ML17346B149
| ML17346B149 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 10/01/1985 |
| From: | Architzel R, Callan L, Martin T, Mckee P, Morris G, Overbeck G, Shymlock M, James Smith, Walenga C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II), NRC OFFICE OF INSPECTION & ENFORCEMENT (IE), WESTEC SERVICES, INC. |
| To: | |
| Shared Package | |
| ML17346B148 | List: |
| References | |
| 50-250-85-32, 50-251-85-32, NUDOCS 8510150228 | |
| Download: ML17346B149 (34) | |
See also: IR 05000250/1985032
Text
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OFFICE
OF INSPECTION AND ENFORCEMENT
DIVISION OF
INSPECTION
PROGRAMS
Report Nos.:
50-250/85-32
and 50-251/85-32
Licensee:
Florida Power and Light Company
9250 West Flagler Street
Miami,
FL
33101
Docket Nos.:
50-250 and 50-251
License Nos.:
and
Facility Name: Turkey Point
3 and
4
Inspection
Conducted:
August 26 - September
13,
1985
Inspectors:
L. J.
C
n, Chic
, Performance
Appraisal
Secti
, Team
eader,
D. Smith, Inspection Specialist,
. Martin, Inspection
Specia ist,
irs
We
)
M. B.
ymlock, Seni
Resident Inspector,
Regi
n II
R.
E.
chitzel, Seni r Inspection
Specia ist,
( irst Week)
/0
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ate
/O
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D te
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Da
e
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Date
yd /
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C.
G.
Wa enga,
spection
Specia ist,
r
(
e ond
We k)
G.
W.
r is,
NRC Cons
tant,
Westec
Date
/o
g
Date
Date
Approved by:
~ '~M
'P i
sp
F.
c ee,
se
,
Operating
Reactor
Programs
Branch,
(oer /8 v
r
85101502kB, 881001
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ADOCK 05000Q50
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h
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~
SCOPE:
This special
announced
team inspection involved 637 inspection
hours
assessing
the operational
readiness
of the auxiliary feedwater
system.
RESULTS:
The licensee's
operational
readiness
and management
controls
as
they relate to the auxiliary feedwater
system were reviewed in six
functional areas.
The functional areas
reviewed were:
Maintenance
Operations
Surveillance
guality Assurance
Training
Design
Changes
and Modification
Additionally, 10 potential
enforcement findings were
presented
to the
NRC Region II office as Unresolved
Items for
followup.
I.
Ins ection Ob'ective
The objective of the team inspection at Turkey Point was to assess
the
operational
readiness
of the auxiliary feedwater
(AFW) system.
This
assessment
included
a determination of the following:
capability of the system to perform the safety functions required
by
its design basis;
adequacy of testing to demonstrate
that the system would perform all
of the safety functio'ns required;
adequacy of system maintenance
(with emphasis
on pumps
and valves) to
ensure
system operability under postulated
accident conditions;
adequacy of operator
and maintenance
technician training to ensure
proper operations
and maintenance
of the system;
adequacy of human factors considerations
relative to the
AFW system
(e.g., accessibility
and labelling of valves)
and the system's
supporting procedures
to ensure
proper system operation
under normal
and accident co'nditions.
II.
Summar
of Si nificant Ins ection Findin s
Section III of this report provides the detailed inspection findings
pertaining to each functional area evaluated.
The safety effects of the
more significant findings on the operational
readiness
of Turkey Point's
(AFW) system are summarized
below.
Safet
Effects
on the Auxiliar
S stem
A.
The
NRC inspection
team identified safety concerns
regarding the
ability of the
AFW system to perform its safety function in the event
of a loss of non-safety
grade instrument air.
Loss of the inst~ument
air supply to the air-operated
AFW flow control valves is an assump-
tion in the
AFW system design basis fot most analyzed
accidents
involving AFW.
To ensure that the flow control valves,
and thereby
the entire
AFW system,
continue to operate in such events,
a safety-
grade nitrogen backup system is provided.
The team determined that
this backup nitrogen system
had never
been functionallytested,
eve'n
though this system
had been substantially modified as recently as
early 1984.
The licensee
had based its procedures
and operator
training on the assumption that 15-20 minutes
were available for
operators
to take necessary
action to establish additional nitrogen
capacity
upon depletion of the first nitrogen bottle.
This would be
accomplished
by valving in additional nitrogen bottles in the event
of a loss of instrument air to the flow control valves
(FCVs).
Control
room operators
would be alerted to take action by annunciator
alarms in the control
room that indicate that the on-line nitrogen
bottles for each of four trains
(two trains per unit) had reached
a
low pressure
condition of 500 psig.
As
a result of NRC c'oncern
during this inspection,
the licensee
tested all four trains of the
nitrogen backup supply to the
This test demonstrated
that
from the time the low nitrogen pressure
annunciator alarmed,
only 6
to 7 minutes (instead of the expected
15-20 minutes) would be avail-
able in the most limiting case
(FCVs remaining in automatic
mode).
The team further determined that correct operator
response
to
a low
nitrogen pressure
annunciator for train
1 would have
been
hampered
by
the incorrect information in the annunciator
response
procedure,
Procedure
0208.11,
which directed the operator to ignore tbe alarm if
all three train
1 nitrogen bottles were in service.
Additionally, a
review of recent design
changes
to the
AFW system indicated that the
low nitrogen pressure
alarm setpoint
had been
reduced in
March 1984 from its original setpoint of 1000 psig to the current 500
psig.
This resulted in a significant reduction in the available time
for operator
response.
The design
change
was also performed without
an adequate
safety evaluation.
The team concluded that the weaknesses
identified above in operator
training, inadequate
procedures,
the failure to functionally test the
nitrogen backup system,
and the apparent
non-conservative
setpoint
for the low nitrogen pressure
alarm could have all contributed to a
significant risk of a, loss of AFW flow.
Specifically, the team
concluded that there
was inadequate
assurance
that the control
room
operators
would take the required actions to maintain
AFW flow within
the 6 or 7 minutes that would potential-ly be available
once the
nitrogen low pressure
alarm was received.
The team noted
that the operators'raining
and procedural
guidance
could have
provided
a false assurance
that at least
15-20 minutes
were
available.
The team
was also concerned that,
even if operators
had
been correctly trained and had adequate
procedures,
the existing low
nitrogen pressure
setpoint of 500 psig might be too low to allow for
a reasonable
response
time for operators
to valve in standby nitrogen
bottles.
Several
operators
expressed
the consensus
that at least
IO-15 minutes should
be available to ensure
necessary
actions could
be taken.
B.
The team identified a safety concern regarding the ability of the
AFW system to perform its safety function in the event of certain
two-unit trip scenarios.
The
AFW system design description
and
design basis required that 286 gpm be supplied to each unit within 3
minutes in the event of a two-unit trip and stated that operator
action would likely be required to assure
correct flow distribution
to each unit if only one
AFW pump were available.
Specifically, the
AFW system is arranged
into two trains,
and any one train is required
by the design criteria to supply both units.
Train 2 contains only
one of the three
AFW pumps.
Consequently,
on the loss of train I,
the single
pump in train
2 is required to supply both units.
The
team determined that the control
room operators
had not been trained
for this eventuality.
In addition, the applicable
emergency
operating
procedures,
such
as
EOP 20004,
"Loss of Offsite Power," and
20007, "Total Loss of AC," made
no mention of the need to provide
a
minimum of 286
gpm to each unit within three minutes.
Without the
requisite training and procedural
support,
the team lacked confidence
that correct operator action would be taken to ensure
adequate
flow to each unit in the event of a two-unit trip with only train
2
of AFW available.
This becomes particularly important if one of the
units provided less flow resistance
to AFW, such
as would be the case
C.
pressures
of one unit were lower than the other
unit.
The inspection
team identified a safety concern regarding the ability
of the on-shift operators
to isolate
steam flow paths to the
environment from the affected
in the event of a steam
generator
tube rupture.
Emergency Operating
Procedure
20003,
"Steam
Generator
Tube Rupture," directed the control
room operators
to
isolate the steam supply from the affected
to the
turbines
by shutting the associated
motor-operated
isolation valves
using the hand switches in the control room.
The inspection
team
determined that the
AFW turbine steam supply isolation valves could
not be remotely shut from the control
room if there
was
an
actuation signal present.
The team identified that the steam supply
isolation valves were designed
to cycle open if an
AFW actuation
signal were present,
even if the control
room handswitches
were held
in the "close" position.
The licensee
had not recognized this design
feature.
Therefore,
the licensee
had not provided operator training
or adequate
procedures
to ensure that alternate
means
were taken to
isolate the
AFW steam supply from the affected
The
team concluded that the lack of operator
awareness
that the steam
flowpaths in question could not be isolated remotely from the control
room could have resulted in an unnecessary
and
potentially signi-
ficant radioactive release
to the environment following a steam
, generator
tube rupture.
A significant amount of time could have
been
required for the control
room operators
to first identify that the
steam supply isolation valve would not remain shut and then take
appropriate
compensatory
actions.
Effects
on Other Safet
S stems
In addition to the specific safety concerns
discussed
above that relate
directly to the operational
readiness
of the
AFW systems
the team also
identified several
general
concerns that have the potential to affect the
proper operation of other safety systems.
A.
Problems
were noted in the Turkey Point maintenance
program.
Program-
matic weaknesses
affecting quality of corrective
and preventive main-
tenance
performed
on Turkey Point safety systems
included:
The maintenance
department
had experienced
a high turnover
rate
among maintenance
technicians
which resulted in a shortage
of experienced
personnel.
