ML16341F947
| ML16341F947 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 01/16/1991 |
| From: | Morrill P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION V) |
| To: | |
| Shared Package | |
| ML16341F948 | List: |
| References | |
| 50-275-90-27, 50-323-90-27, NUDOCS 9102040051 | |
| Download: ML16341F947 (28) | |
See also: IR 05000275/1990027
Text
U.
S.
NUCLEAR REGULATORY COMMISSION
REGION V
Report Nos:
50-275/90-27
and 50-323/90-27
Docket Nos:
50-275
and 50-323
License
Nos:
Licensee:
Pacific Gas
and Electric Company
77 Beale Street,
Room 1451
San Francisco,
California 94106
facility Name:
Diablo Canyon Units 1 and 2
Inspection at:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
October
14 through December
15,
1990
Inspectors:
P.
P. Narbut, Senior Resident Inspector
K.
E. Johnston,
Resident Inspector
B. J.
Olson,
Pro ect Inspector
Approved by:
Foa
orn
,
ie
,
eac
or
rogec
s
ec ion
Summary:
Ins ection from October
14 throu
h December
15
1990
(Re ort Nos.
an
i-lt -~l
a
e
1gne
Areas Ins ected:
The inspection included routine inspections of plant
opera ions, maintenance
and surveillance activities, follow-up of onsite
events,
open items,
and licensee
event reports
(LERs), as well as selected
independent
inspection activities.
Inspect'ion Procedures
30702,
30703
35702,
37701, 40500,
61726,
62702,
62703,
71707,
71710,
83750,
90712,
92700,
52701,
92720,
and 93702 were used
as guidance during this inspection.
Safet
Issues
Mana ement
S stem
(SIMS) Items:
None
Results:.
General
Conclusions
on Stren ths and Weaknesses:
The licensee's
actions taken in response to the security diesel
electrical
panel fire were notable in that the Assistant Plant Manager
for Support Services quickly assembled
an event response
plan which
appeared to be aggressive
in pursuit of root cause,
and creative in
involving outside expertise
from the California Division of Forestry.
9102040051
9XOii6
ADOCK 05000275
8
i I
-2-
Licensee
engineering organizations
hav'e taken
a proactive
approach to
becoming involved in potential
problem areas
being worked on by the
reactor supplier
as discussed
in paragraph
4e.
The licensee
was
commended .for their program which gets the facility personnel
involved
before the reactor vendor has
made
a final determination
and issued
industry notifications.
The operations
organization
demonstrated
several
weaknesses
surrounding
the Unit 1 feedwater isolation event of December 8, 1990.
The operations
crew was not adequately
prepared with a formal strategy for dealing with
degraded
feedwater valves.
One operator's written event s'tatement
indicates
he was not even
made
aware of the valve conditions.
The
operations
crew demonstrated
a lack of proper instincts
when a second
attempt to restore
main feedwater
and continue the startup
was
made
before
management
was even notified of the event.
The
same event
revealed that the issues of why the feedwater regulating
and check valves
were leaking and where the water was go'ing were not deaTt with in a
timely manner
by the licensee.
The valves were first noted
as leaking
and causing operational difficulty in February
1990.
Indications of a lack of strong quality control organization
presence
is
discussed
in paragraph
6a.
An important feedwater flow test
was
performed without gC inspection during the test.
In addition,
gC review
of the procedure prior to the test did not identify the lack of
independent verification of important data.
This test
was considered
a
quality related job by the licensee
and was clearly important to safety
since reactor
power is determined
by the feedwater flow measurement.
Si nificant Safet
Hatters:
None.
Summar
of Violations and Deviations:
None.
0 en Items
Summar
Two followup items were'pened.
Nineteen
open items were closed.
Persons
Contacted
DETAILS
"J.
D. Townsend,
Vice President,
Diablo'Canyon Operations
8 Plant Manager
"D. B. Miklush, Assistant Plant Manager,
Operations
Services
"M. J.
Angus, Assistant Plant Manager,
Technical
Services
"B. M. Giffin Assistant Plant Manager,
Maintenance
Services
"k G. Crockett, Assistant Plant Manager,
Support Services
"M. D. Barkhuff, equality Control Manager
"T. A. Bennett,
Mechanical
Maintenance
Manager
"D. A. Taggert, Director equality Support
"T. L. Grebel,
Regulatory Compliance Supervisor
.
H. J. Phillips, Electrical Maintenance
Manager
J.
