.
No violations or deviations
were identified.
3
4.
Onsite Event Follow-u
(93702
No Surveillance Testin
of Pressurizer
Power
0 crated Relief Valve
Tail Pi
e
Tem erature
Indicators
On April 28, 1989, the licensee
discovered that
no surveillance
testing
had been performed for the pressur izer power operated relief
valve
(PORV)
common discharge
temperature
channel.
Technical Specification (TS) 4.3.3.6
item 13 requires that
a channel
check
be
performed
once
a refueling outage.
On May 3 for Unit 1 and
May 2 for Unit 2,
a channel
check was
performed
on the temperature
channels
and both were found within
calibration limits.
On May 24, 1989 the licensee
issued
Licensee
Event Report
(LER) 50-275/86-24.
The licensee's
corrective
actions
include
a re-revview of the Technical Specifications
and all its
revisions to ensure that all required survei llances
are
proceduralized.
The inspector
has
reviewed the
LER and found both
the root cause
review and corrective actions
taken to be acceptable.
Unit 1 Feedwater
Control Valve Air 0 erator Problems
On May 4, 1989, the assistant
plant manager for maintenance
services
noted
on a plant walkthrough that the controller for the feedwater
control valve FCV-530 was causing the valve to move excessively.
The excess
motion appeared
to have induced minor packing leakage.
As a result of this problem, the plant was taken to less than
30K
power to allow valve closure
and repair.
The air regulator for the
valve operator
was found to have failed high and was replaced.
Since this balance of plant problem resulted in a brief curtailment,
the license initiated a quality evaluation to determine root cause
and corrective actions.
C.
The inspector
found that the identification of plant problems
by
senior plant management
to be indicative of the value of the
licensee's
plant. management
plant walkthrough program.
Additionally, the inspector
found the conservative
action to curtail
power to fix the problem and then initiate the quality evaluation
process
to be commendable.
Diesel Generator
1-2 Failed to Start Mithin Ten Seconds
On May ll, 1989, Diesel Generator
(DG) 1-2 failed to achieve its
rated
speed of 900
RPM within 10 seconds
as .required:by Technical Specification (TS) 4.8. 1. 1.2.a.2).
DG 1-2 attained
r'ated
speed ',in
10.22
seconds
and attained rated frequency
and voltage within'13
seconds
(as required
by the
same TS).
The test
was performed,;by
procedure,
with the backup
DC power unavailable,
disabling two of
four 'airstart motors.
Operations
declared
DG 1-2 inoperable
pending resolution of the
start time.
Subsequently,
DG 1-2 was started six additional times,
four times in the identical configuration (two of four air start
motors available)
and twice with one of four air start motors
available.
In the case of the first four tests,
the start times
were measured
to be less
than 9.2 seconds.
In the case of the tests
with one air start motor available
(a configuration beyond design
basis)
DG 1-2 started in less
than 10.4 seconds.
Based
on the four
acceptable
tests
done in the identical configuration of the first
failed test,
DG 1-2 was accepted
as operable.
Plant engineering
determined that the failure to start was not a
valid fai lure as described
in Regulatory Guide 1. 108 since the
acceptance criteria in the Regulatory Guide only addresses
coming to
rated voltage
and frequency,
and not speed, within specified time
limits'.
However,
on May 30,
DG 1-2 was again tested in the original test
configuration
and attained rated
speed in 8.77 seconds.
In
addition,
a quality evaluation
was initiated to evaluate root cause
and corrective actions.
At the end of the inspection period, the
licensee,had
not identified the root cause,
but suspected
operator
error in the use of the stop watch.
The inspector
found the
licensee's
actions acceptable.
Flow Element
Usa
e for Residual
Heat
Removal
S stem Testin
On May 17,
1989, the licensee
discovered that the appropriate
water
density correction factors
had not been applied to the Residual
Heat
Removal flow indicators
used for surveillance testing.
The flow
indicators,
FI-970 and 971,
have
been
used in Technical
Specification survei llances to verify full flow ECCS injection of
3976
gpm and 3000
gpm at midloop operations.
The licensee
found
that while the flow indicators are calibrated at 400 degrees
F,
testing
has historically been performed at temperatures
below 100
degrees
F.
This has resulted in a non-conservative
measurement
of
volumetric flow rate of approximately nine percent.