The Instrumentation
and Controls
( I&C) section
was the hardest hit:
at the time of the
inspection
over half (15 of 27) of the
I8C technicians
performing surveillance testing
had and average of less
than
6$ months experience
at Turkey Point.
Maintenance
technician training had not been
conducted
since August 1984.
Management controls did not exist to ensure that safety-related
maintenance activities were performed
by qualified personnel.
On-the-job training (OJT) records or other forms of
qualification documentation
were not used
by maintenance
supervisors
as
a basis for work assignments.
Maintenance
procedures
generally lacked detail.
Complex
safety-related
maintenance activities were often considered to
be within the scope of the "skill of the trade",
and therefore
not requiring procedures.
The shortage of experienced
technicians
and lack of training referred to above
do not appear
to justify the widespread
use of "skill,of the trade"
as
a
substitute for detailed procedures.
Post-maintenance
testing requirements
were typically not
included
as part of electrical
and
IKC Plant Work Orders.
Further,
documentation of completed post-maintenance
tests for
electrical
and
IEC maintenance
were typically not pa'rt of the
retained maintenance
records.
Interviews with maintenance
department
supervisory
personnel
indi-
cated that the above maintenance
problems could have contributed to
the large backlog of safety-related
Plant Work Orders
(PWOs)
throughout both units.
This backlog was of particular concern to the
team as it applied to degraded
and malfunctioning control
room
instrumentation.
For example:
The ability of the control
room operators
to diagnose
a
tube leak was degraded
by the fact that the
steam jet air ejector process
radiation monitors
had been out of
.
service for about six months.
The Unit 4 containment
sump high level annunciator
had been
out of service since
December
1984 due to a failed level switch.
Two of the four post-accident
monitors for containment
level for Unit 4 had
been out of service since
February
1985.
A Unit 3 safety injection accumulator Hi/Lo pressure
and
Hi/Lo level annunciators
were in an alarmed condition although
the associated
pressure
and level instruments
read within their
normal bands.
Several
area radiation monitors
on both units were out of
service.
Some of the monitors
had been out of service for
greater than'six months.
AFW system nitrogen backup supply low pressure
for nitrogen station
No.
2 were alarmed
on both units.
station
No.
2 had been
removed from service since January
1985
as
a result of a design
change.
The team considers this
a
concern
because
the alarmed nitrogen low pressure
were located adjacent
to the low nitrogen pressure
for stations
1 and
4 and thereby could degrade
the operator's
reaction time to a valid low nitrogen pressure
alarm.
Since very
little reaction time may be available
(as little as
6 to 7
minutes) to take action to maintain
AFW flow once the low
nitrogen pressure
alarm is received,
the potential for confusion
caused
by the spurious
alarms is considered significant.
- 4.-
Both units had leaking power operated relief valves
(PORVs).
In addition, the isolation valves (block valves) for
the Unit 4
PORVs leaked
and this resulted in elevated
temperatures
downstream of the Unit 4 pressurizer
safety relief.
valves
(which share
common discharge
piping with the
PORVs).
As
a result, control
room annunciators
were alarmed, for all three
Unit 4 pressurizer
downstream
temperature
elements.
This condition is significant because it could
degrade
the control
room operators'bility to identify a lifted
safety relief valve or the failure of a
PORV to reseat.
B.
Problems were noted in the Turkey Point design
change
process.
Programmatic
weaknesses
identified by the team that affect the ade-
quacy of the design
changes
and modifications to safety-related
systems
include:
The engineering
group often did not provide post-modification
testing requirements
to confirm the adequacy of the installation
to the design basis.
The team identified instances
where modifications were
installed without a detailed design analysis.
The licensee
was
found to frequently base
design
changes
on engineering
judgement
that the new design
was bounded
by the original design analysis.
Documentation justifying the engineering
judgement typically did
not exist.
Design bases for safety-related
systems
were difficult to re-
trieve.
In the absence of readily available
design
bases for
many safety-related
systems,
the team is concerned that
excessive
reliance could be placed
on engineering
judgement for
implementing design
changes
and for performing safety evalua-
tions required by 10 CFR 50.59.
The team concluded that the above
programmatic
weaknesses
in the
design
change
process potentially contributed to the following
examples of inadequate
design analysis
and design
change
implementation:
Four of six AFM system
steam supply isolation valve motor
operators
were changed
from AC to
DC motors without adequate
design analysis.
Motor overload protection for the
new
motors
was not properly sized.
Further,
the
new power cables
were not properly sized to ensure
adequate
operating voltage for
the motor operators
in the event of a loss of offsite power.
The licensee
had not performed any cable sizing calculations
to
support this design
change.
The design
change to the
AFW system to provide redundant Train A
and Train
B flow control introduced the potential for common
mode failure due to control circuits from both trains
coming to
common limit switches
and
common relays.
The design
change to provide redundant
nitrogen backup
systems
-5-
to supply Train A and Train
B AFW system flow control valves
introduced
a potential for common
mode failure in the redundant
control
room annunciator circuits.
As discussed
later in this
report, the loss of these
redundant
could lead to a
loss of AFW.
Several
problems
were identified with the modification involving
the replacement of the Unit 3 and Unit 4 safety-related
station
batteries:
no calculation
was available to substantiate
the
one
hour battery discharge profile contained in the design
specification; the factory acceptance
test failed to adequately
demonstrate
the batteries
could meet the design basis profile;
and plant procedures
and Technical Specifications
surveillance
requirements failed to recognize
the existence of the
new
battery requirements
required
by the substitution of GNB
lead-calcium batteries for the old C&D lead-acid batteries.
The
AFW system
was modified to install
a redundant
solenoid
operated
steam vent valve.
Design analysis
does not exist to
document the selection of 150 psig setpoint selection for the
pressure
switches that are used to control operation of the
valves.
The team is concerned that the
150 psig setpoint would
permit the valve to open automatically before plant cooldown
could be transferred
to the residual
heat removal
system.
The design
change to install
a redundant safety-related
conden-
sate storage
tank low level alarm introduced
a potential for an
undetected
common
mode failure.
This failure would have
been
caused
by closing
a normally open manual isolation valve.
In
addition, this valve was not administratively controlled.
The
design calculation to establish
the setpoint for the low level
alarm did not identify all the assumptions
and design inputs
used to perform the calculation.
In particular, there
was
no
evidence that the calculation considered
the net positive
suction
head
(NPSH) required to maintain
AFW pump operation.
A design analysis
did not exist to document the setpoint
selection
(500 psig) for the
AFW system nitrogen backup supply
pressure
switches.
Engineering did not provide post-
modification testing requirements,
and,
as
a result,
the
nitrogen backup system
was never adequately
tested.
The
electrical
and
I&C equipment associated
with the nitrogen
system
were not identified as safety-related
in the Turkey Point
g-List, and as
a consequence
were not being treated
as
safety-related
by the electrical
and
I&C maintenance
technicians.
III. Detailed Ins ection Findin
s
A.
MAINTENANCE
A significant weakness
noted in the Turkey Point maintenance
program
was the consistent failure to evaluate
the root cause of
equipment malfunctions
and to trend these failures to provide
input to the preventive maintenance
program.
The Plant Work
-6-
Order
(PWO) form was used to document the performance of
maintenance.
A section of this form was provided to describe
the cause or reason for the trouble found.
A review of several
hundred completed
PWO forms revealed that the cause of the
associated
equipment failure was not described
in most cases.
Interviews with maintenance
supervisory personnel
revealed that
the cause of equipment failures and the consideration of the
recur rent nature of failures are tracked informally by relying
upon the memory of maintenance
supervisors.
The equipment
history records
were not being kept current in the electrical
and mechanical
areas.
Specific examples of failures to evaluate
root causes
of equipment failures are discussed
below:
A review of the maintenance
history records,
including
PWOs
and Licensee
Event Reports
(LERs) for the auxiliary
(AFW) system,
revealed
several
component
failures of a recurrent nature.
These included seven
separate
examples,
since January
1984, of failure of an
air-operated
AFW flow control valve to properly function "
due to water or foreign material in the instrument air
system.
In 1983,
on two separate
occasions,
two of the six AFW
steam supply motor operated
valves
(MOVs) failed to open
because
of carbon build-up on the motor operator limit
switches.
A review of the maintenance
records for the
remaining four AFW steam supply
MOVs revealed that, despite
the recent failures described
above,
one
had not been electrically cleaned
and inspected
since
1979.
Additional weaknesses
associated
with maintenance
on MOVs
are discussed
in Maintenance
Observations
2 and 3.
2.
A review of the maintenance activities performed
on
indicated weaknesses
in training for repair of these valves.
Interviews with supervisory maintenance
personnel
revealed that
no training had been
conducted in either the mechanical
or
electrical
areas
covering repair of MOVs with the exception of
undocumented,
on-the-job
training and pre-maintenance
briefings.
A mock-up of a Limitorque valve operator
was
available in the training department offices but apparently
had
not been
used to train maintenance
personnel.
3.
Mechanical
maintenance
personnel
were uncertain
regarding the
type of grease
to be used in MOV gearboxes.
This was considered
a problem for two reasons.
First, the mixing of different types
of grease
in the gearbox
could cause
hardening or separation
of
the lubricant.
The potential for this exists at Turkey Point
because its preventive maintenance
instructions for Limitorque
gearboxes
specify the use of Texaco Marfac, while these
same
Limitorques have
been supplied with either Exxon Nebula
EPO or
EPI or Sun
50
EP lubricants.