S. Bard, Planning Manager
"R.
C. Mashlngton,
Instrumentation
and Controls Manager
- J.
A. Shoulders
Onsite Project Engineering
Group Manager
M.
G. Burgess,
system Engineering
Manager
"S.
R. Fridley, Operations
Manager
"P.
M. Lang, gua1ity Control Senior
Engineer
- A. L. Young, equality Assurance
Senior Engineer
"J. J. Griffin, Regulatory Compliance Engineer
"R.
P.
Kohout, 'Manager, Safety Health and Emergency Services
The inspectors
interviewed several
other licensee
employees
including
shift foremen
(SFM), reactor
and auxiliary operators,
maintenance
personnel,
plant technicians
and engineers,
quality assurance
personnel
and general
construction/startup
personnel.
"Denotes those attending the exit interview on January 8, 1991.
0 erational
Status of Diablo Can on Units 1 and
2
Both units started the reportinq period at full power and stayed at full
power except for planned reductions for condenser
cleaning.
Another
exception occurred
when Unit 1 had a reactor trip on December
5,
1990
,due to a turbine trip caused
by an indicated,
not actual,
loss of cooling
water to the electrical generator.
The unit had .a second reportable
event
on restart
due to a feedwater isolation.
'During the report period
the Independent
Safety Committee
(mandated
by
the rate
case
settlement
had
a public meeting in San Luis Obispo
on
November
8, 1990.
On November 29, 1990,
NRC Commissioner
James
Curtiss
visited the site, toured the facility, and met with the plant management
and staff.
0 erational
Safet
Verification (71707
General
During the inspection period, the inspectors
observed
and examined
activities to verify the operational
safety of the licensee's
facility.
The observations
and examinations of those activities
were conducted
on a daily, weekly or monthly basis.
On a daily basis,
the inspectors
obsess ved control
room activities to
verify compliance with selected
Limiting Conditions for Operations
(LCOs),
as prescribed in the facility Technical Specifications
(TS).
Logs, instrumentation,
recorder-traces,
and other operational
records
were examined to obtain information on plant conditions
and
to evaluate
trends.
This operational
information was then evaluated
to determine if regulatory requirements
were satisfied.
Shift
turnovers
were observed
on a sample basis to verify that all
pertinent information of plant status
was relayed to the oncoming
crew.
During each
week, the inspectors
toured the accessible
areas
of the facility to observe
the following:
(a)
General plant and equipment conditions.
(b)
Fire hazards
and fire fighting equipment.
(c)
Conduct of selected activities for compliance with the
licensee's
administrative controls
and approved procedures.
(d)
Interiors of electrical
and control panels.
(e)
Plant housekeeping
and cleanliness.
(f)
Engineered
safety feature
equipment alignment and conditions.
(g)
Storage of pressurized
gas bottles.
The inspectors
talked with operators
in the control
room,
and other
plant personnel.
The discussions
centered
on pertinent topics of
genera] plant conditions,
procedures,
security, training,
and other
aspects
of the work activities.
On December 8, 1990, operators
experienced
a feedwater isolation in
Unit 2.
Operations
issues
were identified as
a result of this event
and are described in detail in paragraph 4j of this report.
Radiolo ical Protection
The inspectors periodically observed radiological protection
practices to determine whether the licensee's
program was being
implemented in conformance with facility policies and procedures
and
in compliance with regulatory requirements.
The inspectors verified
that health physics supervisors
and professionals
conducted frequent
plant tours to observe activities in progress
and were aware of
significant plant activities, particularly those related to
radiological conditions and/or challenges.
ALARA considerations
were found to be an integral part of each
RMP (Radiation Mork
Permit).
Ph sical Securit
(71707)
Security activities were observed for conformance with regulatory
requirements,
implementation of the site security plan,
and
administrative procedures
including vehicle and personnel
access
screening,
personnel
badging, site security force manning,
compensatory
measures,
and protected
and vital area integrity.
Exterior lighting was checked during backshift inspections.
No violations or deviations
were identified.
4.
Onsite Event Follow-u
(93702)
a.
b.
Continuin
Ventilation Fan Ino erabilit
Problems
On October 22, 1990, auxiliary building supply fan S-31 failed to
start
due to the outlet damper position switch needing adjustment.
Also, on this day the fuel handling building supply fans were
due to discharge
damper problems.
Various ventilation
fan problems
have plagued the licensee
in the past
on a continuing
basis.