The licensee,
which intends to issue
a
LER on the subject,
determined that it had been their own error in the application of
the indicators.
In review of previous surveillances,
the licensee
determined after
making the appropriate
correction of flow rate, that at the"time of
the Unit 1 second refueling (April 1988)
a violation of 'the
TS flow
rate required during refueling operations
had been
made.
At that
time the requirement of TS 3.9.8.1
was
3000
gpm and the
administrative limit was
3050
gpm.
When corrected
for temperature
with 3050
gpm as the indicated flow value, the actual flow value
would have
been approximately
2800
gpm.
However,
a subsequent
TS
amendment
was issued to require that
RHR flow be greater
than 1300
gpm when the reactor
has
been subcritical for greater than
57 hours6.597222e-4 days <br />0.0158 hours <br />9.424603e-5 weeks <br />2.16885e-5 months <br />.
As a result there
was
no safety significance to the apparent
degraded
flow.
As part of their review the licensee
also determined
that there were
no other similar misapplications
of flow
instrumentation.
The licensee
has initiated
a nonconformance
report.
The inspector
will review the licensee's
root cause
analysis
and corrective
actions for adequacy
and potential generic implications in a future
inspection.
Hot Shutdown
Panel
Switches
Found Out of Position
On May 17, 1989,
an operator,
accompanied
by a licensee
examiner
and
an
NRC examiner,
discovered that at the hot shutdown panel
(HSP) for
Unit 2, the control
room to local switch for emergency boration flow
valve CVCS-2-8104,
was mispositioned in the local position.
Operations
personnel
later found that the Unit 1 hydrogen recombiner
was also out of position.
The operations
manager
found that in the case of the hydrogen recombiner potentiometer,
an
operator in the process
of his job performance
measures
(JPM) for
requalification testing,
had inadvertently taken control of the
switch and not returned it to its original position.
The operations
manager felt their was adequate
evidence to show that CVCS-2-8104
had been subject to a similar occurrence (i.e.,
a month prior a
complete
walkdown of the
HSP had been performed
and independently
verified, the
HSP is alarmed in the control
room,
and only operators
in training had
made routine access).
In both instances,
the mispositioned
switch did not affect the safe
operation of the plant nor would have affected operations
in the
event either
emergency boration from the
HSP or use of the hydrogen
recombiners
was required.
Operations policy required that if in the performance of a JPM an
operator
needs to operate plant equipment,
specific permission
must
be granted
by the shift foremen.
An example of a case
where
operation of plant equipment is necessary
for training is the
resetting of the turbine driven auxiliary feedwater
pump trip valve.
In the instances
described
above,
actual
manipulations of control
were not required nor was the shift foreman notified.
The operations
manager took the following corrective actions:
o
The operations policy was revise to be more specific with
respect to the operation of plant equipment during training..
The plant manager
issued
a memorandum to plant personnel.
concerning the proper authority require to operate
p]ant.:.-"-;
equipment.
'
All operators
and trainers
were briefed in the event and th'
revised guidance.
The inspector
found these actions to be acceptable.
Failure of Two Unit 1 Auxiliar Salt Water Valves to Close from the
Control
Room
On May 23, while preparing to remove
a Unit 1 train of the Auxiliary
Saltwater
(ASW) System
from service,
two valves failed to operate
from the control
room.
Both 1-FCV-496,
a pump discharge crosstie
valve,
and 1-FCV-602, the 1-1
ASW heat exchanger inlet valve, failed
to close.
The cause of the these failures is discussed
in greater
detail in Section
5 a) and b).
Accidental Actuation of the Unit 2 Auxiliar
Pum
- Terr
Turbine Overs
eed Tri
On May 23,
1989, the Unit 2 control
room received indication that
Pump terry turbine overspeed trip mechanism
had actuated.
The security
computer
access
records
were checked to
identify individuals- in the area at the time of the trip.
The
individuals in the area
were questioned
and it was determined that
decontamination
workers,
doing a routine clean
up of the
pump skid,
had accidentally tripped the valve and not recognized their actions.
The operations
manager,
following a walkdown of the pump,
found that
the warnings at the
pump were not explicit enough to prevent plant
personnel
unfamiliar with system operations
from inadvertently
tripping the overspeed trip valve.
At the end of the inspection
period the licensee
was evaluating
how best to illustrate the
problem.
