ML17326B204
| ML17326B204 | |
| Person / Time | |
|---|---|
| Site: | Cook  |
| Issue date: | 03/25/1986 |
| From: | Hehl C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML17326B205 | List: |
| References | |
| 50-315-86-04, 50-315-86-4, 50-316-86-04, 50-316-86-4, NUDOCS 8603310069 | |
| Download: ML17326B204 (28) | |
See also: IR 05000315/1986004
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION III
Reports
No. 50-315/86004(DRP);
50-316/86004(DRP)
Docket Nos
~ 50-315;
50-316
Licenses
No.
Licensee:
American Electric Power Service Corporation
and Michigan Electric Company
1 Riverside
Plaza
Columbus,
OH
43216
Facility Name:
Donald
C.
Cook Nuclear
Power Plant, Units 1 and
2
Inspection At:
Donald
C.
Cook Site,
Bridgman,
MI
Inspection
Conducted:
January
21,
1986 through February 18,
1986
Inspectors:
B.
L. Jorgensen
J.
K. Heller
C.
L. Molfsen
R.
Swanson
Approved By:
Proje
Chief
s Section
2A
Date
Ins ection
Summar
Ins ection
on Januar
21
1986 throu
h Februar
18
1986
Re orts
No.
50-315/86004(DRP
. 50-316/86004
licensee
actions
on previously identified items; operational
safety verification;
reactor trip/safety system challenge
review; surveillance;
reportable
events;
and independent
inspection activities.
The inspection involved a total of 256
inspector-hours
by four NRC inspectors
including 20 inspector-hours
during
offshift.
Results:
Of the six areas
inspected,
no violations or deviations
were identified
in four areas.
The two violations (Level IV - failure to properly review and
control procedure
changes,
Paragraph
2.c;
Level
V - failure to meet requirements
of Technical Specification for compensatory
sampling with equipment inoperable,
Paragraph
6) were identified with one in each of the remaining areas.
DETAILS
1.
Persons
Contacted
M.
"A.
- J
K.
- J
- L
- L
C
D.
M.
D
"R.
T.
G. Smith, Jr., Plant Manager
Svensson,
Assistant Plant Manager
Blind, Assistant Plant'anager
Kriesel, Technical
Superintendent-Physical
Sciences
Allard, Maintenance
Superintendent
Baker, Operations
Superintendent
Stietzel, guality'ontrol Superintendent
Mathias, Administrative Superintendent
Gibson,
Technical
Superintendent-Engineering
Murphy, Operations-Production
Supervisor
Draper,
Operations
Procedure
Coordinator
Horvath, guality Assurance
Supervisor
McAlhany, guality Assurance
(AEPSC)
Sims, Shift Technical Advisor
Postlewait,
Performance
Supervising
Engineer
The inspector also contacted
a number of other licensee
and contract
employees
and informally interviewed operations,
maintenance,
and
technical
personnel.
"Denotes personnel
attending exit interview February 19, 1986.
~
~
2.
Licensee Actions on Previousl
Identified Items
a 0
(Open) Unresolved
Item (315/85028-01;
316/85028-01);
apparent
failure to perform surveillance testing at the required frequency
and failure to perform adequate
surveillance testing.
This item has
three attributes,
each of which has
been determined to represent
a
Violation.
First,
as described
in Paragraph
3. a. of the referenced
Report, various
CHANNEL FUNCTIONAL TESTS required to be performed
each
month were, prior to August 1985, being performed only once
each
two months.
Second,
as described
in Paragraph
3.c. of the
referenced
report,
a motor-driven auxiliary feedwater
pump loss of
voltage relay required to be tested
each refueling had, prior to
August 1985,
never
been tested.
Third, as described
in Paragraph
3. d.
of the referenced
Report,
selected
CHANNEL CALIBRATIONS (defined
as
requiring inclusion of the sensor)
had, prior to August 1985,
been
performed excluding the sensor.
These matters
have
been discussed
with the licensee
during meetings with the
NRC Region III staff;
specifically during an Enforcement
Conference
held on November 13,
1985.
They remain under evaluation for appropriate
enforcement action,
including potential
escalated
enforcement.
Though
no Notice of
Violation concerning these
matters is being issued with this report
decisions
concerning application of proper enforcement
sanctions
are
pending.
The licensee
is being officially notified in writing via
the transmittal letter for this report that the items are considered
Violations. In the future this item will be tracked
as Violation
(315/85028-01;
316/85028-01).
0
T
'I
T
UI '
b.
C.
(Open) Unresolved
Item (315/85028-02;
316/85028-02):
failure to
conduct
a channel
functional test following a channel calibration.
NRC has not determined if this matter is a Violation.
NRC will
correspond with the licensee
concerning this item at a later date.
(Closed)
Unresolved
Item (315/85028-03;
316/85028-03):
apparent failure
to provide adequate
reviews
and controls
on temporary procedure
changes.
This item has also
been determined to be
a Violation, as discussed
previously with the licensee.
A Notice of Violation concerning this
item is being issued with this report.
A brief review of the facts is
appropriate.
During conduct of the inspection
documented
under Reports
No. 315/85028;
316/85028 the inspectors
observed
a procedure
in use
which had apparently
been altered
by a pen
and ink change.
Following
up this observation,
a large
number of similar procedures
(Control
and
Instrument group test procedures)
were reviewed from the files.