The inspectors
had discussed
the apparent
need for a
comprehensive
review of ventilation problems
and implementation of
corrective action.
Previous actions
were to assign
a system
engineer to ventilation problems.
The ongoing nature of the
ventilation problems indicate comprehensive
actions
have not been
taken or were not effective.
On October 22, the assistant
plant
manager for Operations
stated that the need for comprehensive
action
had been discussed with the plant manager
on that date.
Additional
ventilation fan problems occurred throughout the report period.
Fan
E-2, an auxiliary building exhaust fan, failed to auto start during
testing
on December 30, 1990, following the end of the report
period.
The subject
was again discussed
at the exit interview held
on January 8, 1991.
The licensee
management
stated
they considered that significant
progress
had been
made in improving ventilation reliability, but
that they would revisit the comprehensiveness
of their program.
The licensee's
action reqarding ventilation problems will be
followed up in a future inspection
(Followup Item 50-275/90-27-01).
Reactor Coolant Differential Tem erature
Dro
On October 25, 1990, the licensee
noted that Unit 1 reactor coolant
differential temperature
(delta T) at an indicated
100K power had
dropped
between
3X and 4X since the beginning of the fuel cycle.
This led to licensee
concern with the adequacy of the overpower
and
overtemperature
delta T (OPDT and OTDT) reactor trip setpoints,
which were established
at the beginning of the fuel cycle.
OTDT is a reactor trip setpoint
based
on a function of three inputs;
RCS pressure,
'RCS average
temperature
(Tave),
and core axial flux
difference.
The setpoint is compared to a delta
T. input scaled to
represent
percent power.
As the actual delta T at .100power
has
dropped over the core cycle, the difference between the
setpoint
and delta T has increased.
This was also true for the
OPDT
setpoint.
II
The licensee
has not determined the cause for the apparent delta T
drop to date.
Once licensee
and Mestinghouse
theory is that delta T
has apparently
dropped
due to thermal stratification of the reactor
coolant
as it leaves
the core
and enters
the hot legs.
The second theory was that,
due to feedwater
nozzle fouling with
time, the indicated reactor
power,
as calculated
by heat balance,
has
gone
up causing the licensee to reduce actual
power and actual
reactor coolant delta T.
This theory is supported
by a reduction
with time of the output electrical
megawatts
and by history at other
sites.
The theory is refuted by a high accuracy lithium tracer test
.(discussed
in section
Ga of this report) which indicates the
feedwater nozzles
are not fouling at Diablo Canyon.
The licensee initiated
NCR DCO-90-TN-077 to review the problem.
The
inspector will followup the licensee's
actions regarding this matter
and other related matters (venturi fouling and
RCS thermal
stratification) during routine inspection.
Initial indications were
that the
OPDT and
OTDT setpoints
were valid as set.
Letdown Line Socket Meld Leaks
On October
30, 1990, operators identified a leak in the Unit 2
chemical
and volume control system
(CVCS) letdown line.
The leak
was in an elbow socket weld downstream of the "C" line flow orifice.
Operators
suspected
the ]eak following an increase
in containment
radiation levels
and
an increase
in measured
leakage.
This was the third occurrence
of a crack in a letdown line socket
weld.
On December 4, l990, yet another crack was discovered
on the letdown
line downstream of orifice "C".
This coupling socket weld has only
been welded since
November
as
a result of the October 30 weld leak
repair.
An NRC Regional welding inspector
and a consultant metallurgist were
brought in to perform a detailed 'inspection of the letdown line
problems
and the licensee actions.
The results of their inspection
are published in Inspection Reports 50-275/90-31
and 50-323/90-31.
It should
be noted that licensee
actions to address
weld cracking
issues
were slow.
The licensee
had been
asked in July 1990,
subsequent
to feedwater piping leaks, to perform a comprehensive
review of weld leaks at Diablo Canyon (reference
Inspection Report
Item 50-275/90-15-02).
The report was prepared
on August 3, 1990,
and provided to the
NRC resident inspector in December.
The report concludes
fatigue is the dominant failure mechanism.
However the report, which provides data
on 40 weld failures at the
site, cateqorizes
many weld failures
as caused
by "fatigue," but at
the
same
tsme
shows that no metallagraphic
examination
was done.
The inspector
asked the licensee to provide the rationale for the
P
"fatigue" categorization.
The information was requested 'at an exit
meeting he'ld on December
13, 1990,
and had not been provided as of
January 8, 1991.