The inspector
found this action acceptable.
Unusual
Event
Due to Grass
Land Fire
On May 23, at 6:31 p.m.,
a downed
12
KV utility line started
a grass
land fire on the hill just southeast
of the units.
The power line
was blown over by high winds (up to 70 mph in gusts).
An Unusual
Event was declared
when it was apparent, that the California
Department of Forestry would be needed to fight the fire.
The fire burned approximately
118 acres,
burning mostly to the south
of the plant.
The northern
edge of the fire progressed
slowly
against the wind toward the Unit 2 500
KV output lines.
As a
.;
conservative
measure,
a power reduction to below .50K .power was;,",,~,,;,
initiated for Unit 2 at 8:02 p.m.
and for Unit 1 at 9:56 p.m.",.This
was
done in anticipation of the possibility that the fire burning,
under the 500
KV lines could cause
arcing .in the line, open the'-'-
output breakers,
and result in a load rejection.
It was concluded
by the licensee that there
was
a better chance of .maintaining-'the
reactor critical following a load
rejection,if'the'nit'ere~'='.5'nitially
at or below 50K power.
In addition", opera'tors
switche'd
Unit 2 plant loads to startup
power
so Chat a'fast transfer."..."
following a load rejection would be unnecessary.
The Unusual
Event was terminated at 1:07 a.m.
when the north end
fire was put out.
Unit 1 was retur ned to 100K power.
Unit 2
remained at 50K power, following the trip of a Circulating Water
Pump
(see section 4.i).
While the licensee's
overall handling of the fire was good, there
were
some lessons
learned
from the event:
o
Notification of the
CDF could have
been
more timely.
Following
the decision to notify the
CDF, the Shift Foreman given the
task did not have the
number at hand
and instead called the
Sheriff and requested
that
he notify the
CDF.
While this is
allowed by the Emergency
Procedures,
direct communications with
CDF would be
an improvement to the licensee's
response.
o
The
NRC Incident Response
Center
was not given an update
by the
control
room of the decision to reduce
power resulting from the
proximity of the fire to the Unit 2 output lines.
These
weaknesses
were discussed
with licensee
management
who
concurred with the assessment.
The licensee
committed to perform a
case
study of the fire, including positive and negative aspects,
for
review by the operations
department.
In addition,
on June 9, the
plant manager
met with the California Department of Forestry to
discuss
communications.
The licensee
also initiated actions to
modify the existing communications
system in the control
room and
changed
the fire notification number to 911.
The inspector
found
these
actions to be acceptable.
Unit 2 Circulatin
Mater
Pum
Tri
On May 24, at 12: 13 a.m., Circulating Water
Pump
(CWP) 2-1 tripped
unexpectedly.
Five minutes later, the breaker reclosed;
again
unexpectedly.
Unit 2 was
a 50K power at the time due to the grass
land fire discussed
above,
"and the loss of the
CWP only minimally
affected plant operations.
Following an extensive investigation,
the licensee
was unable to
determine the cause of the failure.
The investigation included the
following;
o
a review of the
CWP control logic and an inspection of the
relays determined that
no valid trip and close signals
were
present.
testing
was performed
on all relays
and wiring in all parts of
the circuit which could have caused
a trip.
a verification of plant configuration versus wiring diagrams
was performed
by electricians at the site.
'I
a verification of wiring diagrams
versus
design logic
was,'erformed
by design engineering.
The licensee
was unable to identify any credible
sequence
o'f events
or failures which would have resulted
on the
pump trip.
The
decision to return to full power was
made
based
on the complete
verification of the operation of the circulating water
pump motor
~,
control circuit.
Instrumentation to monitor points in the circuit
were added.
The inspector
found these
actions to be acceptable.
5.
Maintenance
62703
The inspector
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 inspector verified maintenance activities were performed
by qualified personnel,
in accordance
with fire protection
and
housekeeping
controls,
and replacement
parts
were appropriately
certified.
a.
Maintenance of ASW Crosstie
Valve 1-FCV-496
As discussed
in section 4.f,
ASW Crosstie valve 1-FCV-496 did not
close
when actuated
from the control
room.
Mechanical
Maintenance
found that the lever on the motor operator which takes the valve
from automatic to local
hand control
had not returned completely to
the automatic position due to rust.