Though
the sample
was large, it constituted only a fraction of the total
number of procedures
of this type.
A total of eleven procedures
were
found which had been altered;
however, required review and approval for
such alterations
had not been applied.
Technical Specifications
(both
Units) Paragraphs
6.8.2
and 6.8.3 require prior review and approval of
all procedure
changes;
with permanent
changes
reviewed
and approved
by
the Plant Nuclear Safety Review Committee
(PNSRC)
and the Plant Manager;
and temporary
changes
(not altering the intent of the procedure)
requiring approval of two members of the management staff including one
Senior
Reactor
Operator license holder.
Subsequent
PNSRC and Plant
Manager approval of temporary
changes
must follow within 14 days.
In
the examples identified by the inspectors,
neither type of review and
approval
process
had been performed.
Subsequent
to this finding, as
stated in the licensee's
letter of November 27,
1985 and as described
in Inspection
Reports
No. 315/85041(DRP);
316/85041(DRP),
the licensee
performed
a comprehensive
review of all procedures
of the subject type,
identified and evaluated
each instance potentially involving a
previously unreviewed
and unapproved revision to such procedures,
and
documented
the requisite review and approval
as
needed.
No examples
were identified which appeared likely to have caused
incorrect procedure
performance
or invalid data.
Preventive actions
have included
conversations
with the personnel
apparently
involved in the procedure
alterations.
The discussions
focused
on
a Plant Manager letter dated
September
16,
1985 to all supervisors,
addressing
the
use of required
controls
when making changes
to procedures.
Since actions to correct
and to prevent recurrence
of this Violation have already
been completed,
the licensee will not be required to respond to the Notice of Violation
issued
herewith.
The inspector
has
no further questions
concerning
this matter at this time (Violation 315/86004-01;
316/86004-01).
Four violations and
no deviations
were identified.
'I
C
I
v
0 erational
Safet
Verification
The inspector
observed control
room operation including manning, shift
turnover,
approved procedures
and Limiting Condition for Operation
(LCO)
adherence,
and reviewed applicable
logs and conducted
discussions
with
control
room operators
during the inspection period.
Observations
of the
.control
room monitors, indicators,
and recorders
were
made to verify the
operability of emergency
systems,
radiation monitoring systems,
and nuclear
and reactor protection systems,
as applicable.
Reviews of surveillance,
equipment condition,
and tagout logs were conducted.
Proper return to
service of selected
components
was veri'fied.
Tours of the auxiliary
building, turbine building, and screenhouse
were
made to observe
accessible
equipment conditions, including fluid leaks, potential fire hazards,
and
control of activities in progress.
Unit 1 operated routinely at approximately
90 percent
power throughout the
inspection period.
The inspector performed
a walkdown and review of
accessible
portions of the Unit 1 "E" (East)
Containment
Spray System
(CTS)
using licensee
drawing OP-1-5144-6
and procedure
1-OHP 4021.009.001
"Placing Containment
Spray in Standby
Readiness".
Correct .flowpath valve
positions were verifi'ed, and
no condition was noted which degraded
the
system'or its major components.
It was not possible to verify the correct
(closed) position of valve 1-IMO-210 (an automatic
opening
pump discharge
valve) using the local dial indicator at the valve.
Control
room
indication established
the valve was correctly position'ed.
Discussion with
the licensee
suggested
the local indicator's
not heavily relied upon to
ascertain
valve position.
Nevertheless,
a Job Order was initiated to
adjust the dial to the correct
onscale
reading.
- Based
on a Unit 2 event
(discussed
below) involving valve identification tag interference with
proper valve operation for a small
manual valve, the walkdown specifically
focused
on potential additional
examples
where
an identification tag was
positioned
so as to create possible indication.
No examples
were noted in
this small sampling.
Unit 2 operated at approximately
80 percent
power throughout the inspection
period with three exceptions.
A Unit trip on February 1,
1986 is discussed
in Paragraph
4 below.
The two other events
both involved .licensee
initiation of plant shutdown pursuant to Technical Specifications
because
the Boron Injection Tank (BIT) boron concentration
became diluted below the
required 20,000 parts per million (ppm).
The first event occurred
February 7, 1986.
Operators
acquiring routine shift readings
noted
a level
increase
in the "S" (South) Boric Acid Storage
Tank (BAST), which was in
service recirculating the BIT.
A special
boron sampling
was requested
which showed at l2:05 p.m. that the BIT had been diluted to 17,331
ppm.
Recirculation
was switched to the "M" (Middle) BAST.,
a resample
called for,
and
a Unit shutdown
commenced.
By 1:40 p.m.
resampling results
demonstrated
the BIT concentration
was back in specification
and the
shutdown
was terminated.
Subsequent
investigation of a suspect pair of
cross-tie
valves
from the primary water system disclosed
one of the valves
had a damaged
internal
diaphragm which apparently permitted the leakage
and
resultant dilution.
The primary water system
had been in service to dilute
the primary coolant system in support of the ongoing power increase after
recovery from the reactor trip a week earlier.
0
II',
i
f
t
l
l
I
Five days later,
on February 12,
1986
a second dilution of the Unit 2 BIT
occurred.
In this event,
the BIT had been taken off "M" BAST recirculation
to permit alignment of the still-diluted "S" BAST through part of the
shared piping.
The "S" BAST was intended to be
pumped
down to a holding
tank to make
room for the addition of sufficient highly concentrated
boric
acid to return that tank to specification.