At the exit meeting
on January 8,'991,
the inspector
requested
the
licensee
to provide the information and the licensee
stated
the
information would be provided soon.
Fire in Securit
Diesel Electrical
Panel
On November 19, 1990, the plant experienced
an electrical fire in
the security d>esel
generator
area.
The fire was later determined
to be caused
by a loose electrical
connection in a circuit breaker
cabinet.
The licensee's
response
to and investigation of the event
were good and included the use of a California Division of Forestry
expert in electrical fires causes.
As a result of the investigation it was determined that
some
sprinkler heads just outside of the area
were clogged with silt and
would not have functioned if required.
The inspector evaluated
the situation, it's cause
and the licensee's
lanned actions
and concluded the actions
were adequate.
The
icensee
is tracking the corrective actions through the
nonconformance written as
a result of the fire.
Im roved Communication with the Reactor
Desi ner
On November
21, 1990, the assistant
plant manager for Technical
Services
and representatives
of the general office engineering
management
made
a presentation
to the senior resident inspector.
The licensee
discussed their program for improved communication with
the reactor vendor.
The basic
improvement
was for the licensee's
engineering organization to be involved in potential developing
issues with the vendor, rather than waiting for the issue to
finalize and be issued in the form of a written notification.
At the exit interview the licensee
was
commended for this pro-active
program.
Loss of Power to Uninterru table
Power
Su
l
On November 26, 1990,
an uninterruptable
power supply was
interrupted.
The interruption occurred
subsequent
to an electrical
disturbance
in a 500 kv line off site.
The uninterruptable
power
source supplies
power to the chemistry lab and the Accident
Mitigating System Actuating Circuitry (AMSAC) for both units.
is the Westinghouse
de'sign
improvement in response
to the
anticipated transient without scram
(ATWS) initiative.
AMSAC does
not require
a safety related
powered supply, but was required to
have
a reliable power source.
There were
no operational
consequences
to, the event or actuations of safety systems.
The licensee
made several
observations
from the event:
o
Operators
had difficulty in identifying the power source for
ANSAC.
The licensee therefore
concluded that increased
emphasis
in the preparation of the "fed from" list was
warrante'd.
This list was committed to be generated for
operator
use
due to previous'ifficul.ties and is due in Narch
1991.
o
The uninterruptable
power source didn't have adequate
batterv
maintenance
or periodic testing.
The licensee
stated that this
will be corrected.
o
The annunication logic indicated "tripped" vice "trouble,"
which the operators
considered to be .misleading.
The
operations
department
intends to revise the annunicator
response
procedure to indicate
when the response'ould
be
expected.
o
The operators
consider
the provision of power to both
units'HSAC
from one power source to be a design
weakness
(due to the
potential for the inadvertent loss of both units output).
The
followup engineering evaluation concluded that the potential
for the loss of both units was not a concern.
g.
Cutie'r Hammer Rela
s
On November 27, 1990, the licensee
investigated
the potential for a
generic
problem with Cutler Hammer relays,
which are
used in many
systems
throughout the plant.
The switches allow for various combinations of normally open
and
normally closed contracts
to be assembled
in one relay by the
customer.
The manufacturer
provides specific instructions
as to
which contacts
can be inserted in which holes in the relay.
Diablo
Canyon had apparently not followed the manufacturer's
instructions
in all cases.
The inspector
observed portions of the licensee's
inspection.
The issue
became
moot when the manufacturer
performed testing
and
determined that their precise instructions
were not necessary
and
that the Diablo configurations
were satisfactory.
At the exit the inspector requested
documentation of the vendor's
f'inal opinion (followup item 50-275/90-27-02).
h.
Commissioner Visit
On November 29, 1990,
Commissioner
James
Curtiss visited Diablo
Canyon.
The Commissioner toured the site and met with licensee
management
representatives.
Unit 1 Reactor Tri
On December 5, 1990, Unit 1 experienced
a reactor trip due to a
The turbine trip was preceded
by a turbine runback,
both of which were caused
by indications of a loss of cooling water
flow to the electrical
generator stator.
The indication of a loss
of .stator cooling water flow was due'o
a damaged flow switch.
Further details
on the trip are available in the licensee's
event
report
LER 1-90-14.
The inspectors
examined the damaged flow switch and followed
licensee
actions
and found them'o
be generally adequate.
The
inspectors will continue to followup the licensee's
actions through
the
LER process.