In addition, it was found that
the hand wheel
was frozen in place
due to rust.
Immediate
corrective actions
were to lubricate the valve.
The licensee
added this incident to an open non-conformance
report
related to the the rusted gland packing follower for crosstie
valve
1-FCY-495, discovered
in January
1989.
Subsequent
to the event,
the inspector
was
made
aware that while the
valve body was design
Class
1, the valve operator
was design
Class
2, non-safety.
The inspector
requested
design engineering to
provide the basis for this determination.
Engineering
responded
that the cross-tie
was normally required to be open but was required
to isolate the
ASW trains in the event of a passive failure to one
train.
Additionally, the design basis
does not assume
a passive
failure until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following a design basis accident.
At that
time, decay heat is reduced to the point that time is available to
allow manual actuation of the crosstie valves.
As a result of this finding, the inspector addressed
two questions
to the licensee:
1) were adequate
corrective actions initiated,
following the
FCV-495 packing gland follower problem and the
'aterial
condition findings of the
NRC team inspection in February
1989, to address
rust at the intake;
and 2) what actions
has the
licensee
taken to assure
the manual
operators
on automatic valves
are properly maintained.
With respect to material condition of safety related equipment at
the intake area,
the licensee
responded that extensive
work had been
undertaken
to counteract
the corrosive environment.
Actions taken
include the following:
o
During the last outages, all four ASW motors
and
pumps were
completely disassembled,
cleaned
and refurbished,
o
all
ASW check valves
have
been inspected,
o
the
ASW pump
room ventilation fans
have
been placed
on an 18
month maintenance
program,
o
carbon steel
valve packing followers have
been
scheduled to be
replaced with stainless
steel followers,
o
and dedicated
maintenance
and paint crews
have been stationed
at the intake area.
With respect to the maintenance
of manual
valve operators of motor
operated
valve, the licensee
has initiated a review of the adequacy
of maintenance
being performed.
This will be carried
as
an open
item to verify the adequacy of the licensee's
program review
(Follow-up Item 50-275/89-14-01).
Maintenance of ASW Heat Exchan er Inlet Valve 1-FCV-602
As discussed
in section 4.f.,
ASW
heat exchanger inlet valve
1-FCV-602 did not operate
from the control
room.
Maintenance
found
that the key joining the shaft to the actuator
had sheared.
An
inspection of the key showed it had been subject to metal fatigue.
An NCR was initiated on this event.
At the end of this report
period the licensee
had not established
the root cause of the key
failure.
However, maintenance
had inspected
two of the other three
ASW heat exchanger
valves
and planned to inspect the third.
No
further key problems
were identified.
The inspector
found these
actions to be acceptable
and will follow-up the root cause
and
corrective action review in a subsequent
inspection.
Additionally,
the inspector
also reviewed past history of the valve.
The
inspector verified that the preventive maintenance
and increased
surveillance testing committed to by the licensee in response
to
inspection findings contained in inspection report 50-275/87-11
have
been performed.
The inspector also reviewed past history of the
valve.
Februar
1988 Failure of FCV-602
The inspector found that FCV-602 failed to close
on February 16,
1988.
The Instrumentation
and Controls (IBC) department
found the
air regulator for the valve operator to be controlling at
5 psi
as
opposed to 60 psi
as designed.
In addition, the regulating valve
pressure
gage
was found to have "stuck" at 60 psi.
=INC technicians
readjusted
the regulator
and replaced
the gage with a plug.
The
regulator failure was not identified as
a "quality problem" and the
lowest level of problem evaluation,
a guality Evaluation (gE),was
not performed.
The inspector
addressed
the following questions
to the
18C manager:
o
Should
a gE have
been initiated to determine root cause
and
corrective actions?
10
o
Should
a design
change
have
been processed
to change
the gage
to a plug?
o
Were the appropriate
design
Class
1 regulators installed in the
plant?
The following responses
were obtained:
o
The guality Control
(gC) Manager determined that this was
a
quality problem and
a gE should
have
been performed.
As a
result,
a gE was initiated.
Subsequent
to February 1988,
gC
identified as
a problem the initiation of gEs
and
has 'taken
a
number of corrective actions.
The actions
included the
training of the
gC staff on what constitutes
a quality problem
and limiting the
number of individuals who determine
the
necessity of a gE.
