ML15224A658
| ML15224A658 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/10/1990 |
| From: | Binoy Desai, Shymlock M, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A656 | List: |
| References | |
| 50-269-90-08, 50-269-90-8, 50-270-90-08, 50-270-90-8, 50-287-90-08, 50-287-90-8, NUDOCS 9004250083 | |
| Download: ML15224A658 (13) | |
See also: IR 05000269/1990008
Text
t REQg
UNITED STATES
So
NUCLEAR REGULATORY COMMISSION
REGION II
0
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos:
50-269/90-08, 50-270/90-08, 50-287/90-08
Licensee: Duke Power Company
422 South Church Street
Charlotte, N.C.
28242
Docket Nos.:
50-269, 50-270, 50-287
License Nos.:
Facility Name: Oconee Nuclear Station Units 1, 2, and 3
Inspection Conducted:
February 18 - March 24, 1990
Inspectors:
r4 aes
/
/0 ?a
P. H. Skinner,Senior Resident Inspector
Date Signed
L. D. Wdft, Resident Inspector
Date Signed
B. B. De.di, Resident Inspector
Date Signed
Approved by:
____A0
. B. Shymlo~
Section Ch
fDate
Signed
Division of eactor Projec s
SUMMARY
Scope:
This routine, announced inspection involved inspection on-site in the
areas of operations, surveillance testing, maintenance activities,
degraded grid voltage issues, review of local public document room
and inspection of open items.
Results: A violation associated with failure to take adequate corrective
action associated with Reactor Building Cooling Unit surveillance was
identified (paragraph 3.b).
A strength was noted in the licensees continuing indepth engineering
review associated with Design Basis Documentation (paragraph 5).
900425003 90411
FDR
ADCK:'.: 0500026 9
0
.
REPORT DETAILS
1. Persons Contacted
Licensee Employees
- B. Barron, Station Manager
D. Couch, Keowee Hydrostation Manager
- T. Curtis, Compliance Manager
- J.
Davis, Technical Services Superintendent
D. Deatherage, Operations Support Manager
B. Dolan, Design Engineering Manager, Oconee Site Office
W. Foster, Maintenance Superintendent
D. Hubbard, Performance Engineer
- E. LeGette, Compliance Engineer
H. Lowery, Chairman, Oconee Safety Review Group
B. Millsap, Maintenance Engineer
D. Powell, Station Services Superintendent
- G. Rothenberger, Integrated Scheduling Superintendent
R. Sweigart, Operations Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
NRC Resident Inspectors:
- P.
Skinner
- L. Wert
B. Desai
- Attended exit interview.
2. Plant Operations (71707)(71710)
a. The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements, Technical
Specifications (TS), and administrative controls. Control room logs,
shift turnover records, temporary modification log and equipment
removal and restoration records were reviewed routinely. Discussions
were conducted with plant operations, maintenance, chemistry, health
physics, instrument & electrical (I&E), and performance personnel.
Activities within the control rooms were monitored on an almost daily
basis.
Inspections were conducted on day and on night shifts, during
weekdays and on weekends. Some inspections were made during shift
change in order to evaluate shift turnover performance. Actions
observed were conducted as required by the licensee's Administrative
Procedures. The complement of licensed personnel on each shift
inspected met or exceeded the requirements of TS. Operators were
responsive to plant annunciator alarms and were cognizant of plant
conditions.
2
Plant tours were taken throughout the reporting period on a routine
basis. The areas toured included the following:
Turbine Building
Auxiliary Building
CCW Intake Structure
Independent Spent Fuel Storage Facility
Units 1, 2 and 3 Electrical Equipment Rooms
Units 1, 2 and 3 Cable Spreading Rooms
Units 1, 2 and 3 Penetration Rooms
Station Yard Zone within the Protected Area
Standby Shutdown Facility
Units 1, 2 and 3 Spent Fuel Pool Rooms
Keowee Hydro Station
During the plant tours, ongoing activities, housekeeping, security,
equipment status, and-radiation control practices were observed.
Unit 1 operated at 100% power for the entire reporting period.