At the exit interview, the 'inspector discussed
the occurrence of a
miscommunication to the
NRC regarding
a misassembled
agastat
relay,
which prevented
the circulating water pump from automatically
starting following the trip.
The licensee
had reported the problem
to be
a vendor error, which subsequently
was determined to be
a
licensee error due to a lack of instructions.
The inspector noted
to the licensee
an apparent
growing number of verbal inaccuracies.
The licensee
was unable to determine
how the misinformation was
assed to the reporting shift supervisor.
The licensee
did correct
he 10 CFR 50.72 on December
18,
1990.'n
additional problem during this trip was the fact that operators
had to close
a motor operated
valve due to a combination of severely
leaking feedwater regulating
(FH530 and 1530)
and check valves
(FM-531) on steam generator
1-3.
The level oscillations
were
controlled in this case.
Plant management
addressed
the issue of
severely leaking valves
and determined that corrective maintenance
action was not required.
This decision contributed to the next
event described
below.
Isolation
Unit 1
On December 8, 1990, during the reactor restart from the December
5
trip, Unit 1 experienced
a P-14 feedwater isolation and feedwater
pump turbine trip from Mode 2, 2X power.
This is an Engineered
Safety Feature
(ESF) actuation
and was duly reported to the
NRC.
The automatic feedwater isolation occurred
due to high steam
generator water level in steam generator
1-3.
The events preceding the isolation were that Unit 1 was in Mode 2
(startup) at approx>mately
2X power.
Plant startup
was in progress
an accordance
with operating procedure
L-3, secondary plant startup.
The control
room operators
had just completed placing all main
feedwater regulating
and bypass
valves in automatic control,
and had
placed
main feedwater
pump 1-2 in service with pump speed
adjusted
so that the feedwaterlmain
steam differential pressure
was
approximately
0 psid.
The control
room operators
noted that steam generator
(SG) l-3 was
indicating a decreasing
level trend, with auxiliary feedwater flow
reater than the other three
This problem was
iagnosed
as back-leakage
through the main feedwater
FM-1-531, which had been
a recurring problem under conditions where
low differential pressures
existed across
the check valve.
The
condition also indicated
leakage past the feedwater regulating
valves.
'
Note:
The licensee finalized their theories
as to where the
1-3 water was going on December
21, 1990,
A walkdown revealed
back leakage to the condenser,
which had apparently existed
since at least February 20, 1990,
when the first operational
difficulties were encountered.
To correct the low steam generator
level problem, the operators
increased
speed
on main feedwater
pump 1-2 (which was the next step
in the startup procedure)
to correct the back-leakage
problem and
allow steam generator
1-3 to be fed from the main feedwater
system.
The level in steam generator
1-3 rapidly increased
beyond its normal
no-load level setposnt.
The control
room operators
took manual
control of FCV-1530, the main feedwater regulating valve bypass
valve to steam generator
1-3,
and decreased
the controller demand
below the normal "closed" output.
This action terminated the
initial steam generator
level increase.
Operators
then discussed
the situation with the onshift supervisor
and foreman
and attempted
the evolution again.
This time a
different main feed
pump speed
was set to provide
a lower pump
discharge
pressure
than that stated in the licensee
procedure,
OP-L-3.
Note:
The procedure
provides
some latitude for deviation in
step 1.2, but the inspector considered that the operati'ons
personnel
went too far when they deviated without management
consultation.
The assistant
plant manager for operation
concurred with the inspector.
A subsequent
review of the event found the following:
Back-leakage
through main feedwater
contributed to this event.
The back leakage through the check valve was due to apparent
misassembly
on November 9, 1999, during the last refue'Iing
outage.
The valve was inexplicably satisfactorily blue checked
for seat leak tightness at that time.
The back leakage through the feedwater regulating valves
was
not understood
and was accepted
as "normal" for regulating
valves in control
mode by p]ant personnel
and management.
The
valves .do close
more tightly in the "tripped" mode when all air
is bled-off the air actuator.
The valve leakage
was originally noted following a reactor trip
on February 20, 1990,
and again
on February 22, 1990, during a
restart from that tr>p.
UI'J
I
The operations
crews actions
were as follows:
o
At 0145 hour0.00168 days <br />0.0403 hours <br />2.397487e-4 weeks <br />5.51725e-5 months <br />',
1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 14 minutes after the event,
the
operators
successfully transferred to main
from auxiliary feedwater.