The inspector
found these actions to be
acceptable.
o
The licensee
determined that
a design
change
was not needed
since the pressure
gage
does not perform a design function, it
is not calibrated,
the design specification
does not indicate
that
a gage is required,
and regulators
supplied in either
configuration are considered
acceptable.
The inspector
found
this response
acceptable.
o
The licensee
confirmed that the regulators
were required to be
instrument design
Class
1A.
However, at the time of this
report, the licensee
had not been able to provide documentation
of the purchase
requirements
for the regulators for the Units 1
and
2
ASW heat exchanger inlet valve operators.
This is an
unresolved
item (Unresolved Item 50-275/89-14-02).
No violations or deviations
were identified.
6.
Survei
1 1 ance
61726
Containment
Combustible
Gas Control
S stem
The inspector
observed
the performance of surveillance testing for Unit 2
boric acid storage
tank level transmitters.
Through direct observation
and record review of the surveillance testing,
the inspector assured
compliance with TS requirements
and plant procedures.
The inspector
verified that test equipment
was calibrated,
and acceptance
criteria were
met.
k
No violations or deviations
were identified.,
,. <<
7.
En ineerin
Safet
Feature Verification
71710
I4 *
,
e
-
<<j'<
In review of the valve and breaker alignments, it was determined..by
the
operations
department that the misalignments
had occurred during-.,valve
and system testing performed subsequent
to startup valve alignment,
(performed
once for each unit following refueling outages).
As an
"
example,
the surveillance tests to satisfy
ASME stroke testing for
containment isolation valves
FCVs 658,
659, 668,
and 669 did not require
that the breakers
be racked out following completion of the testing.
12
As corrective
actions with respect to breaker position, the operations
department initiated steps to require that the containment isolation
valve breakers
be sealed in the open position to provide positive
control.
It had not been determined at the end of the inspection period
whether
or not it had always
been the intent of TS surveillance 4.6. 1. 1. a
and General
Design Criteria 56 that the breakers
be sealed
in the open
position during plant operations.
Additionally, it was unclear whether
the licensee
had complied with the asterix portion of TS 4.6. l.l.a
(position verification during every
COLD SHUTDOWN) for inside containment
isolation valves
FCV-658 and FCV-668.
This is an unresolved
item
(Unresolved
Item 50-275/89-14-03).
The operations
department initiated a number of other steps to address
the valve misalignments:
o
Action was initiated to revise the OVIDs to reflect
OP H-8: II.
o
Action was initiated to revise applicable surveillance tests to
return the system to the alignment specified in OP H-8: II.
o
On the Spot Changes
were
made to the procedures
governing the
control of Post-LOCA sample valves to require that when not in use
the fuses for each valve be pulled.
This was
done to ensure that
the valves could not be inadvertently operated.
o
The licensee
has instituted
a generic
program to assure
equipment
lineup in accordance
with discussion
in an April 25,
1989
Enforcement
Conference.
H dro en Monitor Alarm Set oint
In review of the Annunciator response
procedures
for the hydrogen
monitors
(CEL 82 and 83), the annunciator setpoint
was found to be 4X
The
FSAR states
that the combustible
gas control system is
designed
to maintain hydrogen concentration
below 3.5X where 4.3X is the
lower limit for hydrogen flammability.
The inspector
requested
the
licensee to provide justification for the setpoint.
The licensee
responded
that
design
document
(WCAP 7709L,
Supplement
5) cautions,
but does not prohibit, the use of the hydrogen
recombiners
above
4X concentration
since it is possible that they may
become
a source of ignition.
As a warning that concentrations
are too
high for the
use of the recombiners,
the document suggests
an alarm
setpoint of 4X.
k.
Prior to the identification of this concern,
the licensee
by two separate
paths
had identified similar concerns.
The IBC department
had idehtified
it in March,
1989 in conjunction with their review of instrument
accuracy.
The Engineering department
had identified it in early May,
1989 through their review of FSAR commitments.
At the end of the
inspection period, the licensee
had not established
a final solution that
balanced
instrument accuracies
with the philosophy of annunciator
setpoint.
This issue
was
a licensee identified item of inadequate
configuration control (i.e., although the alarm setpoint
was
4X hydrogen,
13
the purpose of the alarm was not implemented in that no caution
was
included in the annunciator
response
procedure stating that the hydrogen
recombiners
may need to be shut off).