Unit 2 operated at 100% power until March 5 when Reactor Coolant Pump
2B2 experienced a low oil pot level on the motor. This resulted in
a power reduction and the pump being secured. An oil leak was
identified on a pipe flange. The licensee overtorqued the flange as
justified by an engineering evaluation, to correct the leakage
problem. Oil was added to the motor, the pump restarted and the unit
returned to 100% power on March 6. The unit continued to operate at
that condition for the remainder of this reporting period.
Unit 3 operated at 100% power until the reactor tripped due to high
Reactor Coolant System pressure on March 7 (See paragraph 2.b).
The
unit was returned to power on March 8 and remained at that level
through the remainder of the report period.
b. Unit 3 Reactor Trip
At approximately 2:06 p.m. on March 7, 1990, Unit 3 tripped from 100
percent power. The automatic trip was caused by high Reactor Coolant
System (RCS) pressure. The high RCS pressure occurred due to a
partial loss of main feedwater flow to the 'A' Once Through Steam
Generator (OTSG).
All safety systems performed as expected following
the trip.
Because of periodic spiking on Nuclear Instrument (NI) number 9, the
normal input to the Integrated Control System (ICS), NI 5 (an
available alternate NI channel) was being used to provide nuclear
power level input to the ICS.
NI 5 also provides a signal to the
RPS.
Instrument and Electrical (I&E) technicians were performing
routine online RPS testing. Part of this required manipulation of
the NI 5 signal.
In preparation for this testing, the control room
3
operators had placed certain portions of the ICS into the 'hand' mode
so that the testing would not affect the ICS.
(With these ICS
stations in 'hand', the ICS does not process the incoming signals and
will not automatically control the plant.) The operators were
manually controlling plant parameters.
During the testing, NI 5 continued to provide a signal to the main
feedwater block valve interlock circuitry. At low power conditions
(less than 25 percent power) if the startup feedwater control valves
are open, this interlock functions to shut the main feedwater block
valve. The limit switch assembly on the startup valves associated
with this interlock feature on the 'A' OTSG had previously
malfunctioned and the main feedwater block valve was receiving an
erroneous signal indicating that the startup valve was open. As a
result, when the I&E technicians decreased the NI signal to less than
25 percent, the main feedwater block valve went shut. Operators were
unable to increase the feedwater flow rapidly enough to prevent an
increase in RCS pressure and the trip occurred.
Following the trip the operators reduced turbine header pres.sure to
about 975 psi to reseat one main steam relief valve. The valves are
required to reseat within a tolerance of 93 percent of their lifting
setpoint. Post trip review verified that this valve had reseated
within the acceptance band. There were also indications of
overheating at the discharge of the condensate booster pumps (CBP)
after the trip. This had been noted during a previous Unit 3 trip.
Apparently one of the CBPs has a slightly lower discharge pressure
causing its discharge check valves to remain shut limiting
recirculation flow through the pump. The minimum recirculation
valves open on a flow signal from the discharge header of all three
pumps. It is believed that the discharge flow remained above the
recirculation valve open setpoint. Operators have been informed of
this potential problem and available corrective actions.
Also,
during the post trip review process, one reactor trip breaker was
identified as exceeding the maximum opening time interval specified
by the post trip review procedure by 28 milliseconds and was replaced
prior to startup.
The broken limit switch assembly on the 3A startup control valve was
repaired and its correct function verified. While the limit switch
had been documented as broken in December 1989, it was widely
believed that the only function of the switch was for position
indicating lights.
Its role in the main feedwater block valve
interlock had been previously overlooked and maintenance personnel
had been directed to delay its repair. The unit was returned to
criticality at 9:40 p.m. on March 7 and reached 100 percent power at
11:13 a.m. on March 8, 1990.
No violations or deviations were identified.
4
3. Surveillance Testing (61726)
a. Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy. The completed tests reviewed
were examined for necessary test prerequisites, instructions,
acceptance criteria, technical content, authorization to begin work,
data collection, independent verification where required, handling of
deficiencies noted, and review of completed work. The tests
witnessed, in whole or in part, were inspected to determine that
approved procedures were available, test equipment was calibrated,
prerequisites were met, tests were conducted according to procedure,
test results were acceptable and systems restoration was completed.