When the "M" BAST level
increased
(as observed
in the Unit 1 control
room, which has the only level
indication on this "shared" tank)
a special
boron sample
was again
requested
which, at 4:48 p.m.,
showed boron concentration
to be 19,047
ppm.
Since it was believed the dilution path must be directly through the BIT
(which later proved the case)
the BIT was immediately restored to
recirculation via the "M" BAST (which had not diluted significantly) and
resampling called for while a shutdown
was begun.
By 5:55 p.m. the
resample
analysis
showed the BIT back in specification.
The shutdown
was
terminated.
Investigation of this problem found a small
(one inch) manual
isolation valve separating
the "S" BAST from the BIT had not been fully
closed
because
the handwheel
had 'tightened
down on a small ball-chain
attaching the valve identification tag to the valve, instead of tightening
into the valve seat.
Some discussions
among the inspector
and licensee
personnel
concerning this event suggest
the following: first, the valve in
question
was not the sole isolation valve available
and dual isolation
could have
been established;
second,
changing
"M" BAST level could have
been
noted sooner
had Unit 2 communicated
more clearly or forcefully than
it did to Unit 1 that changing tank leve~l could indicate
a problem and;
third, the tag interference is not necessarily
indicative of a generic
problem because it involved a small manually operated
valve on an insulated
and heat-traced
pipe run (the insulation obscuring the valve stem)
and the
"old style" plastic identification tag;attached
with a ball-chain.
The
licensee is engaged
in placing new, color coded metallic permanent
identification tags
on plant components.
Guidance already in existence for
such permanent
tag placement
should, for a valve of this type, result in
attachment to the pipe rather than around the valve stem.
In fact, prior
to the conclusion of this inspection
a permanent
tag had been
made
and
placed at the valve in question
and the old tag and chain removed.
In each of the above instances,
the licensee's
actions
were in compliance
with requirements.
The previous Inspection Report
(No. 315/85041(DRP);
316/85041(DRP))
discusses
some
need for improved clarity in the way the licensee controls
the turbine driven auxiliary feedwater
pump speed controller setting.
The
instructions
given in various procedures
were at odds with each other.
During this inspection,
the licensee
completed procedure
change
sheets
to
applicable procedures
such that these contradictions
are
removed.
He has
chosen to control this parameter via an information tag placed at the
controller indicating the correct setting
as established
by monthly testing.
Proper controller position will be verified each shift.
The inspector
has
no further questions
or concerns
in this area.
Finally, the inspector discussed shift staffing,
and the licensee's
capabilities for maintaining and/or augmenting shift crews
as necessary
when considering
severe
inclement weather, with licensee
operations
management staff.
They appeared
both sensitive to and prepared for
weather
emergencies
insofar as maintaining adequate shift crews
was
concerned.
0
J
II I
'
Pl
1
5
v
0 'o
violations or deviations
were identified.
Reactor Tri s - Safet
S stem Challen
e Review
t t
The following event was reviewed by the resident inspectors
to determine:
the significance of the event;
the performance of safety systems;
immediate
actions
taken
by the licensee;
radiological
consequences;
and corrective
actions
taken.
Unit 2 tripped from about
80 percent
power at 8: 11 a.m.
on February 1,
1986
as
a consequence
of a main generator "unit differential" trip.
The
generator differential trip was apparently
caused
in turn by protective
relay response
to a faulting condition on the
2CD auxiliary transformer,
which was providing station power back off the main generator.
Plant
response
to the trip, including fast-transfer of station loads to startup
power,
was normal.
A fire ensued
on the
2CD transformer at a failed bushing atop the unit, and
the bus ducting system
drew considerable
smoke into the adjacent turbine
building, making the magnitude
and location of the fire uncertain at first.
An "Unusual
Event" was declared at 8: 15 a.m.
due to the fire, which was
subsequently
extinguished
by 8:27 a.m.
The "Unusual
Event" was secured at
9:03 a.m.
Licensee
response
to and management
of the fire situation are
subject to further review at
a later date
by specialists
from NRC
Region III, and will not be addressed
fur ther here.
Response
of the plant,,
as noted above,
was normal; although operators
continued running the
turbine driven auxiliary "feedwater
pump longer than needed
(perhaps
due to
focus
on the incoming reports relating to the fire) and cooldown proceeded
to 532 degrees
versus
a normal hot standby of 547 degrees
(and pressure
was
around 2,000 psig) before the
pump was secured.
Following applicable post-trip reviews
and required authorizations
the
Unit 2 reactor
was again taken critical late
on February 3, 1986.
In the
interim, early on February 3, the initial approach to criticality was not
proceeding
per expectations
established
by an estimated critical position
(ECP) calculation.
Extrapolations
during the approach
suggested
the
ECP,
plus
a 500
pcm target band,
was going to be exceeded.
The approach
was
terminated, all control banks re-inserted,
and a review initiated to
determine
what happened.
An NRC Region III inspector
specializing in
reactor physics
was onsite performing an inspection in that area,
arrangements
were
made for the specialist to review this matter as well.
That review was documented
in IE Inspection
Reports
No. 315/86005(DRS);
316/86005(DRS).
5.
No violations or deviations
were identified.