Secondly,
the only Limitorque
lubricant that meets
the environmental qualification
. requirements
of 10 CFR 50.49 at Turkey Point- is Exxon Nebula
EPO
or EPI.
A program to address
these
concerns
was in progress
and
scheduled for completion
by December
1986.
The progress of this
effort will remain
an inspector followup item (50-250/8532-1;
50-251/8532-1).
4.
The licensee
has recently taken steps
to improve
reliability.
Temporary Operating
Procedure
166 was issued in
May 1985 and provide detailed instructions for troubleshooting
and repair of MOVs, including limit switches,
torque switches,
and post-maintenance
testing.
This procedure
provides specific
torque switch settings for safety-related
motor-operated
valves
and required that, during maintenance,
proper torque switch
settings
be verified by an electrical quality control inspector.
Discussions with management
representatives
revealed that the
licensee
was in the process of purchasing
new MOV test equipment
to use in improving the reliability of the MOVs.
5.
- A review of calibration records
revealed that the low pressure
alarms for the
AFW nitrogen system were not routinely calibrated
(see
Design
Changes
and Modifications Observation
5.c for
further discussion).
A search of calibration records with the
assistance
of an
IEC supervisor
revealed. that the most recent
calibration records for two of the nitrogen supply low pressure
alarm pressure
switches
(PS 2322 and
PS 2323) were dated
June
14,
1978.
In addition,
no procedure
was available for the
calibration of these alarms.
The apparent failure to establish
and implement procedures
for the calibration of the
system low pressure
alarms
was discussed
with the licensee
and
will remain unresolved
pending followup by the
NRC Region II
Office (50-250/8532-2;
50-251/8532-2).
Due to this identified concern,
the licensee
issued
PWOs 8349
and 8350 to calibrate all four nitrogen system pressure
switches.
These calibrations
were performed
on September
9,
1985.
6.
The control
and documentation of 'sampled
post-maintenance
testing
was found to be weak.
In many cases,
neither the
post-maintenance
testing instructions nor the results of the
testing were documented
on the
PWO.
This was particularly
evident for 18C and electrical
maintenance activities.
However,
for mechanical
maintenance activities, Administrative Procedure
(AP) 0190.28,
"Post Maintenance Test Control," was.specified
on
the
PWO in most cases.
This procedure
described
most of the
testing considered
adequate
by the licensee to return mechanical
systems
to an operable status
and also provided
a form to docu-
ment the test results
as
an attachment
to the
PWO.
The apparent failure to provide adequate
instructions for
post-maintenance
testing
on some
PWOs appears
to be contrary to
AP 0190.19,
"Conduct of Maintenance
on Nuclear Safety Related
and Fire Protection
Systems,"
was discussed
with the licensee,
and will remain unresolved
pending followup by the
NRC Region II
Office (50-250/8532-3;
50-251/8532-3).
7.
A weakness
was noted in the program to return instruments
properly to service following maintenance
or calibration while
-8-
the plant was operating.
The licensee
had
a program for provid-
ing general
assurance
that instruments
inside and outside the
containment
were properly aligned
when the plant was returned to
operation
from an outage condition.
The procedures
describing
the instruments to be checked,
O-SMI-059.1 and O-SMI-059.2, were
considered
adequate,
providing a place for first and second
check verification for each applicable instrument.
However,
interviews with I8C supervisory
personnel
revealed that these
procedures
wou1d normally be used only to verify instrument
alignment at the end of an outage condition.
Instrument
line-ups were not required
by the licensee to be independently
verified following maintenance
or calibration while the plant is
in an operating status.
8.
A sample of maintenance
procedures
indicated that many complex
maintenance activities were accomplished without detailed,
step-by-step
procedures.
Instead,
these
complex activities were
considered
to be "skill of the trade".
The team considers
the
licensee's
frequent reliance
on individual skills of maintenance
technicians
as
a substitute for detailed procedures
to be
unjustified in view of the limited training provided to
maintenance
technicians
and the high turnover rate
among
maintenance
personnel.
(See Maintenance
Observations
10 and 11.)
.
9.
A backlog of approximately
900
PWOs existed in the I5C section.
Included in this backlog of PWOs were
a number affecting control
room instruments.
The team considers that any degraded
condition of these
instruments
could hamper the
operators'bility
to diagnose
and respond to abnormal plant conditions.
Examples of instruments that fit into this category were:
Unit 3 Steam Jet Air Ejector
(SJAE) Process
Monitor had
been out-of-service
(OOS) since
February
13,
1985,
and the
Unit 4 SJAE Process
Monitor Cabinet
had been pulled from
the control
room for maintenance for approximately
6
months.
The SJAE Process
Mo'nitors are used to monitor
radioactivity in the steam exhausted
to the main condenser
and are
an important diagnostic tool for identifying a
primary-to-secondary
leak.
At the time of the inspection,
the
SJAE exhaust
gas radioactivity was being recorded
by a
backup
(SPING) system that
had
no control
room indications
or alarms.
The readout of the
SPING system
was checked
by
the chemistry department
every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
The Unit 4 Containment
Sump High Level Annunciator
had been
OOS since
December 6, 1984.
The cause
was determined
to be
an inoperable
level switch, LS-1538.
The containment
pump handswitches
(labelled
"Off-Auto-Run") were in the "Off" position for both units.
This was
done
because
the
pumps would not cut off auto-
matically when
sump level
was
pumped
down if the switches
were left in "Auto" as designed.
-9-
Two of the four accident monitors for Unit 4 containment
sump level indication, which are used to determine the
level during a Loss-of-Coolant Accident (LOCA), had been
OOS since February 7, 1985.
The Hi/Low Pressure
Annunciator and Hi/Low Level
Annunciator for one of three Unit 3 Safety Injection
Accumulators were in an alarmed condition.
Area Radiation Monitors on both units
had many
PWO tags
which had been in place for extended
periods.
Some of
these monitors were in degraded
conditions for greater
than
6 months.
This reduced
the operators'bility to diagnose
abnormal plant conditions
and also increased
the
possibility of personnel
exposure.
The
number
2 low pressure
were alarmed
on both units.
These annunci-
.,
ators
were used to indicate
low nitrogen supply to the
differential pressure
transmitters,
which had been
disconnected
since January
1985.
Further,
these
were located beside
the
station I and station
4 low pressure
and
therefore
could potentially degrade
the control
room
operators'bility to distinguish
a valid low nitrogen
supply pressure
condition (see Operations
and Surveillance
Observation l.a and I.b for further discussion).
10.
Interviews with maintenance
supervisors
and training personnel
indicated that formal classroom training sessions
for
maintenance
technicians
had been discontinued
in August 1984.
Licensee
management
stated that maintenance
training had been
discontinued to dedicate training resources
to developing
training materials
required to support Institute of Nuclear
Power Operations
(INPO) accreditation. of the maintenance
training program.
The licensee
stated that this decision
was
necessary
in order to meet the
INPO accreditation Self
Evaluation Report submittal date of February
1986.
Additionally, a review of maintenance
training records
indicated
that
a very limited amount of on-the-job
(OJT) training and
vendor supplied training had been conducted
since the decision
to discontinue
classroom training.
The team concluded that maintenance
training being conducted did
not appear
adequate
to maintain staff proficiency and to train
new personnel,
particularly in view of the high turnover rates
experienced
by the maintenance staff (see Maintenance
Observation
11 of this section).
11.
Review of training records
and interviews with training and
maintenance
supervisors
raised
the following concerns:
Over half of the
ISC technicians
that conduct surveillance
tests
( 15 of 27 at the time of the inspection)
had
an
- 10-
average of less
than 6.5 months of experience
at Turkey
Point.
The electrical
and mechanical
maintenance
groups
had also recently experienced
high turnover rates
among
their technicians,
but not to the degree of the
18C group,
The licensee's
management
controls for safety-related
maintenance
work assignments
were considered
weak.
Maintenance
supervisors
relied on their knowledge of each
technician's abilities and experience for work assignments.
OJT records or other forms of qualification documentation
were not used to assure that only properly qualified
personnel
were assigned safety-related
maintenance
activities ~
B.
0 erations
and Surveillance
1.
The procedures for normal
and emergency operation of the
system were evaluated
as weak, with numerous
instances
of incorrect information that could result in degraded
AFW system operation.
For example:
a ~
b.
Procedure
0208.11,
"Off-Normal Operating Procedure,"
stated
that in the event of a low hitrogen pressure
alarm the standby nitrogen bottle should
be valved in.
However, in the case of the train
1 nitrogen system,
the
procedure states
that if all three available nitrogen
bottles are valved in, the operators
were to ignore the
alarm.
To ignore the annunciator
alarm in that instance
could quickly lead to a loss of sufficient nitrogen
pressure
to operate
the train
1
AFW flow.
The licensee
informed the team that this procedural
inadequacy
would be
corrected
on a priority basis.
This item will remain
an
inspector
followup item pending confirmation of the
licensee's
corrective actions
(50-250/8532-4;
50-251/-
8532-4).
Additionally, this procedure
did not alert the
operator to the fact that very limited time might be
available to take corrective action, nor did the procedure
advise the operators
to conserve
nitrogen pressure
by
shifting AFW flow control valve operation
from automatic to
manual.
The team determined that confusing
and incorrect
information was available to control
room operators
regarding the capacity of the
'Procedure
7300.2.
"AFW System
Flow Control Valves
Instrument Air/Nitrogen Backup System Operation," states
the operators
have
15 minutes to valve in standby nitrogen
bottles after the low nitrogen pressure
alarms.