Surveillances reviewed and witnessed in whole or in part:
PT/1/A/0257/O1
Performance Testing of Unit 1/2 Low Pressure
Service Water Pumps
PT/O/A/0170/05
Penetration Room Ventilation System Monthly
Performance Test dated 5/6/88 (Unit 3)
PT/1/A/0600/13A Performance Testing of the '2B' Motor Driven
Emergency Feedwater Pump dated 3/2/90
PT/3/A/0204/07
Reactor Building Spray Performance Test
dated 9/13/88
PT/2/A/0400/07
SSF RC Makeup Pump Performance Test
dated 12/16/88
b. Thermal Performance of Unit 3 Reactor Building Cooling Units (RBCU)
Degraded Due To Fouling (61726)
On February 19, 1990, as a result of observed Reactor Building (RB)
Dome and RBCU inlet temperature increases, an entry was made into the
Unit 3 RB to conduct an investigation. Extensive boron deposits were
observed on the surfaces of the Auxiliary Cooling Units. Thermal
Performance testing was promptly conducted on the 'A' and 'C' RBCUs
on February 20, 1990. The results indicated that the 'A' cooler was
operating at about 26% capacity and the 'C' cooler at 23%. The 'B'
cooler had not been operated since unit startup in late December
1989. Available information measured during startup indicated that
it would perform at approximately 71% capacity. Design Engineering
(DE) determined that a combined performance of 82% capacity (two
worst RBCUs) was required. At 2:50 p.m. on February 20, the 'C'
cooler was declared inoperable and a 7 day LCO was entered in
accordance with TS 3.3.5. The auxiliary coolers and then the 'C'
RBCU were cleaned. The licensee has concluded that it is possible
that the 'A' and 'C' cooler combination had been inoperable for some
time in excess of 7 days before the testing and will be submitting a
voluntary 10 CFR 50.73 report.
5
Degradation in the thermal performance of the RBCUs (particularly
Unit 3) due to fouling has been a continuing problem. As early as
1986, Oconee has been investigating heat exchanger fouling problems.
Although some indications of fouled heat exchangers had been noted
during 1985/1986, it was not until early 1987 that thermal
performance testing and calculation methodology improvements
identified that some heat exchangers were fouled beyond acceptable
design values. LER 269/87-04 addressed this issue.
Operability
evaluations later revealed that all 3 Oconee units had degraded
coolers and operation at 100% power could not be supported. The NRC
issued a confirmatory order on April 10, 1987 which limited Unit 1
and Unit 2 operation with degraded cooler capability. (Unit 3 was in
an outage and cleaned the coolers prior to startup.) Meetings were
held with Region II and NRR personnel to discuss cooler fouling in
mid 1987.
In August 1988 testing indicated that the Unit 3 RBCUs were again
fouled. The licensee's operability evaluation indicated that the
coolers had degraded over operating cycle 10 to a point at which
operation at 100% power could not be supported. Testing indicated
that while some degradation had occurred on Units 1 and 2, they were
still fully operable. At this time temperature trending was being
utilized as a rough indicator of degradation with approximately
monthly testing. Based on projections utilizing conservative fouling
rates, testing frequency was shifted to preclude inoperability. Also
there was still a question if air or water side fouling was the
primary problem. Calculational and operability evaluation
methodology was actively being improved. In October 1988 an
Enforcement Conference was held concerning the Unit 3 issue. The
meeting concluded that all information indicated that the licensee's
analysis was conservative. It was acknowledged that difficulties
were present in both measurement of heat transfer in air-to-water
heat exchangers and in correlating the testing conditions to LOCA
conditions. The licensee's commitment for increased frequency of
testing to assure component operability and to perform additional
data collection was also acknowledged.
The licensee continued thermal performance testing and analysis on
the RBCUs on all three units.
As of December 1988, testing was being
performed quarterly and, in addition, at intervals determined by
previous operability assessments and conservative fouling
projections.