Surveillance
The inspector
reviewed Technical Specifications
required surveillance
testing
as described
below and verified that testing was performed in
accordance
with adequate
procedures,
that test instrumentation
was
calibrated, that limiting conditions for operation
were met, that removal
1
'
4
and restoration of the affected
components
were properly accomplished,
that
test results
conformed. with Technical Specifications
and procedure
requirements
and were reviewed by personnel
other than the individual
directing the test,
and that deficiencies identified during the testing
were properly reviewed
and resolved
by appropriate
management
personnel.
Performance
of all or parts of the following tests
was observed:
""1 THP 4030 STP.013
"Pressurizer
Pressure
Protection
Set III"
- 1 THP 4030 STP.014
"Pressurizer
Pressure
Protection Set IV"
""1 THP 4030 STP.005
"Over Temperature
and Over Power Protection
Set II Surveillance Test (Monthly)"
"*1 THP 6030
"OT/T-avg Protection
Set II Calibration"
The test designated
IMP.095 was required for recalibration of two R/E
converters
which were determined to be out of specification during initial
performance of STP.005.
The test designated
STP.005
was then repeated
(this retest
was specifically observed)
and all "as left" values
appeared
to be in specification.
For the following tests,
the inspector
reviewed the test procedures
and/or
completed test data for the more recent test performances:
~*1 OHP 4030 STP.007E
"East Containment
Spray System Operability
Test"
- 1 OHP 4030
STP.007W
"West Containment
Spray System Operability
Test"
~*1 THP 4030 STP.205A
- 1 THP 4030
STP.205B
""1 THP 4030 STP.217A
"Engineered
Safeguards
Features
Time
Response
Test - Train A"
"Engineered
Safeguards
Features
Time
Response
Test - Train B"
"Diesel Generator
Load Shedding
and
Performance
Test - Train A"
- 1 THP 4030 STP.217B
"Diesel Generator
Load Shedding
and
Performance
Test - Train B"
The inspector
reviewed the technical
content of STP.007E
and
STP.007W (both
were Revision
1 with change
sheets
1,
2 and
3 incorporated)
and found that
the procedures
appear to demonstrate
the operability of the Containment
Spray
and Spray Additive Systems
in accordance
with the appropriate
monthly
Technical Specification surveillance
requirements.
However, the inspector
questions if the cycling of l-IM0-212, "1E CTS
Pump Eductor Supply Valve"
and 1-IMO-222 "1W CTS Pump Eductor Supply Valve" meets the intent of ASME
Boiler and Pressure
Vessel
Code,
Section XI.
The sequencing of STP.007E
/'I
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ys
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t
1
N
'\\
and STP.007W is such that valves
1-IMO-212 and I-IMO-222 are cycled
(closed-opened-closed)
before the valves are stroke-timed in the open
position.
The inspector discussed
this with the Operations
Superintendent
and the Operations
Procedure
Coordinator.
The Operations
Procedure
Coordinator agreed to review this item and make the appropriate
revisions
to STP.007.
This is an Open Item pending the Operations
Coordinator review
(Open Item 315/86004-02).
Technical Specification
3. 3. 2.1 at Table 3. 3-5 specifies
an Engineered
Safety Feature
(ESF) response
time of less
than or equal to 45 seconds
for the Containment
Spray System.
STP.205A and STP.205B at Step 6.6 '
of
attachment
4 implements this requirement.
The inspector
reviewed these
procedures
and found that parallel
spray
pump discharge
valves
(two per
pump) have
an allowable
ESF response
time of less
than or equal to 60
seconds.
This time is footnoted by reference
to Attachment
3 of STP.205A
or B, explaining why the response
time is increased
from 45 seconds
to 60
seconds.
Basically, attachment
3 explains that if the valves are
open at
least
20 percent,
the system resistance
is negligible and the spray system
will be capable of performing its safety function.
The attachment
does not
state
how many seconds. it takes for the valve(s) to reach
20 percent
open.
The inspector discussed this with the Technical Superintendent-
Engineering,
who initiated an evaluation to show the valves are at least
20
percent
open in less than 45 seconds.
An analysis that shows
20 percent
open will provide negligible flow resistance will be included.
Pending
further
NRC review of this matter, this is considered
an Open Item
(315/86004-03).
The inspector
reviewed completed Attachment
4 to STP.205B
(performed
November 1985)
and STP.205A (performed October 1983).
The following were
found.
a e
b.
STP.205B listed an
ESF response
time of 60.2 seconds
for IMO-220 and
documented
"Attachment
3 states
that valves must be 20 percent
open
within 60 seconds"
which is an incorrect interpretation of
Attachment 3.
The acceptance
criterion
was less
than or equal to 60
seconds.
The significance of the additional 0.2 seconds
is unclear.
However, this should
be resolved
when
Open Item 315/86004-03 is
resolved.
l
STP.205B includes the diesel
generator start time and load sequencing
time to determine
ESF response
time,
and states
these
times can
be
obtained
from STP.2178.
The inspector
reviewed
STP.217B
(performed
June
16, 1985)
and found that the timing graphs,
which used
a
multi-pen recorder,
did n'ot have
a "key" for deciphering which pen
tracks what component.
With the assistance
of a Performance
Engineer
the key was found in an uncontrolled location.
The Performance
Engineer
committed to incorporate
the
key into STP.217B.
The
inspector
reviewed
a sample of other procedures
that used multi-pen
recorders
and found that the completed procedures
adequately
identified components.