The inspector will follow this
item during routine inspection.
S stem
0 eratin
Procedures
The inspector
reviewed the system operating procedures
to verify that
adequate
instruction was provided.
The licensee,
following a review of
the design basis for the system,
stated that its intent was for the use
'of the internal
recombiners
to be initiated by the control
room
and followed up by the Technical
Support Center
(TSC) while the use of
the hydrogen
purge
system
was to be controlled by the
TSC.
The inspector
determined that the path provided in the emergency
procedures
for the use of the internal
hydrogen recombiners
was fairly
clear.
However, outside the emergency
procedures,
the path was not as
clear.
Guidance pertaining to the vendor's
concern that where the
internal
recombiners
could serve
as
an ignition source,
as discussed
in
the preceding section,
were not included in the operating procedure for
the internal
recombiners
or the annunciator
response
procedure.
In
addition,
guidance
was not provided in OP H-8: I that it was the TSC's
decision
as to when the purge
system should
be placed in service.
Finally, the licensee
had
no procedures
or instructions for the
initiation of procurement of an external
hydrogen recombiner (although
there is a lineup procedure if one is to be used).
These
weaknesses
were discussed
with operations
and engineering
management.
Revisions
were
made to the Annunciator Response
procedure
for high hydrogen to reflect that the
TSC contacted if high hydrogen
concentration is noted.
A precaution
was added to the Hydrogen Purge
make available procedure
(OP H-8: I) to state that the system
be placed in
service at the direction of the
TSC.
This
same direction, along with a
caution for use of the hydrogen
recombiners
in concentrations
of greater
than
4X were
added to
OP H-9, the containment internal
recombiner
procedure.
Conclusion
In the review of the the combustible
gas control system,
three basic
issues
were developed.
l.
Equipment lineup for the system
was not effectively controlled and
subsequently
was not in its proper lineup.
However, the equipment
lineup problems did not effect the operability of the system.
The
licensee
has undertaken
a significant equipment alignment program
(discussed
in the April 25,
1989 meeting,
Inspection Report,'"
'~ '*
50-275/89-15).
This system
had not undergone its review at the time
of this report and therefore
a statement
as to the effectiveness
of
the licensee's
corrective actions with respect to equipment lineups
is premature.
The licensee
was responsive
to the inspector's
findings and took acceptable
corrective actions following the
identification of problems.
14
There were weaknesses
in the implementation of the system design
basis.
This was evidenced in the hydrogen annunciation
issue
and
the lack of adequate
guidance in procedures
other than the emergency
procedures
as to when the various
components
of the system are
used.
As with the equipment lineup issue,
design basis
implementation
issues
have
been the subject of much correspondence
and the licensee
has initiated an extensive configuration management
program
(Inspection
Report 50-275/89-11).
Additionally, a design basis
review had not been performed
on the hydrogen purge system.
The
licensee
was in the process
of an
FSAR review which identified the
concern.
3.
As stated
above, this inspection
has
an unresolved
item with respect
to the licensee's
implementation of the Containment Integrity TS as
it applies to remote manually actuated
motor operated
containment
isolation valves
(FCVs 658,
659,
668,
and 669).
This will be
resolved in a future inspection.
8.
No violations or deviations
were identified.
Radi ol o ica 1 Protection
71707
The inspector 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 inspector 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
RWP (Radiation Work Permit).
No violations or deviations
were identified.
9.
Ph si cal Securi t
(71707
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 ort Follow-u
92700
a ~
Status of LERs
The
LERs identified below were also closed out after review and
follow-up inspections
were performed
by the inspector to verify
licensee
corrective actions:
Unit 1: 86-24,
see section
4a.
15
Unit 2: 88-02
Rev.
2,
see review below.
b.
Reactor Tri
Due to an Undetected
Failed Rela
Durin
Seismic Tri
Channel
Testin
LER 2-88-02
Rev. 1
Closed
On May 15,
1989, the licensee
submitted
a revised
LER, which
included
a completed root cause
review, for the March 3, 1988,
reactor trip due to an undetected failed relay during seismic trip
channel testing.
The root cause
review included in the revised
LER stated that the
seismic trip relay had failed due to deterioration of the coil
insulation.