Improvements in testing and calculational methodology
were still being identified. In January 1989, the Unit 3 coolers
again became fouled (see LER 287/89-01). A unit shutdown and
subsequent cooler cleaning were necessary. This was attributed to
lack of information and fouling unpredictability. Also in January
1989, a task force of licensee general office and Oconee site
6
representatives was formed to address and resolve the overall RBCU
fouling issue. The resident inspectors have been closely monitoring
these efforts, by attending meetings and detailed reviews of
calculational and testing results. The licensee has expended
extensive resources in efforts to:
-
refine the calculational methodology involved
-
develop improved cleaning methods for the fouled coolers
-
determine whether air side or water side fouling is the primary
problem
-
install on-line monitoring capability, at least on Unit 3 which
has been identified as the unit most susceptible to fouling
-
determine the effect of operation of the Auxiliary cooling units
on the RBCU's
-
develop some "rough" onsite analysis capability, possibly with
data acquisition capabilities.
In February 1989, Unit 3 had remote flow and humidity monitoring
instruments installed on RB cooler ductwork. By this time Unit 3 had
been observed to undergo fouling behavior which often did not
parallel the fouling of Units 1 and 2. The reason for this
difference has not been determined. A total of 14 thermal
performance tests were conducted on Unit 3 in 1989. In April the
remote monitoring instruments for measuring relative humidity failed,
apparently due to the harsh conditions in the RB. Replacement
instrumentation was recently received and prepared for installation
but has not been installed.
Since this fouling issue was initially identified, the NRC's primary
concern and emphasis has been that the licensee closely monitor
performance to ensure operability. The licensee, through several
LER's and during meetings with the NRC, repeatedly committed to
testing as necessary to prevent operation of a unit with coolers
degraded beyond required performance levels. Projections have been
made based on conservative fouling rates and extensive resources have
remained dedicated to testing of the coolers.
As an interim measure, while additional data was being collected, two
parameters available to Control Room operators were being monitored.
These were RBCU air inlet temperature and the difference between RBCU
inlet temperature and condenser circulating water inlet temperature.
These parameters had specific limits placed on them above which
additional testing would be initiated. As additional data was
gathered and improvements were made in the testing process, these
limits were no longer used. Thermal performance testing was
completed quarterly and at intervals based on conservative fouling
rates determined by previous testing. Performance engineers, on a
7
daily basis, reviewed computer printouts of specific temperature
data.
DE had established a limit of 116 degrees F on RBCU air inlet
temperature based on a related concern. On February 20, 1990,
Performance personnel noted that the RBCU air inlet temperature was
approaching this limit and initiated the RB entry. The coolers,
however, had already degraded to inoperable levels.
Investigation by
the licensee and the resident inspectors has resulted in the
following observations:
-
The coolers had been tested in November 1989, just prior to
shutdown for a refueling outage. Based on the results, DE
projected the coolers would remain operable through at least
November of 1990. As a conservative measure, cleaning of all
the RBCUs was conducted during the outage.
Following startup
the coolers were tested again on January 9, 1990. The results
of this test indicated that the coolers had undergone
significant degradation despite their previous high capacities
and the recent cleaning. The results were attributed to
relatively low RB temperatures during the testing and the fact
that the RBCU fusible dropout plates had been reinstall-ed. It
was felt that both of these factors may have significantly
affected the testing data. A projection of operability based on
this test was not transmitted to onsite personnel.
-
No reason for the increased fouling has been identified. The
source of the boron has not been identified. RCS leakage rates
and RB sump rates have not indicated any excessive RCS leakage.
While Unit 3 underwent a trip in early January 1990, no
correlation between the increased fouling rate and the trip has
been noted.
-
While both Performance and Operations staff personnel have been
aware of steadily increasing Unit 3 RBCU inlet and RB dome
temperatures, this data along with other information which
should have alerted personnel to a potential excessive fouling
problem apparently was not adequately trended or monitored.