However, licensed operators
were trained in their ongoing
requalification training program that they have
20 minutes
to take action (reference:
Training Brief f9, dated
March
1, 1984).
The
AFW system description
and design basis
states
that only 10 minutes
are avai'table for the operators
to take action.
At the request of the
NRC, the licensee
performed
a functional test of the nitrogen backup
system
- 11-
c ~
d.
during this inspection period.
The test results indicated
that, in fact, operators
had as little as six minutes (with
the flow control valves in auto) to take action to avoid
the loss of AFW due to a loss of nitrogen pressure.
Because of the inadequate
operator training and incorrect
procedural
information available,
the team lacked assurance
that appropriate
operator action would be taken
1n the
event of a low nitrogen pressure
alarm
following a loss of instrument air.
Emergency operating
procedures
did not provide adequate
guidance to control
room operators
to assure
that adequate
AFW flow (286 gpm) would be provided to each unit within 3
minutes,
as required
by the
AFW design basis,
in the event
of a two-unit trip with only one
AFW pump available.
20004,
"Loss of Offsite Power," and
EOP 20007, "Total Loss
of AC," made
no mention of the need for timely operator
action to balance flow between
the units in this instance.
EOP 20003 (E-3), "Steam Generator
Tube Rupture," dated
December 20,
1984, provided incorrect information to the
control
room operators
regarding
how to isolate the steam
supply to the
AFW turbines from the affected
steam
generator.
Specifically,
EOP 20003 directed the control
room operators
to isolate the steam supply from the
affected
by shutting the associated
motor-operated
isolation valve using the handswitch in the
control
room.
However, the inspection
team determined that
these
AFW isolation valves could not be remotely shut from
the control
room if there
was
an
AFW actuation signal
present
(see
Design
Changes
and Modifications Observation
5.c for further details).
The licensee
had not recognized
this design feature
and therefore
had not provided operator
training or procedures
to ensure that alternate
methods
were available to isolate the
AFW steam supply from the
affected steam generator
in the event of a tube rupture.
The licensee
stated that the affected
EOPs would be
corrected
on a priority basis.
Further, the licensee
provided training to all on-coming control
room operators
regarding this matter.
This item will remain
an inspector
followup item (50-250/8532-5;
50-251/8532-5).
2.
During a system walkdown of the auxiliary feedwater
supply and
steam
systems,
as described
in piping
and instrument drawings 5610-T-E-4062,
Rev. 33, and
5610-T-E-4061,
Rev. 6, the following observations
were noted:
turbine casing
and exhaust silencer drain valves 328, 329,
331 and 332 were missing their associated
handwheels;
local pressure
instruments
(PI) 1416,
1417,
and
1418 had an
additional isolation valve not shown
on the drawing;
- 12-
feed flow transmitter
3-1401B was marked 4-1401B and
one
isolation valve, 3-002,
was not tagged;
feed flow
transmitter 3-1457B had an isolation valve, 3-003, not
tagged;
the following valves
had
no identification tags:
3-012,
RV-6401A, AFWU-010)70-102,
AFWU-011,70-103)
AFWU-012,70-104,
and isolation valves
on PI-1430, PI-1431;
a flexible hose
was supplied from the backup service water
system through Aeroquip quick disconnect fittings to supply
backup
AFW pump cooling water.
Debris
was noted in the
hose for the "A" pump.
There
was
no control for either the
male or female fittings;
all the valves for nitrogen station
No. 4 were mislabelled
as station
No. I valves;
three nitrogen bottles in each nitrogen station
(No. I and
No. 4) had "empty" tags
on them.
When questioned
by the
inspector,
the licensee
determined that the bottles were,
in fact, full;
the licensee
had not established
contingency measures
to
ensure that replacement
nitrogen bottles could be made
available
on backshifts.
This issue
was significant
because
only about
3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of nitrogen is available at the
nitrogen stations,
so several
replacement
nitrogen bottles
would be required to operate
the
AFW system long enough to
cool
down the units to allow for residual
heat
removal
operation.
The
AFW system walkdown revealed that replace-
ment nitrogen bottles were not readily available.
3.
A review of "Auxiliary Feedwater Train I Operability Verifica-
tion," Procedure
3-OSP-075. I, dated August 7, 1985, identified
that it did not adequately verify the operability of AFW steam
supply
HOVs 3-1404
and 3-1405.
Limit switches
located in these
valves are used to control associated
flow control valves in the
feedwater lines.
When either of the
MOVs opens, all flow
control valves in trains I and
2 open to assure
a feedwater flow
path.
However, procedure
3-0SP-075.1
required opening both of
these
steam supply valves together.
Therefore,
each of the
was not independently verified capable of opening all the flow
control valves
as designed.
4.
The team considers
local control of train 2 AFW valves to be
virtually impossible.
Off-Normal Operating Procedure
0208.17,
"Control
Room Inaccessibility," dated
Nay 24,
1985, would be
used to take local feedwater
control in the event of a control
room evacuation.
This procedure
has
no guidance for local con-
trol of train 2 AFW valves.
Additionally, it appeared
that
operation of this train would be difficult because
the valves
are located under the feedwater platforms
and all indications
for train
2 are located
on the platform area.
- 13-
The team's
concern
regarding the ability of the licensee
to
safely shut
down the plant in the event of control
room inac-
cessibility was reinforced
by the observation that the licensed
operator requalification program did not include drills or plant
walkthroughs to simulate local control of essential
safety
systems.
This is considered
a weakness
at Turkey Point for two
reasons.
First, Turkey Point does not have
a safe
shutdown
panel outside the control
room that would provide
a central
location for essential
instrumentation
and control.
Second,
less
than
a quarter of the licensed control
room operators
had
previously been
a watchstander
outside the control
room; there-
foree,
the majority were not as familiar with local equipment
operation.
5.
The team noted the following concerns with the condition of the
auxiliary feed
pump turbines
and their associated
steam supply
system.
a.
During a system walkdown, the drain lines on the turbine
casings
and the exhaust silencers
were noted to be hot.
Water
was flowing from the drains
on the A and
C turbines.
The steam supply isolation valves for the
A and
C turbines
were leaking and allowing steam to reach the turbines
even
though the valves were closed
(MOV-3-1404, NOV-3-1405).
A
review of the valves'aintenance
history revealed that
these
valves
had been
reworked several
times.
However, it
did not appear that the problem had been resolved.
The
associated
steam supply valves
on Unit 4 also appeared
to
be leaking.
It should
be noted that the
B turbine did not
appear to have any leakage
from its steam supply valves
(NOV-3-1403 and HOV-4-1403).
During this inspection
period,
no current
PWOs were noted
on the leaking steam
supply valves.
b.
The steam supply vent system did not appear to be
functioning properly in that the vent valves were open but
only a small amount of steam
was being vented.
Further,
a
substantial
amount of steam
appeared
to be reaching
the
turbines
based
on the condensate
flow from the casing
and
silencer drains
and the elevated
temperature of the exhaust
stack.
The team identified that one of the vent valves
on
Unit 3 was failed shut
on September
11,
1985.
The licensee
promptly corrected this problem.
6.
It was noted during walkdowns of the auxiliary feedwater
system
that the seismic qualification of portions of the system
was not
being proper ly maintained;
The following observations
were
noted: control air lines going to CV-3-2816 were attached
to
their tubing tray but the tray was not attached to the floor for
several feet; nitrogen instrument lines were noted to go
underground to transit from one location to another;
and
nitrogen bottles stored at nitrogen station
No. I were not
adequately
restrained.
- 14-
It was noted also that temporary scaffolding was in place above
all four instrument racks for Unit 3 and
flow transmitters.
In addition,
a leg of one of these scaffolds
was installed adjacent to the Unit 3 train 2 auxiliary feedwater
instrument rack right between
two of the flow transmitters.
The
failure of non-seismic
components
(scaffolding) could cause
the
failure of safety-related
AFW components
with the resultant
common
mode failure of all auxiliary feedwater flow to both
units.
This item will remain unresolved
pending .followup by the Region
II Office (50-250/8532-6;
50-251/8532-6).
7.
Procedure
4-0SP-075.3,
"AFW Nitrogen Backup System Operability
Verification," was reviewed by the team.
This procedure
did not
appear
adequate
to functionally test the nitrogen backup system
as it only tested
the operability of the system during static
conditions.
The test did not demonstrate
that the nitrogen
backup system would function properly in its design basis
mode
of supplying the
AFW flow control valves with the valves in
automatic.
8.
The differential pressure
transmitters
on the discharge of each
AFW pump were disconnected
in January
1985 in accordance
with
Procedure
0103.3,
"Control and
Use of Temporary System
Alterations."
This procedure
required that
a
safety evaluation
be written and the alteration
be reviewed
and
approved
by the Plant Nuclear Safety Committee
(PNSC).
The
Temporary System Alteration for disconnecting
these differential
pressure
transmitters
included neither
a
10. CFR 50.59 safety
evaluation
nor
PNSC approval.
This item will remain unresolved
pending followup by the Region II Office (50-250/8532-7;
50-251/8532-7).
C.
Oesi
n Chan
es
and Modifications
1.
Plant Change/Modification
(PC/M) 80-77 was reviewed by the team.
This modification package installed redundant
instrument strin9s
to provide safety related
condensate
storage
tank level
indication and .an alarm 20 minutes prior to needing another
source of water for the auxiliary feedwater
pumps.
The team
determined that the implementation of this design
change failed
to ensure that it met the single failure criteria.
Specifically,
an operator error to close
one manual isolation
valve (isolation valve 428) could have
caused
an undetected
'ommon mode failure of safety-related
condensate
storage
tank
level indication and alarm functions.