This was discussed
at the exit interview with
the inspector stressing,
and the licensee
agreeing,
that completed
documentation
should stand alone.
C.
STP.205A documented
"N/A" for the requirement to include the load
sequencing
time when determining the lE Containment
Spray
Pump
response
time.
This appears
to be in error.
The inspector discussed
this with the Performance
Supervisor concerning
how a demonstration
of
compliance to an overall time limit requirement
can
be made without
one of the time constituents.
He agreed to verify the response
time,
including sequencer
loading time, met the 45 second
requirement.
This
is considered
an Open Item (Open Item 315/86004-04).
No violations deviations
were identified.
Three
open items were
identified.
Re ortable
Events
Through direct observation,
discussions
with licensee
personnel,
and review
of records,
the following Licensee
Event Reports
(LERs) were reviewed.
The
review addressed
compliance to reporting requirements
and,
as applicable,
accomplishment
of immediate corrective action.
If indicated "closed", the
review showed appropriate corrective action to prevent recurrence
had been
accomplished
in accordance
with applicable
requirements.
Unit 1
(Closed)
RO 315/85005-00:
incorrect iodine sample
medium.
The plant had
been using silver zeolite cartridges for iodine collection/analysis
since
June
1982, contrary to Technical Specification 3.11.2. 1 Table 4. 11-2, which
specifies
a charcoal
medium for iodine collection in the auxiliary building
vent system,
and gland exhaust
system.
The iodine collection medium was
changed
back to a charcoal
cartridge
on February 5,
1985 and will be used
until a Technical Specification
change
can
be made to allow for the use of
the more accurate silver zeolite cartridge.
Application for this change is
included in a letter, dated January
21,
1986
(AEP:NRC:0956A) written to the
Office of Nuclear Reactor
Regulation.
(Closed)
RO 315/85019-00
and 315/85019-01:
low ice condenser
basket weights.
An April 1985 surveillance indicated that several
ice condenser
ice basket
weights were low.
The ice inventory in the ice condenser
was below the
Limiting Condition for Operation
(LCO) in Technical Specification 3.6.5. l.d,
for the minimum average
ice weight (1220 lb/basket) of sample
baskets
from
each row/group.
An extensive
ice replenishment
program was completed
during the Unit 1 1985 outage;
the surveillance,
12
THP 4030 STP.211,
"Ice
Condenser
Basket Weighing," was completed three times satisfactorily in
1985 after the replenishment.
In addition, Unit 2 satisfactorily completed
an ice basket weighing surveillance in August 1985 and plans
a
replenishment
program for 540 baskets
for the 1986 outage
which begins in
February
1986.
(Closed)
RO 315/85026-00:
ESF actuation-safety
injection.
The signal
occurred
due to one channel
of pressurizer
pressure
in test concurrent with
loss of the block signal
on another
channel
when the vital instrument
bus
Control
Room Instrument Distribution (GRID) was momentarily deenergized.
To prevent recurrence
the licensee
has
added
a precaution to the vital
I
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r
f!
1
tl
'
instrument
bus power supply transfer
procedure
(OHP 4021.082.008)
that
advises
the operator to evaluate
the status
of protection channels prior
to power transfer.'-'-
The licensee
has,implemented'-a
design
change in Unit 1
to replace the
CRID inverters
(DC-01-2766)
and plans to complete the Unit 2
design
change during the 1986 outage.
The
new design
power supply can
be
transferred without deenergizing
CRIDS.
(Closed)
RO 315/85031-00
and 315/85031-01
(Applies to both Units):
incorrect calibration of residual
heat flow instrumentation.
The licensee
discovered
a combination of factors
had led to instrumentation for RHR hot
leg process
flow and
RHR cooldown flow being inaccurate.
The indicated
flow exceeded
the actual flow, such that use of the flow indication to show
compliance to requirements
for minimum flow through the reactor coolant
system,
is suspect.
At an indicated 3,000
gpm (corresponding
to the
minimum flow requirement)
actual
flow could have
been
as
low as 2,026
gpm.
The licensee's
supplemental
report dated
September
9,
1985 contains
analyses
demonstrating
2,000
gpm is adequate
flow for decay heat
removal
and to avoid boron stratjfication.
One of the subject instruments
(per
Unit) feeds
a low flow alarm which would warn plant operators
of loss of
flow, so actions could be taken to protect the associated
pump and to
establish
an alternate
flow path.
The alarm setpoint (intended for
2,000
gpm) could have
been set
as
low as
675
gpm.
Considering
independent
means to identify loss of flow and the substantial
time (at least
one hour)
permitted to correct
such loss,
accuracy of the alarm setpoint is not
considered critical.
At the time of the discovery of this matter in early July,
1985 the
inspector briefly reviewed the circumstances
with licensee
personnel.
Replacement
of erroneously
drawn meter faces
(considered
the primary
deficiency - see
IE Inspection
Reports
No. 50-315/85020(DRP);
50-316/85020(DRP)
Paragraph 3.c.)
was specifically verified at that time
as immediate corrective action.
Subsequent
reviews indicate all the
instruments
affected (three per Unit) were identified in the licensee's
search f'r additional
examples,
and
no other examples
were 'found in
independent
reviews by the resident inspectors.
Prevention
should
be
assured
by revision of the associated
calibration procedures,
which is
complete,
now that correctly drawn permanent
meter faces
are installed.