At 0146 hours0.00169 days <br />0.0406 hours <br />2.414021e-4 weeks <br />5.5553e-5 months <br />,
operators
made the report to
NRC duty officer
per 10 CFR 50.72.
At 0149 hours0.00172 days <br />0.0414 hours <br />2.463624e-4 weeks <br />5.66945e-5 months <br />, the operations
manager
was notified.
'0
At 0154 hours0.00178 days <br />0.0428 hours <br />2.546296e-4 weeks <br />5.8597e-5 months <br />, the assistant
plant manager for operations
was
notified.
o
At 0157 hours0.00182 days <br />0.0436 hours <br />2.595899e-4 weeks <br />5.97385e-5 months <br />, the
NRC senior resident
was notified and asked
whether
management
had concurred with the
restart
and received the negative reply.
o
At 0200 hours0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br />, the plant manager
was notified.
Several
noteworthy items were identified as
a result of this event.
o
Although the P-14 feedwater isolation interlock is primarily to
protect the turbine from water carry-over
damage
versus
a
reactor safety function, the fact that it is an
ESF reportable
actuation
suggests
that the underlying causes
of the actuation
and the adequacy of corrective actions
be reviewed by
management prior to a second start-up attempt.
Hany details of why the feedwater valves
are, leaking and where
the water was going were not understood
by the licensee
and
were not pursued aggressively in post trip outages
in February,
June,
and December.
The operating
crews were not adequately
prepared with a formal
strategy for dealing with degraded
feedwater valves.
Proceduralization
and training appear to be needed.
Licensee actions to date
have been:
o
The assistant
plant manager for operations
has briefed all
crews regarding the need for management
consultation prior to
~
~
~
roceding with restart attempts after events
such
as occurred
ere.
o
Check valve FM-531 was disassembled
and properly reassembled
following the December
24
1990
regulating bypass valve FkV-1533 was disassembled
and made
relatively leak tight also during that outage.
Valve FW-530
was worked, but stall apparently
leaks.
Valve
FCV". 420 to the
condenser
was not worked and still apparently
needs
readjustment,
but was manually isolated
on December 21, 1990.
4
10
o
The licensee
prepared
a nonconformance
report,
DC 1-90-0P-N083.
As of January 5, 1991, the nonconformance
was not complete
and
did not contain the management
issues
of inadequately
informed
crews
and crews proceeding 'in the face of uncertainty without
management
concurrence.
The licensee's
LER issued
January
7, 1991, likewise did not address
the two management
issues
and the LER's stated root cause,
that the
valves leaked,
was not very insightful.
At the exit interview on January 8, 1991, the inspector discussed
the event, the two management
issues,
and root cause of the
LER.
No violations or deviations
were identified;
Maintenance
62703)
The inspectors
observed portions of, and reviewed records
on
selected
maintenance activities to assure
compliance with approved procedures,
technical specifications,
and appropriate
industry codes
and standards.
Furthermore,
the inspectors verified that maintenance activities were
performed by qualified personnel,
in accordance
with fire protection
and
housekeeping
controls,
and replacement
parts were appropriately
certified.
The inspectors
examined maintenance activities associated
with the events
and occurrences
described in section
4 of this report.
In particular the
inspectors
reviewed the maintenance activities associated
with fan
maintenance
(paragraph
4a), socket
we')d leaks
and repair (paragraph 4c),
electrical
panel repair (par agraph 4d), uninterruptable
power supply to
AMSAC (paragraph 4f), Cutler Hammer relay inspection
(paragraph
4g),
stator cool1n
flow switch repair and agastat
relay replacements
paragraph 4i
, and check valve repair and valve positioner maintenance
paragraph 4j .
No violations or deviations were identified.
Surveil 1 ance
61726
By direct observation
and record review of selected
surveillance testing,
the inspectors
assured
compliance with TS requirements
and plant
procedures.
The inspectors verified that test 'equipment
was calibrated,
and acceptance criteria were met or appropriately dispositioned.
The inspectors
examined surveillance tests
associated
with the events
and
occurrences
described in paragraph
4.
Specifically, the inspectors
examined the surveillance test aspects
of ventilation fan problems
(paragraph
4a),
heat balance testing (paragraph
4b), fire sprinkler
testing
(paragraph 4d),
and uninterruptable
power supply testing
(paragraph 4f).