The level transmitters
for redundant
level indication are connected
to a
common
instrument tap from the condensate
storage
tank.
The
common
instrument tap has
a normally open isolation valve which could
be mistakenly closed
by an operator causing
co@non
mode failure
of the level instruments.
No valve position indication was
provided to alert the operator of incorrect valve position and
- 15-
no administrative controls
(such
as locking the valve open) were
applied to ensure that the valve remained
open.
As a result of the inspection concern,
the licensee
checked
open
isolation valve 428 and installed
a locking device.
Revision of
appropriate
valve lineup sheets
and plant drawings will also
be
required.
This item will remain
an inspector followup item
(50-250/8532-8)
50-251/8532-8).
2.
PC/8 80-117
was reviewed.
This modification added
redundant
steam supplies
to the auxiliary feedwater turbines.
The modi-
fication also replaced
the auxiliary feedwater flow control
valves.
Upon auxiliary feedwater initiation, six pneumatic flow
control valves per unit are automatically opened
and controlled
to supply
125
gpm through each valve.
The three auxiliary
pumps are aligned in a two train arrangement
with
turbine
pumps
A and
C assigned
to train
1 and turbine
pump
B to
train 2.
Three flow control valves are assigned
to each train
to provide auxiliary feedwater
flow to each of three
steam
generators.
Flow transmitters
immediately downstream of the
flow control valves monitor feedwater flow and provide feedback
to I/P converters
to alter control air pressure
to flow control
valve positioners.
Upon loss of instrument air these
valves are
designed to fail shut.
To prevent this from occurring the flow
control valves are provided with a safety-related
source of
bottled nitrogen to restore
the sources of motive and control
power for the flow control valves.
PC/Yi 80-117 also added six new flow control valves (three valves
per unit) and replaced
the actuators
on the six installed valves
(three actuators
per unit).
To accommodate
redundancy
in the
nitrogen system,
the existing nitrogen cylinders (five cylinders
per unit) were divided into two trains per unit.
This division
resulted in assigning
three nitrogen cylinders to train
1 and
two cylinders to train 2.
In each train, only one cylinder was
valved on-line.
During the team's
review of PC/N 80-117, the
design of the nitrogen system
was examined.
The following
observations
were made during the review of the modification
package.
a.
The implementation of the design control process for this
modification did not produce
a documented
analysis
substantiating
the design
adequacy of the nitrogen system.
The team found that
a design analysis
was not performed
by
Bechtel to confirm that the design
change
was acceptable.
The team was informed that Bechtel
reviewed the original
design analysis
and confirmed that the
new design
was
bounded
by that calculation in lieu of a new design
analysis.
No evidence existed
documenting this engineering
judgment.
The team was informed that the existing calcula-
tion was considered
bounding
because
the
new components
had
a lower nitrogen consumption rate.
The original design
analysis
was performed in 1972 and
had consumption
rates
for components
which existed in the original control
scheme
and which were subsequently
replaced with new components
by
-16-
PC/M 80-117.
The calculation
had
no indication of a check
or verification.
Likewise, the sources
and nature of the
consumption
rates
were not identified.
During the inspec-
tion, Bechtel could not determine if the values in the
1972
calculation represented
steady-state
conditions or consump-
tion rates reflecting
some assumption for valve modulation
and component
leakages.
Bechtel cited information from a
vendor technical
manual
which indicated that the-new valve
actuators
have
a lower steady-state
air usage
value of 0.26
scfm per valve, rather than the 1.0 scfm per valve used in
the existing calculation.
The valve actuators
are
diaphragm actuators
with a balance positioner constantly
exhausting air through
a detecting nozzle.
Bechtel pointed
out that only three actuators
are being supplied
by the one
nitrogen cylinder on line instead of six per the original
design.
Thus, Bechtel
concluded that the original design
analysis
bounded the
new design.
By inspection,
the team
could not arrive at the
same conclusion for the
following'easons:
The team determined that the steady-state
air usage
value of 0.26 scfm was based
upon
a vendor test of a
similar, but not identical valve positioner.
The
vendor test
was conducted with an air supply pressure
of 60 psi instead of the minimum nitrogen supply
pressure of 80 psi furnished by the installed nitrogen
system regulators at Turkey Point.
As a consequence,
the steady-state
air usage
value can
be expected to
increase.
During the inspection,
Bechtel indicated
that
a linear extrapolation
was
a reasonable
assumption.
Therefore,
the steady-state
consumption
rate approaches
0.36 scfm (i.e., increased
by a factor
of 80 psi/60 psi).
The assumption of instantaneous
steady-state
operations
does not appear
to be consistent with the
as-designed
valve response (i.e., upon actuation
the
valve cycles full open
and then closes
towards the
125
gpm flow setpoint).
The vendor's technical literature
indicates that high operating
speed is achieved with
virtually no overshoot
when approaching
the final plug
position.
Although a designer might choose to assume
a leak tight system with periodic testing to confirm
this assumption, it appears
unreasonable
to conclude
that no valve modulation is required
and that
a
steady-state
condition is reached
imnediately.
The
team
was informed that the operators typically take
the flow control valves out of automatic control
and
place
them in remote
manual control immediately after
an auxiliary feedwater flow to maintain steam
generator level.
The team was informed that this
operator action results in elimination of control
valve modulation except for the initial valve cycle.
However, the team determined that the operators
were
not required
by procedure
to take remote
manual
- 17-
control nor were the operators
directed to do so by
existing management
guidelines or training.
Consequently,
the team concluded that the licensee's
assumption that operators
would immediately take
remote manual control of the flow control valves
(and
thereby reduce
the valves'ir usage rate)
was
unjustified.
In addition, the team found no periodic
testing performed
on the nitrogen system to confirm
its leak tightness
and instead
observed
a system with
significant leakage rates.
The minimum available
volume of nitrogen is higher in
the original design analysis
than prescribed
in the
system design description.
Specifically, the original
design calculation
uses
a minimum volume based
upon
1005 psig in the cylinder, and the system description
indicates
a minimum volume based
upon 500 psig.
This
reduction can, in part,
be explained
by the reduction
in the assumed
time the operator
has available to
valve in a new nitrogen cylinder.
The original
analysis
was performed with a design basis of operator
action within 15 minutes of receiving
a low nitrogen
pressure
alarm, whereas,
the current system
description specifies
10 minutes.
This time reduction
does not appear to be based
on a documented
analysis
of the actions required of the operator to recognize
the alarm, analyze the appropriate
response,
send
another plant operator to the nitrogen cylinder and
valve in a second nitrogen cylindet
.
(See Operations
and Surveillance Observation I for further
discussion.)
The original nitrogen system design
bases
included
a
requirement that the stored
volume of nitrogen
be able
to permit system operation for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> assuming that
all five nitrogen cylinders were full.
A similar
requirement for the current system
does not appear to
be addressed.
This does not appear to be consistent
with the licensee's
comnitment to have at least
one
AFM system
pump and its associated
flow path
and
essential
instrumentation
capable of being operated
independent of any AC power source for at least
two
hours
(SER related to Amendment
No.
75 to operating
license
No.
DPR-31 and Amendment
No.
69 to facility
operating license
No. DPR-41).
b.
The team found that
a design analysis
did not exist to
document
the setpoint selection for pressure
switches
used
to alert the operator via control
room annunciation that
ten minutes of nitrogen remained before loss of motive and
control power to the
AFW flow control valves.
Instead
the
team was informed that the setpoint reduction from 1005
psig to 500 psig for the pressure
switches
was established
by testing performed under Temporary Procedure
085 on Parch
I, 1984.
This test appeared
to have
been
performed prior
- 18-
0
to the splitting of nitrogen system into two redundant
trains but after addition of the
new flow control valves
and actuators.
The test was performed with one nitrogen
control cylinder supplying all six flow control valves with
the valves in a full open position'.
Placing the valves in
a full open position causes
the air usage to be in a
steady-state
condition.
Because
the nitrogen pressure
decayed
the last 500 psig in 15 minutes, the low-pressure
alarm was set at 500 psig.
This setpoint
was selected
based
upon
a steady-state
test without consideration
of
instrument error and without compensation for that pressure
at which the flow control valve can
no longer modulate
(approximately
30 psig per manufacturer information).
The
issue is safety significant because
incorrect setpoint
selection could result in the premature
loss of nitrogen
pressure
and closure of all auxiliary flow control valves.
c.
The design verification process failed to ensure that
appropriate quality assurance
requirements
were specified
for nitrogen system
components.
Electrical
and
I5C
equipment associated
with the nitrogen system were not
identified as safety-related
in FP8L's g-List.
As a
consequence,
the pressure
switches
used to alert the
control
room operator of low nitrogen pressure
and the need
for immediate operator action were not being treated
as
safety-related
by the 'site
IEC group.
The AFM system design description identifies the
AFW system
as
an emergency
safeguards
system to prevent core
damage
in
the event of transients
such
as
a loss of normal feedwater
or a main steam line break.
The nitrogen system is
essential
to operation of the auxiliary feedwater flow
control valves and,
as such,
the nitrogen system serves
a
safety-related
function.
FPEL (}uality Instruction
JPE-g1-2.3A,
"Classification. Of Structures,
Systems
and
Components,"
indicated that the mechanical
equipment but
not the electrical
and instrumentation
and control
equipment associated
with the nitrogen system were
safety-related.
The team was informed that
a more detailed
component level g-List was being developed
and that this
list indicated the pressure
switches
were safety-related;
however, this list had not been
issued
from engineering at
the time of the inspection,
and the
IAC group was
unaware
that the safety classification for the pressure
switches
had changed.