Deterioration of the coil insulation was attributed to
the
use of the 110 Vdc rated coil in a system normally supplied
by
135.7
Vdc power.
The inspector questioned
whether there were any other relays
important to safety which could be susceptible to this type of
failure.
The licensee
responded that in the case of the reactor
trip system, all other relays
are supplied
form a separate
AC power
source.
Additionally, the components
supplied
by the vital
buses,
normally subjected to 135. 7 Vdc, have nominal ratings of 125
Vdc with maximum continued service ratings of 140 Vdc.
The licensee
stated that these
relays
and components
have not had
a history of
failure.
As corrective actions,
seismic trip system status lights have
been
provided
and
a system
upgrade is scheduled for the next refueling
outages.
The inspector
found these actions to be acceptable
and
review of this
LER is closed.
No violations or deviations
were identified.
11.
0 en Item Follow-u
92703
92702
a.
Boron In ection Tank
BIT
Relief Valve Leaka
e
Unresolved
Item
50-323/87-34-02
Closed)
This item concerned
aspects
of the licensee's
review of BIT relief
valve leakage
and its potential effects
on post-LOCA environment.
Inspection
Report 50-323/87-38 identified two outstanding
questions.
1)
Has the licensee initiated a corrective action root cause
evaluation of why FSAR leakage limits for post-LOCA
recirculation were not incorporated into STP M-86? .
This type of review was not performed.
However, the licensee
has taken action since to address
these 'types of problems.
'pecifically,
this was just one of many identified
configuration management
issues
which led the licensee to
initiate their configuration management
program.
As part of
that review, the plant system engineers
have
been performing
a
review of FSAR commitments to assure their adequate
implementation in procedures.
16
2)
What consideration
is being given to leakage evaluation
between
refueling outages?
The licensee
was in the process
of issuing
a procedure to
address all aspects
of leaking systems,
including this concern
of maintaining
a "living" post-LOCA recirculation
system
leakage
number.
In the
mean time, the licensee
has reviewed
each
leak on a case
by case
basis against the post-LOCA
recirculation leakage limit. It was noted that analysis
performed subsequent
to the BIT relief valve leakage
issue
showed that the licensee
remained within their dose calculation
with 1.44
gpm leakage
in a filtered area
and 0.155
gpm in an
unfiltered area.
This is opposed to the 1910 cc/hr that had
been previously identified in the
FSAR.
The FSAR,number
had
been
based
on the maximum normal
leakage
expected
(by adding
up
expected
pump seal
and valve packing leakage).
Based
on the above, this item is closed.
b.
Redundanc
of Diesel Generator Air Start Trains
Unresolved
Item'0-275
89-05-02
Closed
This item concerns
questions pertaining to the redundancy
requirements for diesel
generator
(DG) air start trains discussed
in
Inspection
Report 50-275/89-05.
The redundancy
requirement
identified in the inspection report was that with the "normal" train
of air start motors out of service
on the local selector switch in
the "back-up" position, the
DG is inoperable
since with one single
failure it would be possible for two DGs to be unavailable.
The
questions
and associated
resolutions
are listed below:
1)
Should the licensee
have identified the
DG airstart train
operability concern earlier?
The inspector
reviewed the previous
documentation
(NRC
Inspection
Report 50-275/88-17,
gA Audit finding report 87-296,
Non-Conformance
Report DCI-88-TN-069) and found that while all
addressed
closely related
issues
none addressed
the question
specifically.
However, in not asking the question of what are
the redundancy
requirements for the
DG air start system,
especially following the failure of a
DG to start in rated time
with one train out of service, plant engineering displayed
a
lack of depth in their problem evaluation.
The licensee
has
established
the configuration management
program (described in
PG8E letter
dated April 19, 1989) to address, future concerns of
similar nature.
w
2)
Has the licensee
ever operated with an undeclared 'inoperable
(as
a result of not having identified air start redundancy
requirements)?
The plant engineering
manager stated that the above
had never
occurred.
17
3)
Were corrective actions
taken in a timely way?
Once the problem was identified and understood
by the licensee,
action
was taken in a timely way to revise the monthly testing
of the
DGs to identify air start redundancy
requirements.
Based
on the above, this unresolved
item is closed.
Maintenance
of Dia hra
m Valves
Unresolved
Item 50-275/87-38-04
Cl osed
Inspection
Report 50-275/87-38 discussed
the licensee's
maintenance
practices for diaphragm valves.