Though uncertain, it is likely the licensee
operated
both Units at various
times with (unknowingly) less than the required flow, in violation of
Technical Specifications.
In such
an event,
the violation would be of the
kind (identified, 'reported
and corrected
by the licensee,
small safety
significance
and unrelated to a previous similar violation) for which NRC,
under its enforcement policy as stated in 10 CFR Part 2, Appendix C, does
not usually issue
a Notice of Violation, and
no Notice of Violation is
being issued in this case.
(Closed)
RO 315/85034-00:
breach of containment integrity during refueling.
Both airlock doors were momentarily opened simultaneously
during refueling,
identifying a malfunctioning latching mechanism.
The mechanism
was
repaired within about five hours,
during which time no further simultaneous
openings
occurred.
10
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(Closed)
RO 315/85035-00:
boron concentration
below
2,000
ppm during refueling (two occasions
about
30 ppm below).
The fuel
vendor evaluated
minimum boron concentration
necessary
to maintain shutdown
margin at 1565
ppm, well below the concentrations
observed
in this event.
No positive identification could be
made of the source of dilute water,
despite
an investigation of various possibilities.
The licensee
believes,
since strict control of boron concentration
above 2,000
ppm was not required
during the full core offload preceding this event, that stagnant
RCS volumes
(e.g. in idle legs)
mixed back into the system following reload
and
establishment
of varying residual
heat
removal flow paths.
This
possibility has
been
addressed
by a Standing Order to maintain 2,000
ppm
throughout the systems
even during periods
when there is no fuel in the
reactor vessel.
(Closed)
RO 315/85037-00:
ESF actuations
during cold shutdown.
Two events
occurred
as
a consequence
of modifications to the plant permitted only
during cold shutdown.
They are considered
minor events with respect
both
to safety significance
and to the question whether they may have merited
some effort in an attempt to avoid them.
Their reportabi lity is based
(correctly)
on the understanding
~an
ESF actuation
not "preplanned"
must
be reported.
The licensee
categorized
these
items
as not "preplanned"
due
to the absence
of a specific prior notification to the operators that an
actuation
was imminent.
(Closed)
RO 315/85039-00
(applies to both Units):
surveillance
performed
on wrong fire water ring header valve.
This item is similar to
RO 315/84025-00
discussed
in IE Inspection
Reports
No. 50-315/84023(DRP);
50-316/84025(DRP)
in that it involves discovery,
due to flow print verifi-
cation activities mandated
by the licensee's
Regulatory Performance
Improvement
Program, that a valve other than that intended
had been
subjected
to testing
due to flow print error.
The error was corrected.
(Closed)
RO 315/85040-00
(applies to both Units):
potential for RHR flow
below limits.
In review of
RO 315/85031-00
discussed
above involving RHR
flow instrument calibration, the licensee
recognized
RHR flow paths
are
available
and used which are not equipped with a low flow alarm.
Though
the license condition which prompted installation of the existing alarms
no longer exists,
the need to promptly identify loss of RHR flow remains
whatever the system alignment,
and written instructions to the operators
establishing
frequency for and documentation
on flow verification have
been issued.
(Closed)
RO 315/85044-00:
ESF actuation during cold shutdown.
As with
RO 315/85037-00
discussed
above,
these
were trivial (but reportable)
events
related to installation of a design
change permissible only with the plant
in cold shutdown.
(Closed)
RO 315/85052-00:
an
ESF actuation in the form of a containment
purge isolation
~si nal
(no purge
was in progress
so
no actual isolation
occurred)
was caused
by component failure in the Critical Control
Room
Power
(CCRP) inverter.
Damaged
and questionable
components within the
inverter were replaced
and normal electrical
lineups restored.
(Closed)
RO 315/85054-00:
an
ESF actuation in the form of a turbine trip
~si nal (the plant was in NDDE 3 with the turbine not in service)
was caused
by steam generator hi-hi level.
Level was being maintained
above the high
deviation alarm point of 50 percent level (at about
60 percent) to perform
a calibration procedure.
Temperature
changes
and feedwater
leakby increased
level to the 68 percent "trip" setpoint undetected
by the operator,
who was
involved in shift turnover.
Though this specific event lacked safety sig-
nificance, operator attentiveness
is highly important and was specifically
addressed
with the operator involved.
Job Orders to investigate
apparent
feedwater isolation valve leakage
were written.
n
(Closed)
RO 315/85057-00
and 315/85057-01:
an
ESF actuation in the form of
a reactor trip ~si nal (the plant was in NODE 3 with the control
rods
inserted
and the reactor trip breakers
open)
was caused
by simultaneous
de-energization
of two power range nuclear instruments to install
a design
change.
Though this specific example
lacked safety significance, it
occurred
because
the Unit Supervisor
and the, instrument technicians
involved
did not recognize
the activity could best
be accomplished
one channel at a
time.
(Closed)
RO 315/85059-00:
an
ESF actuation in the form of a reactor trip
~si nal (plant in NODE 3, trip breakers
open)
was caused
by a technician
lifting the wrong leads while performing instrument checks.
(Closed)
RO 315/85060-00:
an
ESF actuation in the form of an actual safety
injection and main steam isolation (plant in MODE 3, trip breakers
open)
was caused
by simultaneous
conduct of unrelated activities;
one of which
created
indicated high steam line flow while the other created
low-low
average
temperature.