It appears
that, contrary to the requirements
of ANSI
N45.2. 11Property "ANSI code" (as page type) with input value "ANSI</br></br>N45.2. 11" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process. Section 6.3, the design verification process for
the g-List and the design modification did not ensure that
equipment performing
a safety-related
function were
designed,
specified,
and maintained
commensurate
with that
function.
This item wi'll remain unresolved
pending
followup by the Region II Office (50-250/8532-9;
50'-251/8532-9).
-19-
0
d.
Implementation of the design
change
process for this
modification did not produce
a design analyses
to confirm
that non-safety
components of a system
do not adversely
affect the safety function of the system.
Although not
identified in the system design description
and design
bases
document for the auxiliary system,
steam vent valves
were provided to vent steam
when the system is not
operating.
The valves are signaled to close
on increasing
steam pressure
(increasing
steam pressure
indicates that
system
has initiated) and to open
upon
decreasing
pressure
to vent the steam lines between
the
steam admission
valves
and the auxiliary feedwater
pump
turbines.
The steam vent valves are outside of the seismic
boundary
and are treated
as non-safety-related.
In
reviewing
PC/M 80-117 this design feature
was examined
and
the following observations
were made.
Design analysis
does not exist to document the
consequence
of a failure of the vent valves to shut "
and the ability of the auxiliary feedwater
pump to
supply sufficient feedwater flow at reduced
steam
generator
pressures
to reach the point of Residual
Heat
Removal
System operation.
Design analysis
does not exist to document the
setpoint selection for pressure
switches
and the error
band used to control the operation of solenoid-
operated
steam vent valves.
The setpoint
was verified
to be at 150 psig which would permit the valve to open
automatically before the cooldown has
been transferred
to the Residual
Heat Removal
System.
The lack of a design analysis
in the cases
cited above in
subparagraphs
a, b, and
c appears
to be contrary to the
requirements
of ANSI N45.2. 11 Sections
4. 1 and 4.2 which
requires that design analyses
be performed in a planned,
controlled and correct manner
and that there exist
traceability from design input through to design output.
This item will remain unresolved
pending followup by the
Region II Office (50-250/8532-10;
50-251/8532-10).
3.
During the review of PC/N 80-117, the team observed
system tubing which did not appear to be seismically supported
and instances of broken supports.
This tubing was routed from
the nitrogen cylinder racks to the flow control valves
and
included original tubing as well as
new tubing.
The team was
informed that this lack of adequate
seismic supports
was
known
by the licensee
as
documented
in REA No.
TPN 85-30.
In a March
7,
1985 letter, the licensee directed Bechtel to walk down the
system in the field and determine if the tubing was actually
supported
in accordance
with Bechtel's
design specification for
seismic
Class
I tubing supports or in accordance
with the
original seismic design specification.
On July 19,
1985, in
response
to this request,
Bechtel reported that most of the
3/8-inch tubing was installed in accordance
with Bechtel
- 20-
specifications
but with two tube spans
greater
than that
allowed.
These deviations
were evaluated
and found to be
acceptable
as installed.
Mith respect to the old tubing in the
rest of the system,
Bechtel identified that the configuration
was different than originally accepted
by Project Engineering.
Bechtel evaluated
the configuration using the functionality
criteria developed to justify continued operation in response
to
The Bechtel analysis
determined that the
tubing must be supported at 27 inch maximum intervals-to meet
final design requirements for long term operation.
The licensee
informed the team that correction of this. nonconforming
condition will be performed during the next refueling outage.
This item will remain
an inspector followup item (50-250/8532-11;
50-251/8532-11).
4.
The team found that design calculations
were not being updated
by FPSL to reflect current modifications.
The team was informed
that design inputs were maintained
so that, if required,
the
calculations
could be recreated.
The team found that design
criteria documents
did not exist and that design
bases
were, in
many instances, difficult to retrieve.
This condition was
further complicated
by the controls Bechtel maintains over
calculations
performed
by Bechtel.
The team found that Bechtel
had
a set of original project design calculations
which were
used for reference
purposes
but not updated.
For current design
activities, Bechtel maintained
design calculations
and updated
those calculations
as plant modifications were assigned
to their
design responsibility by FPhL.
As
a consequence, it was
difficult for a Bechtel or FPhL engineer to know where
applicable
design analyses
were to be found.
Further,
the team
observed
a lack of attention to documenting
assumptions,
.justification for their use,
and confirmation that the
assumptions
were accurate after the design
had proceeded.
Likewise, the team found that the source of input data
was not
consistently
design
documents
but,the
FSAR or uncontrolled Plant
Data Books.
During the inspection the
team observed errors in design
documents (e.g., calculations,
drawing and specifications)
which
do not represent,
in themselves,
inadequate
designs
but reflect
a need for more attention to design traceability.
For example:
a.
Bechtel calculation
(M-08-093-02, Auxiliary Feedwater
System Control Valve Sizing, Rev.
1, July 31,
1981) did not
identify the source of assumptions
and input data
such
as
main steam safety valve setpoints, relief valve
accumulation, auxiliary feedwater
pump flow, and
pump
discharge
pressure.
The calculation
made
a general
reference
to FPSL's Turkey Point Unit 3 and
4 Plant Data
Book, Volume 1.
Although this document is not
a design
document, it appears
that it was used
as
a source
document
for design input.
b.
Bechtel
drawing 5610-P-151,
Piping Isometric Auxiliary
System
Pump Discharge,
Rev. 0, November I, 1981,
-21-
had incorrect valve weights
shown for AFW valves CV-3-2818,
CV-3-2816,
and CV-2-2817.
The team confirmed that the
valve weights identified on the vendor valve drawing were
on Bechtel. Drawing 5177-162-P-325,
Rev. 1, dated
May 16,
1983,
and that these weights were used in the piping stress
analysis.
During the inspection,
FP&L initiated an
External
Request for As-Built Verification and Document
Review to correct the identified discrepancies
in the
Bechtel isometric drawings.
c.
Bechtel calculation M-08-093-03, Auxiliary Feedwater
Flow
At Minimum Steam Conditions,
Rev. 0, May 4,
1982,
references
FP&L Plant Data Book, Sections
5.6 and 5.7, for
pump performance ratings.
As stated
above
(subparagraph
a), the Plant Data
Book is an uncontrolled
document
and is
not considered
a suitable
source for design input.
d.
FP&L Calculation,
Low Level Alarm on Condensate
Storage
Tank,
November 15,
1979,
does not identify all of the
assumptions
and design inputs used to perform the
calculation.
The calculation
was performed to establish
the alarm setpoint a'lerting the operator in the control
room of the need to provide makeup water or transfer to an
alternate
water supply in order to prevent
a low pump
suction pressure
condition from occurring.
The team found
no evidence in the calculation that the preparer
considered
the
NPSH required to maintain
AFW pump operation.
Instead,
the preparer
appeared
to have
assumed that the minimUm NPSH
would be below the instrument tap,
because
the analysis
calculated
the height above the instrument tap which
corresponds
to 20 minutes of water at a usage rate of 600
gpm with a
105 factor for conservatism.
The team
independently
confirmed that the
NPSH is well below the
instrument tap and the design is not deficient.
However,
the calculation did not document
assumptions
nor identified
those assumptions
that required verification as the design
proceeded.
The calculation did not define the design
bases
and their sources.
FP&L procedures
in place at the time
this calculation
was performed required
a design analysis
to contain this information (guality Instruction
EPP-gI-3.1,
"Control of EPP Design,"
Rev. 2, October 9,
1979).
e.
Bechtel
Drawing 5610-M-339 Sheet I of 1, Rev.
15,
incorrectly shows that the nitrogen system pressure
control
valves
PC-3-1706,
PC-3-1708,
PC-4-1705,
and PC-4-1709
were
set to provide
55 psig.
These
pressure
control valves were
set for 80 psig.
f.
The
AFW System Description and Design
Bases
document dated
January 31,
1985 had the following errors.
The system description stated that an air signal is
supplied
by a differential pressure
controller which
is set to maintain
a minimum pump discharge
pressure
22
approximately
125 psi higher than the steam supply
pressure.
As observed during the inspection, this
design feature
had been disconnected
(see Operations
and Surveillance Observation 8).
The system description incorrectly stated that when
instrument air pressure
drops
below 55 psig (nitrogen
regulator valve outlet pressure),
open to
automatically supply backup nitrogen.
As stated
previously, the pressure
control valves were set at 80
psig.
The system description incorrectly stated that the low
pressure
nitrogen alarm will allow about
10 minutes
for the operator to get to the station,
close off the
first bottle and cut in bottles 2, 3, and 4, which
will each provide about
a 30 minute supply to the flow
control valves.
This description
appeared
to refer to
the intended operation of the nitrogen station before
the station
was divided into two trains with three
bottles in train I and two bottles in train 2.
The
described action would violate the single failure
criterion.
5.
PC/N Numbers 80-78 and 80-79 were reviewed.
These
PC/Ms
addressed
the diversity of the power supplies to the steam
admission
valves of the auxiliary feedwater
system.
The steam
supply for the auxiliary feedwater
pump turbines is developed in
, the steam generators
and fed to the station
common auxiliary
feedwater turbine
pumps through six steam lines associated
with
the six steam generators
(three
per unit).
'Each
steam generator is isolated from the steam
header with a
normally closed motor-operated
gate valve.