The inspector found that the
licensee's
maintenance
program did not address
the following items;
o
corrective actions to assure
periodic diaphragm replacement
(including valve clearance
problems)
o
diaphragm shelf life
o
maintenance
of diaphragm valves in accordance
with the vendor
manual
including stroke adjustment
(manual
and operated
valves)
o
status
(open or closed) of vent plugs
on valve bodies in the
plant,
and the need for vent lines to drain.
The licensee
has taken the following corrective actions;
o
The licensee,
in March 1988, initiated a diaphragm replacement
program.
The program
was based
on the safety service
and
environmental
service of the valves.
Valves in the charging
pump suction
and boration flow 'path valves (mostly heat
traced
and in a 12K boric acid solution) were scheduled
to be
changed
out every five years or every third refueling outage.
Valves in high radiation service or would cause
operational
problems if they fail are scheduled for change-out
every ten
years or seventh refueling outage.
The balance
are not
scheduled
and are to be changed
as
needed.
o
The licensee
completely revised Maintenance
Procedure~MP
M-51.,7
and included stroke settings
and appropriate lubrication" ~,:.'..
requirements.
o
Following discussions
with the vendor and
a review of 'diaphragm
failure history, it was concluded that a bonnet,.plug inspection
program was not needed
and that plugs are to be left installed
in the bonnets.
~
r
' 14
l4
The inspector
found these corrective actions to be acceptable.
The
licensee
has subsequently initiated a review of vendor .manuals to
ensure that applicable
maintenance
requirements
are included in
plant procedures.
This action was initiated in response
to the
findings related to the turbine driven auxiliary feedwater
pump
0
18
overspeed trip valve (Inspection
Report 89-13).
Unresolved
Item
50-275/87-38-04 is closed.
Meetin
with ualit
Assurance
The meeting
commended at 10:00 a.m.
Mr. Skidmore presented
an agenda
and
package
of, information (attachment
1).
He then presented
a summary of
the licensee's,Safety
System
Outage Modification Inspection Surveillance
Program
(SSOMI).
Mr. Skidmore indicated that the latest
SSOMI findings
were under final review by the line organizations
and Quality Assurance
(QA) felt that the response
was positive.
The topic of field changes
to
design
changes
was discussed
and the licensee's
program of ".Rev. A"
design review was described
by Mr. Taggart.
Messrs.
Kirsch and Crews
suggested
that the licensee
review consider the design process that
Washington Nuclear Plant
2 had instituted.
Mr. Skidmore indicated that
based
on the
SSOMI results
PG&E engineering
was initiated major
modifications to the design
change
process
and that
QA would review the
modifications to assure
timely, comprehensive
corrective actions.
Mr.
Skidmore viewed the
SSOMI and the Safety System Functional Audit and
Review Program
(SSFAR)
as positive steps to improving engineering
wor k at
PG&E.
Mr. Kirsch encouraged
the licensee
to continue to develop the
aggressive,
penetrating
engineering attitudes
not only in engineering
and
QA but also in the
QC departments
at the plant and engineering.
Mr. Skidmore then discussed
the licensee's
efforts in the supplier audit
area,
and that
a dedicated
group of PG&E engineers
was
used in this
effort.
Messrs.
Mendonca,
Kirsch and Crews emphasized
the importance
that the
NRC was placing on this topic.
During the discussion
of the
Emergency Operating
Procedure effort at
Diablo, Mr. Kirsch pointed out the importance of assuring that
Human
Factors
was considered
during this review and this was acknowledged
by
Mr. Skidmore.
Mr. Skidmore asked
a question
'on the NRC's inspection report 89-13 in
regard to the cover letter discussion
on the adequacy of management
and
quality organization discussion.
Mr. Mendonca
responded that the cover
letter discussion
was oriented toward the opportunities for management
and the quality organizations
to identify and mitigate the problems
discussed
in the report.
Unresolved
Item
,$Y. '
An unresolved
item is a matter about which more information is required
to ascertain
whether it is an acceptable
item,
a deviation, or a'." ': ".
violation.
Unresolved
items are documented
in paragraphs
5.b
and"7-.-~>>'n
June
16,
1989,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspector
summarized
the
scope
and findings of the inspection
as described
in this report.