The following Unit 2 item is discussed
here for continuity:
(Closed)
RO 316/85037-00:
an
ESF actuation in the form of a reactor trip
from about 81 percent
power resulted
from isolation for maintenance
of a
safety instrument channel
also being used for control circuit input without
transferring control to the alternate
channel.
Each of the three items immediately above
have in common that they were
avoidable
had plant personnel
exercised
greater foresight in conduct of
activities.
The licensee
has
been requested
to specifically address
NRC
concern in this area,
in writing, in response
to IE Inspection
Reports
No. 50-315/85036(DRP);
50-316/85036(DRP).
(Closed)
RO 315/85063-00:
main steam flow transmitters.
Two
transmitters failed independently
but simultaneously,
indicating no steam
flow during a power increase.
License action requirements
were met, the
instruments
were repaired
and recalibrated,
respectively,
and returned to
service.
12
(Closed)
RO 315/85068-00:
an
ESF actuation in the form of a main steam line
isolation (plant in MODE 3) was caused
by performance of a surveillance with
temperature
below 541 degrees.
Reportability was
based solely on the lack
of prior notification to control
room operators that the actuation would
occur,
such that so far as they were concerned, it was unanticipated.
It
was considered
minor similar to
RO 315/85037-00
discussed
above.
Unit 2
(Open)
RO 316/83014-00:
No.
23 Main Steam Isolation
Valves
Dump Valve, MRV-232, removed for repair.
The repair of MRV-232
placed
No.
Stop Valve in a a less conservative
configuration than required
by Technical Specification 3.7.2.5,
however the
redundant
dump valve,
MRV-231 remained operable,
action requirements
were
.met,
and the valve',was
returned to service within, four hours.
The inspector
reviewed several,Job
Order packages'regarding
similar 'repairs to both Units
and found that three valves out of sixteen
needed repetitive repairs.
The
preventive
maintenance
program
was discussed
with plant personnel.
The
Preventive
Maintenance
(PM) procedure
for, the maintenance
department
(MHI 5030) included extensive
information on items scheduled
and frequency
of preventive maintenance,
and
has recently been
updated to reference
the
documentation
which resulted in an item being included in the Preventive
Maintenance
schedule.
However, the inspector is leaving this item open
until further details
on the preventive maintenance
program can
be reviewed.
(Closed)
RO 316/85014-00:
an, ESF actuation in the form of a safety
injection ~si nal (plant in MODE 5) was caused
by a momentary voltage drop
to two Control
Room Instrument Distribution (GRID) buses
when
a reactor
coolant
pump was started
from the
same
power source.
The CRID electrical
alignment was unique to an ongoing design
change
and would not have
been
permitted in other
MODES.
(Closed)
RO 316/85016-00:
missing seismic restraints.
In review of I. E.
and preparations
to address
questions/concerns
relating to seismic design of selected
Incore Flux Mapping
Systems
(FMS), the licensee
discovered restraint devices specified in the
original design were never installed
on the
FMS frame.
This circumstance
was unique to Unit 2,
and was expeditiously corrected, prior to .startup
from the then existing shutdown.
(Closed)
RO 316/85018-00:
an
ESF actuation in the form of a reactor trip
~si nal (plant
in,.MODE 3, but reactor trip breakers
closed)
was
caused
by
conduct of routine instrument checks
not normally performed with the trip
breakers
closed.
This event
has
no safety significance but is another
example of an "avoidable" actuation.
Note: the following four items are grouped together
due to the
interrelationship
among them; although all apply to both Units, two
were identified first and assigned
by the licensee to the Docket for
each Unit.
13
A
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L,B
1
1
(Open)
RO 316/85021-00
(applies to both Units):
failure to perform certain
instrument
channel
functional tests at the required frequency.
This matter
was originally identified in part by the
NRC and was described in the
associated
IE Inspection
Report as
an Unresolved
Item (No. 315/85028-01;
316/85028-01).
NRC has subsequently
determined this matter to be a
Violation, has
met with the licensee to discuss it, and is continuing an
evaluation relating to the choice of appropriate potential
enforcement
action.
Pending
such determination,
no Notice of Violation is being issued.
(Open)
RO 315/85043-00
and 315/85043-01
(applies to both Units): failure to
include primary sensors
in channel calibrations.
As with the above item,
NRC originally identified this item in part,
has
documented it within the
same Unresolved
Item (No 315/85028-01;
316/85028-01)
and
has since
determined it to represent
a Violation for which appropriate
enforcement
action is yet to be determined.
(Closed)
RO 315/85047-00
and 315/85049-00
(applies to both Units):
failure
to perform instrument surveillance at the required frequency.
These matters
were identified by the licensee
in performance of reviews stipulated in a
Confirmation of Action Letter (CAL) dated August 30,
1985 which was based
on the
NRC findings discussed
above.
In that appropriate
enforcement action
is being developed
concerning the similar NRC-identified matters,
no Notice
of Violation is deemed
necessary
concerning these
items identified, reported
and corrected
by the licensee
pursuant to the
CAL based
on the
NRC items.
(Closed)
RO 316/85025-00
(applies to both Units):
inadequate
control to
assure
required surveillance
completed.
This matter
was also identified,
reported
and corrected
by the licensee
pursuant to the evaluations
performed
to implement the
CAL discussed
immediately above.
(Closed)
RO 316/85012-00
and 316/85043-00:
failure to complete
compensatory
sampling within required time interval.