These valves are
powered from a safety-related
power supply (two motor-operators
per unit are
DC powered
and
one is AC powered)
and will auto-
matically open
upon
an auxiliary feedwater initiation signal.
Downstream of these
steam admission valves,
steam vents are
provided to vent off steam that may leak past the isolation
valves.
The following observations
were
made during the review
of the modification package:
a.
The modification of the motor-operators
on the steam supply
valves involved the purchase
of new
DC motor starters.
These motor starters
were specified
and purchased
by
material requisition No. 5177-B6-E-818-4.
These starters
were to be supplied complete with motor overload heaters
compatible with Limitorque operators.
The team reviewed
the motor starter vendor's
drawings to determine
the
overload heater size supplied
and to verify that the type
of overload heater installed agreed with the drawing.
In response
to a team request for criteria and the
calculation
used to determine
the size of the motor
overload heater
needed
to protect the steam supply valve
motors, the licensee
produced
a preliminary calculation,
23
R
~
No. 5177-462-E-02,
prepared
on September
6,
1985 (i.e.,
prepared
during the inspection), to demonstrate
that the
as-installed
motor overload protection would not trip the
valve motor for continuous currents
below 9.19 amperes.
From inspection of the motor nameplate
data,
the team
determined. that these
DC motors are
5 minute duty rated
motors
and the full load current is 6.5 amperes.
This
results in a trip point 140 percent of full load-current.
The team independently
determined that the setting of the
overload devices
provided inadequate
ovet load or stall
protection for the motor-operators.
The team also
confirmed this conclusion with the motor-operator vendor's
engineering
department.
The team's
concern
was that the. motor insulation could be
damaged
during normal plant operations
or periodic testing
because of inadequate
overload protection.
This could
result in the inability of the
DC motor-operated
valves to
perform their safety function during
a design basis event.
In an attempt to determine the generic implications of this
issue,
the team requested, the Bechtel criteria used to
determine
the overload protection for the existing
motor-operated
valve on the third steam supply line.
No
basis for selection of the overload protection
on these
motor-operated
valves at Turkey Point was provided during
the inspection.
The failure of the design organization to verify the
adequacy of the overload protection specified for the
motor-operated
valves is contrary to ANSI N45.2. 11-1974
Section 6.3 which requires that specified parts
and
equipment
be suitable for the required application.
This
item will remain unresolved
pending following by the Region
II Office (50-250/8532-12
- 50-251/8532-12).
b.
Implementation of the design
change
process failed to
verify that the design
change
did not violate the original
design function.
The proposed
cable routing for motor cable 400128( from
motor starter
3N1403 to steam valve MOV-3-1403, as
shown in
the cable
and raceway schedule,
was
78 feet of 5 conductor
AWG No.
12 wire. The team requested
the sizing criteria and
supporting calculations that would indicate that the
conductor size
was sufficient.
During the second
week of
the inspection the licensee
produced
a calculation,
dated
September
10, 1985, With no calculation
number or file
identification.
The calculation
was prepared
during the
inspection
and appears
to have
been
performed in response
to the team's
concerns
about the adequacy of the wire size.
No earlier calculation could be located at Bechtel's
offices either
on site or in Gaithersburg,
The
calculation
used as-installed
cable lengths obtained
from
Bechtel's
5177-E-45C Electrical Circuit Schedule
and motor
- 24-
data
from the Limitorque data sheet.
Although this motor
data did not agree with the motor nameplate full load
current, fts application in this calculation
was judged to
be conservative
by the team.
The calculation demonstrated
that the cable's
ampacity and short circuit withstand
capability were adequate.
However, the calculation stated
that the cable resistance
was sufficiently low so that the
voltage drop was not a concern
because
voltage at the worst
case valve (MOV-4-1403) would remain above
96 volts
DC.
The team questioned this conclusion
because
Bechtel
had
failed to consider starting current.
The team contacted
the actuator manufacturer directly and
confirmed that starting current
and the resulting voltage
drop to the motor must be considered
because
the valve was
tested with only 90 volts
DC as the minimum starting
voltage.
To assess
the effect of starting current, the
team substituted
the published
53 amperes
locked rotor
current obtained
from the Limitorque data sheet for the
8
Amperes full load current used in the Bechtel calculation.
The team determined that the voltage would be less
than the
required
minimum starting voltage of 90 volts for
NOY-4-1403.
F
The team is concerned that during a loss of offsite power
and the resulting
DC system voltage drop, inadequate
voltage would be available at the motor terminals resulting
in a stall condition and
a failure of the
DC motor-operated
valves to perform their safety function.
The failure to adequately
understand
the requirements of
the original design
and to confirm that those
requirements
were met with the new design, is contrary to ANSI N45.2.11
Section 6.3 and 8.2.
This item will remain unresolved
pending followup by the Region II Office (50-250/8532-13;
50-251/8532-13).
c.
The control circuit schematic for the
DC and
AC motor-oper-
ated
steam isolation valves
shows that the control switch
used in the circuit is
a momentary open/closed
return to
normal control switch.
As a consequence,
this switch will
not stop the valve from automatically reopening following
an operator's
attempt to shut the valve as long as
an auxi-
liary feedwater initiation signal is present.
The licensee
had not recognized this design feature
(see Operations
and
Surveillance Observation
1.d for further discussion).
d.
PC/Vi 80-117 added
a second
steam vent valve between
the
steam admission valves
and the auxiliary feedwater
pump
turbines.
The original header
design contained
an
air-operated,
DC solenoid controlled steam vent valve whose
purpose
was to vent steam that may leak by the normally
closed
steam admission valves.
The vent valve is normally
open
and closes
when the
DC solenoid is energized
through
a
pressure
interlock.
When the steam supply header
was
- 25-
separated
into two headers,
an additional vent valve was
added.
The solenoid for this new valve must be energized
to close the valve; however, the valve was powered from an
.
AC source.
The team is concerned that on
a loss of AC
power the open vent on the train 2 steam
header will result
in a path for steam loss.
6.
The design of the nitrogen system failed to provide the required
separation
in the low nitrogen pressure
alarm circuit. Alarms
are provided on the redundant nitrogen system to warn the
operator that he must take action to maintain the nitrogen
system's ability to position the auxiliary feedwater flow
control valves.
The team determined that the low pressure
signals
from pressure
switches
PS-3-2322
(nitrogen train No. I)
and PS-3-2323
(nitrogen train No. 2) feed adjacent control
room
windows.
Associated
pressure
switch contacts
must
close to alarm.
The team determined that the two signals
share
a
common field wire (cable 3R38/3C05-TB3414/I is a
3 conductor
cable with wire AN38 common to both alarm circuits).
The team is concerned that
a single failure, such
as
a loose or
disconnected
wire could result in the co+non
mode failure of all
low pressure
alarms for the redundant nitrogen system.
Further,
this design
appears
to be contrary to the redundancy
and
separation
requirements
of ANSI N45.2.11, Section 3.2.
This
item will remain unresolved
pending followup by the Region II
Office (50-250/8532-14;
50-251/8532-14).
7.
The team reviewed
PC/M 83-05 concerning
replacement of the
safety-related
station batteries.
system
uses direct current motor-operated
valves
and control
'systems
whose
power is derived from the station batteries.
Turkey Point Units 3 and 4 share safety-related
batteries
such
that the
DC power for some of the .Unit 3 auxiliary feedwater
components
is derived from the Unit 4 batteries.
The converse
is true for Unit 4 auxiliary feedwater
components.
The
following observations
were
made during the review of this
modification package.
a,
The safety-related
battery system which existed before
PC/M
83-05 consisted of four batteries,
two per unit.
Unit 3
had
one
C&D battery rated at
1885 ampere-hours
and an
EXIDE
battery rated at 648 ampere-hours,
Unit 4 had one
C&D
battery rated at 2175 ampere-hours
and
an
EXIDE battery
rated at 648 ampere
hours,
With PC/M 83-05, the
1885
ampere-hour
and 2175 ampere-hour
C&D batteries
were
replaced with smaller Gould-GNB 1800 ampere-hour cells.
The 648 ampere-hour
EXIDE batteries
were replaced with
larger Gould-GNB 1200 ampere-hour cells.
These
new
batteries
were purchased
using Bechtel specification
5177-272-E-850.1,
Rev. 0, dated January
18,
1983.
This
document contained
a one-hour battery load profile and
required corrections for
a minimum electrolyte temperature
of 55'
and
an 80 percent end-of-life compensation
in
accordance
with IEEE Standard
485. This specified load
-26-
profile did not agree with that given in FSAR Table 8.2.4.
The team noted that the
DC loads listed in this table did
not include the auxiliary feedwater
DC motor-operated
valves.
In an attempt to determine if all
DC loads
were
accounted for in the sizing of the
new replacement
batteries,
the team requested
the battery sizing
calculations.
The licensee
was unable to produce
an analysis
oP calcu-
lation which was used to develop the load profile used in
the procurement specification.
However, the licensee
did
exhibit a
DC 'system capability study, calculation
5177-399-E-01,
which was performed
by Bechtel during the
first half of 1985.
The purpose of this study was to.
determine
the capability of the
DC system to respond to the
unavailability of selected batteries
under different
operating conditions.
In case I of this study,
each
battery was checked with its own emergency
loads.
This
calculation did include loads for the auxiliary
motor-operated
valves;
however, it assumed
data
based
upon
a preliminary 1980 calculation
and not on manu-
facturer's
data or the equipment
nameplate
data.
This
calculation included inappropriate
assumptions
for the
steady-state
load by basing this load on battery charger
readings
under normal operating plant conditions.
The
calculation did not identify these
as assumptions
requiring
verification.