11
Flow Verification Test
Unit 2
On. November 14, 1990,
a lithium tracer test
was performed to verify
the accuracy of flow indications that are obtained
using the
feedwater flow nozzles to the four steam generators.
The test was
performed
due to a concern that the feedwater flow nozzles
could be
fouled and result in a higher indicated flow than actual.
A higher
indicated feedwater flow results in calculated reactor
power
besna
greater
than actual reactor power.
This is a financial loss to the
utility and not a safety concern.
However, the licensee
could use
the test results
as
an input to their nuclear instrument adjustment
procedure,
and the test therefore
was of safety significance.
The tracer test performed
by a vendor,.consisted
of injecting
lithium nitrate into the feedwater
system just downstream of the
main feedwater
pumps.
Samples
were drawn upstream of the feedwater
pumps
and were analyzed to establish
background conditions.
Forty
samples of feedwater were drawn downstream of the injection point.
The vendor
analyzed the forty samples to determine the lithium
concentration.
Feedwater flowrate was calculated
usina the results
of the analysis
and the
known lithium injection flowrate and
concentration.
On November 13, 1990, the inspector
observed
a briefing conducted
by
the test director.
The test
was described,
personnel
responsibilities
were defined
and test equipment
was sighted.
On
November 14, 1990, the test director conducted
a pretest briefing to
address
communication
and coordination issues.
The
inspector'bserved
performance of the test.
In conjunction with the tracer
test,
the licensee
also obtained feedwater flow data from hiqh
accuracy differential pressure
detectors that were temporariTy
installed in parallel with the detectors
normally used for feedwater
flow measurement.
4
The inspector noted that the vendor provided a timer and weight
scale
used to c'alibrate the lithium injection pump.
The calibration
consisted
of adjusting
pump discharge,
timing pump operation,
and
weighing the amount of tracer discharged.
Once the pump,was
adjusted,
the timed discharges
were repeated
to ensure
pump
consistency.
The vendor supplied calibration data for the timer and
used calibrated weights to check the scale.
No calibration data was
available for the scale.
The licensee
indicated that the
calibration data would be obtained
from the vendor.
The inspector
also noted that the vendor recorded all of the data
used to
calibrate the injection pump without independent verification by the
licensee.
The licensee
was questioned:
as to why equality Controi
(gC) was not involved to independently verify data
used to perform
the injection pump calibration.
In a discussion after the test
was
performed,
the
gC manager indicated that the vendor
had been
qualified by the licensee,
and additionally gC involvement was not
considered to be required.
The inspector stressed
that as the test
was not routinely performed
and the results affect the calculation
for reactor power, that independent verification of test data
appears
to be warranted.
The test director indicated that
independent
engineering verification could have
been performed
and
the verification would be considered for any future performance of
the test.
equality control indicated
on Janury 7, 1991, that the
gC
verification section would be given additional'uidance
on when to
get involved and
on when to invoke independent verification.
On December
3, 1990, the licensee
indicated that the preliminary
results
from the tracer test were available.
The test results
indicate that feedwater flow as calculated
by the test closely
matched feedwater flow as measured
by both the normal
and
temporarily installed differential pressure
detectors.
These
results indicate feedwater nozzle fouling has not occurred contrary
to previous suspicions.
The licensee is currently assessing
the
test results.
No violations or deviations
were identified.
7.
Licensee
Event
Re ort Follow-u
(92700
a.
Status of LERs
The
LERs identified below were closed out after review and follow-up
inspections
were performed by the inspectors to verify licensee
corrective actions:
Unit 1:
83-37, 84-42, 84-43, 84-44, 84-45, 88-25 Rev.l,
90-05, 90-07,
90-10
Unit 2:
83-37, 84-42, 84-43, 84-45, 88-23 Rev.l, 90-03,
90-05,
90-06,
90-06
Rev. 1, 90-07
No violations or deviations
were identified.
8.
0 en Item Follow-u
-(92703
92702
a.
Unit 2 Main Steam
Pi
e Movement
Followu
Item 90-19-01 (Closed)
The inspector
had questioned
the relatively large pipe movements
experienced
in the Unit 2 restart.
A meeting was held with the
licensee
on November
21, 1990, in which the licensee
presented
analysis
which adequately
explained. the pipe movement.
This item is
considered
closed.
9.
Exit (30703)
On January 8, 1991,
an exit meeting
was conducted with the licensee's
representatives
identified in paragraph
1.
The inspectors
summarized the
scope
and findings of the inspection
as described in this report.
I