Each of these
events
involved late
collection of "grab" samples of the Unit 2 auxiliary building ventilation
gaseous
effluent with the automatic
sampling equipment inoperable.
Unit 2
Technical Specification 3.3.3. 10 requires
the effluent monitoring instrumen-
tation be
OPERABLE as
shown in Table 3.3-13, which lists the Unit vent noble
gas activity monitor as Item 3.a, specifying the minimum operable
channels
permissible
as
one channel.
Pursuant to Specification 3.3.3. 10, with less
than the minimum number of channels
OPERABLE, the licensee
must take the
ACTION shown in Table 3.3-13,
which is ACTION 28 in the case of the vent
gaseous
monitor.
ACTION 28 permits continued operation for up to 30 days
provided grab samples
are taken at least
once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
The first event
occurred
June 3,
1985 when
a sample required
by 5:00 a.m.
was not collected
until 5:30 a.m..
The second
event occurred
December
27,
1985 when
a sample
required
by 4:55 a.m.
was not collected until 7: 18 a.m..
In accordance
with NRC enforcement policy concerning licensee-identified violation which
should
have
been prevented
.by corrective action for previous similar
problems,
a Notice of Violation is being issued for the second
(December
27)
occurrence
(Violation 316/85004-02).
Five violations and
no deviations
were identified.
Each of the violations
were initially identified by the licensee.
One Notice of Violation is
being issued.
14
7.
Inde endent Ins ection Activities
a 0
b.
On February 4,
1986 the licensee
discovered
the Technical
Specification surveillance
"grace period" for performing
CHANNEL
CALIBRATIONS on the post-accident
monitoring instrumentation of
Table 4.3-10 (Unit 2) was about to expire.
The instruments
in this
Table were overlooked in the licensee's
request for a one-time
extension of the surveillance interval (for instrumentation
which
would otherwise
be "overdue") to February
28,
1986.
Thus, with no
time available to process
a Technical Specification
change
request,
the licensee properly declared
the instrumentation in question to be
"inoperable" effective that day.
This places
the Unit 2 plant in a
30 day Limiting Condition for Operation
(LCO); however,
since
operation
beyond February
28 is already prohibited (relates to
electrical
equipment environmental qualification issues)
the subject
LCO will not affect plant operation.
The instrumentation in question
remains functional
and is operating normally.
The following procedures
(main Control
Room copies)
were reviewed
for clarity, technical
content,
consistency,
and appropriate
administrative controls:
1 OHP 4024. 105
"Annunciator No.
5 Response
Containment
Spray"
U-1
2
OHP 4024.205
"Annunciator No.
5 Response
Containment
Spray" U-2
These procedures
are currently a combination of recently re-typed
(perhaps
word processor
based)
pages - each
page typically addresses
response
to a single alarm "window" on the panel - and what appear to
be repeatedly
photocopied
pages.
Several of the pages
in each
procedure suffer from poor legibility.
The Unit .1 procedure currently
has
seven effective change
sheets,
while the Unit 2 procedure
has only
three.
Finally, an obvious typographical error (e. g., high spent fuel
pool temperature
alarm setpoint at 18025 degrees)
on "drop 28" of the
Unit 1 procedure
had been corrected to 125 degrees
(handwritten
"correction").
The corresponding
Unit 2 setpoint
was identified as
124 degrees.
Alarms on another panel
(each Unit) also covering fuel
pool high temperature
- and there is but one pool - identify the alarm
setpoint
as
125 degrees.
Each of these
minor matters
was discussed
with the procedure co-ordinator
who is taking action to address
them.
The inspector specifically checked procedure
cross-references
to
Technical Specifications for accuracy
and found all were accurate.
C.
Observations
were
made involving plant personnel
access
controls
utilizing newly-arrived and more modern automated
metal detection
equipment at the main access
control point.
The new equipment
appeared
substantially .superior to that it replaced.
d.
Preliminary conduit layout work to support planned 'implementation,
during the upcoming Unit 2 outage,, of RFC 2808,
(replacement
of
control
room instrument distribution panels),utilizing'Job
Order
43573,
was briefly observed.
'o
violations or deviation were identified.
15
~ '
J
(
II
I
'1
4
n
U
g
~0en Items
Open Items are matters
which have
been discussed
with the licensee,
which
will be reviewed further by the inspector,
and which involve some action
on the part of the
NRC or licensee
or both.
Open Items disclosed during
the inspection are discussed
in Paragraph
5.
e
Mana ement Interview
K
4
1
I
The inspector
met with the licensee
representatives
(denoted in Paragraph
l.a above) following completion of the inspection
on February 19,
1986.
The inspection
summarized
the scope
and findings of, the inspection
as
described in these details.
a.
The two apparent Violations were specifically discussed,
including
corrective actions for the first Violation as
a basis for not
requiring a written response
(Paragraphs
2.c.
and 6.).
b.
The inspector advised the licensee that certain items identified as
Unresolved
items in Inspection
Reports
No. 50-31585028;
316/85028 are
now to be classified
as Violations.
NRC will correspond further
with the licensee
concerning
these matters at a 'future date
(Paragraphs
2.a.
and 2.b.).
The inspector also discussed
the likely informational content of the
report with respect to documents
or processes
reviewed.
The licensee
was
afforded the opportunity to identify any such document/processes
which
might be proprietary,
and
none were
so designated.