This calculation also did not include design
margin correction factors for temperature
or inadequate
maintenance
as required
by IEEE Standard
485.
b.
The design modification process failed to include adequate
acceptance
criteria and verification testing for the
new
batteries.
The purchasing
documents specified required
testing
by the battery manufacturer.
Gould-GNB performed
a
standard eight hour capacity test which showed that the
batteries
would deliver at least their eight hour rated
capacity.
This test stopped short of determining
any
margin above rating (Inspection Report 83779 dated
May 5,
1983).
The manufacturer
also performed
a load duty cycle
test
on selected cells in accordance
with the specified
load profile but failed to correct the discharge
rates for
the specified
minimum temperature
condition.
The post-mod-
ification testing performed
on the Unit 3
B battery (Plant
Mork Order 358353) tested
the
new battery using the
half hour profile, not the one hour duty cycle of the
specification.
Again, no temperature
correction
was
made
to the discharge
rate
as indicated
on the July 12,
1985
data sheets.
Because of the lack of an acceptable
load analysis
combined
with inadequate
testing,
the team was unable to determine
the degree of margin existing in the
new batteries.
c.
The plant operating
procedures for the
DC System failed to
reference
the specific periodic testing requirements
for
- 27-
the
new Gould-GNB batteries.
Plant Operating
Procedure
96041.1,
dated
June
19, 1985, specified the requirements
for the monthly equalizing charge.
However, the
new
Gould-GNB batteries
are
composed of lead calcium cells,
and
this type of battery cell should not be given monthly
equalizing charges.
Instead,
they should only be given an
equalizing charge
when required in accordance
with the
manufacturer's
recommendation.
Further, this operating
procedure
references
the instruction manuals for the old
batteries
and does not reference
the new Gould-GNB in-
struction manuals.
Also this procedure calls for different
float and equalizing voltages for the two new Unit 3 bat-
teries.
These batteries
are both made
up of Gould-GNB
NCX
type cells and should have the
same charging voltages.
Plant operating
Procedures
9654.1
and 9654.2,
dated
November 8, 1984, describe
the load test procedures for all
four safety-related
batteries.
Again, these
procedures
only refer to the
CSD Batteries Instruction Manual
(even
though batteries
3B and
4A were originally EXIDE batteries)
and do not reference
the new Gould-GNB instructions.
Additionally, the description of the battery load test
profile used in these
procedures
use the 30 minute
profile also without compensation for minimum electrolyte
temperature
requirements.
The team could not find plant operating
procedures
describing
a battery performance test to determine actual
battery capacity
compared to rated capacity
(as
recommended
by IEEE Standard
450).
The apparent failure to establish
and implement technically
adequate
procedures for the
new station batteries will
remain unresolved
pending followup by the Region II Office
(50-250/8532-15;
50-251/8532-15).
'he
team had
a significant concern that excessive
reliance
was
placed
on operator action instead of design features
to ensure
the proper functioning of the auxiliary feedwater
system.
Specifically, the team was concerned that immediate operator
action
may be required
upon initiation of the auxiliary feed-
watet
system following a loss of main feedwater
and reactor trip
with a concomitant loss of the non-safety-related
instrument air
supply.
Although the auxiliary feedwater
system is designed
to
automatically initiate, design calculations
do not exist which
demonstrate
that the system will continue to run for a period of
time without immediate operator action.
This concern is, in
part,
based
upon the lack of design analyses
to support nitrogen
system design details
and the need for immediate operator action
inherent in the design of the nitrogen system.
This concern is
based
upon the following observations:
Lack of design analysis
based
upon the as-installed
system
to document the setpoint selection for pressure
switches
used to alert the operator that ten minutes of nitrogen
-28-
remain before loss of motive and control pressure (i.e.,
closure of flow control valves
and loss of all feedwater).
Lack of design criterion to define
how long the auxiliary
system
has to operate without operation action.
Consequently,
no guidance
was provided to establish operat-
ing limits on available nitrogen supply before reaching the
low level setpoint.
Lack of engineering direction with respect to post-modifi-
cation testing requirements
to confirm the adequacy of the
installation to design
bases.
II. ~ll l
A review of the corporate
and site quality assurance
auditing
activities revealed that these audits,
as implemented,
neither
had
identified nor were capable of identifying quality concerns of a
technical
and operational
nature similar to those
concerns identified
during this
NRC inspection.
Both the corporate
vendor audit and the
plant audit programs
were designed
to assure that gA programs
met
NRC
requirements
and licensee
commitments
from a programmatic basis only.
The following are examples of audits
conducted
by corporate
and site
gA staffs that failed to identify any of the significant weaknesses
identified during this inspection.
Audit Numbers
Activit Audited
08. 01. DTLMD.84. 1
OAS-EPP-83-1
gAS-JPE-84-1
gAO-PTP-84-549
gAO-PTN-85-657
gAO-PTP-82-10-421
gA program including
design control
(BPCO)
Power Plant Engineering
Training
Plant Change-Modification
The lack of an implemented corporate
and site audit program providing
for technical
and operational
reviews of vendor and plant activities
meant that
FPSL management
was not receiving important feedback
on
the quality of activities affecting the safe operation of the plant.
The team noted that recent Performance
Enhancement
Program
initiatives were being implemented
and guality Improvement
Program
efforts were underway to address
some aspects
of these
gA weaknesses.
The progress of this effort will be tracked
by the
NRC Region II
Office as part of their routine followup to the licensee's
Perform-
ance
Enhancement
Program.
IV.
MANAGEMENT EXIT MEETINGS
An exit meeting
was conducted
on September
13,
1985, at the Turkey Point
plant.
The licensee's
representatives
are identified in the Appendix.
- 29-
The scope of the inspection
was discussed,
and the licensee
was informed
that the inspection would continue with further in-office data review and
analysis
by team members.
The licensee
was informed that
some of the ob-
servations
could become potential enforcement findings.
The team members
presented their observations for each area
inspected
and responded
to
questions
from licensee's
representatives.
-30-
Persons
Contacted
APPENDIX
The following lists the persons
who attended
the exit interview.
persons
were contacted
during this inspection
and other technica
strative personnel
were also contacted.
C. 0.
Woody, Vice President,
Nuclear Operations
J.
W, Dickey, Assistant to the Vice President,
Nuclear Operation
C.
M. Wethy, Vice President,
Turkey Point
C. J. Baker, Plant Manager,
Nuclear
H. T. Young, Site Project Manager
and Acting Plant Manager
D. D. Grandage,
Operations
Superintendent
T. A. Finn, Operations
Supervisor
J.
E. Price,
Corporate
Engineer
R. J. Acosta, guality Assurance
Superintendent
L.
W. Bladow, gualfty Assurance
Supervisor
T. P. Coste, Project guality 'Assurance
Engineer
J.
W. Kappes,
Maintenance
Superintendent
W. C. Miller, Training Supervisor
E. F. Hayes.
I&C Department Supervisor
S.
G. Brain, Turkey Point Project Engineer
K. L. Jones,
Technical
Department Supervisor
J. Arias, Jr., Regulatory
and Compliance Supervisor
'.
E. Boger,
ANI Inspector
J.
K. Hayes,
Manager, Licensing and guality Assurance
E.
H. O'Neal,
Systems
Engineer,
AFWS
J.
M. Donfs, Site Resident
Engineering Supervisor
H. E. Hartman, In-Service Inspection Supervisor
R. Gouldy, Corporate,
Licensing
D.
W. Haase,
Safety Engineering,
Group Chairman
M. J. Crisler, gualfty Control Supervisor
G.
M. Vaux, Safety Engineer
J. Rosenfeker,
Corporate
Engineer
F.
H. Southworth, Corporate
Engineer
R. A. Longtemps, Assistant Superintendent,
Maintenance
Some of these
1 and admini-
Enclosure
2
Su
ested Addition
The following insert would update the draft report.
This insert could
be placed after the first full paragraph
on page 35:
The NRC's Office for Analysis and Evaluation of Operational
Data
collects,
assesses,
and distributes
data,
including statisical
measures
of licensee
performance.
Recent activities in this regard
include:
o
The Licensee
Event Report System
was modified through adoption
of a new rule, 50.73, which was effective January I, 1984.
The
new LER rule, for the first time, places
uniform reporting
requirements
on all nuclear
power plants
and assures
that events
of interest,
such
as actuations of all engineered
safety features,
will be reported to the
NRC.
Thus data,
which was not previously
readily available,
now exists to track the operational
experience
of each plant on
a defined
and consistent
base.
o
AEOD analyzes
the trends
and patterns of individual plant perfor-
mance
as well as that of the industry.
Included in this activity
are performance
indicators
based
upon operational
data.
Two major
studies
in this regard
have
been
produced;
one study covers the
scram history of all plants during 1984,
and the other study covers
the actuation of Engineered
Safety Features
(ESF) equipment for the
first six months of 1984.
These studies
have
been distributed to
the staff and are intended for use
as input into the
SALP Program.
hase studies
are the first in a series of reports
on scrams
and
actuations.
Subsequent
reports will also consider the trends in these
measures
of licensee
performance.
AEOD also
has in progress
studies
which will provide statistical
measures
associated
with safety system
availability and technical specification violations.
o
As another specific measure of plant performance,
AEOD is implementing
a quantitative
program to assess
the quality of Licensee
Event Reports
prepared
by licensees.
This program provides
a summary of the strengths
and.weaknesses
of LERs from individual plants
and then provides
a summary
of all plants.
This data is also being routinely provided to each
region
as input to SALP determinations.