-
Since the susceptibility of Unit 3's RBCUs to foul has been
known for some time, a formal dedicated effort should have been
made to track all pertinent information. Apparently only an
RBCU inlet temperature limit of 116 degrees F and informal
monitoring by Performance Engineers were being utilized to
follow the RBCU concerns. Unit 3 temperatures steadily
increased for the six weeks following startup which was an
unexpected trend and, in retrospect, should have keyed personnel
to investigate closer.
The inspectors concluded that the licensees corrective actions to
prevent recurrence of fouling beyond operability limits were
inadequate. The program established to insure operability was not
sufficient in that it was not formally defined and controlled.
Additionally, the inspectors noted that the attention given to the
.program by management was less than expected since the RBCU's were
8
inoperable at the time of significant management involvement. This
is identified as Violation 50-269,270,287/90-08-01:
Inadequate
Corrective Actions to Prevent Reactor Building Cooling Unit
Inoperability Due to Fouling.
4. Maintenance Activities (62703)
Maintenance activities were observed and/or reviewed during the reporting
period to verify that work was performed by qualified personnel and that
approved procedures in use adequately described work that was not within
the skill of the trade. Activities, procedures, and work requests were
examined to verify:
proper authorization to begin work, provisions for
fire, cleanliness, and exposure control, proper return of equipment to
service, and that limiting conditions for operation were met.
Maintenance reviewed and witnessed in whole or in part:
Annual Inspection and Maintenance on Air Circuit
Breaker (ACB) Number 2
WR 55622B
Preventive Maintenance on Valve 3 PR-15
WR 55623B
Preventive Maintenance on Valve 3 PR-19
MP/0/A/2001/2
Inspection and Maintenance of Keowee ACB's and
Associated Disconnects and Bus
No violations or deviations were identified.
5. Degraded Grid Voltage Issue Identified During Switchyard Design Basis
Documentation Analysis Program (71707)
On March 1, 1990, DE identified a potential problem concerning Oconee's
offsite power supply and a degraded voltage situation. This issue was
identified during the licensee's Design Basis Documentation effort on the
230 KV switchyard system.
Normally one of the available sources of power to the Oconee Engineered
Safeguards Systems is the 230 KV transmission system through each unit's
startup transformer. This circuit is designed to be available within a
few seconds following a loss of coolant accident (LOCA). The onsite
backup source of auxiliary power (the 2 unit Keowee Hydrostation) is
available to provide power if the offsite source were to fail.
The Keowee
units can supply power to the engineered safeguards switchyard buses
through either the 230 KV switchyard isolated yellow bus, the unit's
startup transformer and its associated breakers (overhead path) or a
dedicated 13.8 KV underground circuit (underground path).
In the event
that the external transmission circuit is lost and a LOCA occurs
simultaneously, the switchyard isolation system will automatically isolate
(the under voltage setpoint is 70 percent of the 230 KV) the 230 KV safety
related yellow bus to permit one of the Keowee hydrostation units to
utilize the overhead path to provide power to the safeguards buses as
required. Additionally, the underground power path automatically becomes
9
energized as the other hydro unit is started. In summary, there are
essentially three sources of power normally available to supply power to
the engineered safeguards buses; the 230 KV transmission system via each
unit's startup transformer, the underground circuit from one Keowee hydro
unit, and the remaining Keowee unit via the switchyard yellow bus and the
startup transformer (overhead path).
The current concern is a scenario in which the external grid undergoes a
degradation which causes the voltage available at the startup transformer
to be low enough to prevent the startup transformer breakers (the "E"
breakers) from closing yet still above the Switchyard Isolation circuitry
setpoint. An undervoltage feature exists on the "E" breakers which is
intended to ensure that the engineered safeguards loads are not energized
by a source of voltage which is too low. The setpoint of this feature
corresponds to approximately 219 KV on the switchyard side of the startup
transformer when it is loaded. DE identified that if the switchyard
voltage degraded to a value of approximately 222 KV, in certain scenarios
the resultant effect of loading the transformer could result in the
E breakers not closing due to low voltage. (The plant is protected from
the degraded grid voltage in these situations since the undervoltage
feature on the E breakers will function).
But this means that the 230 KV
transmission system via the unit's startup transformer is not available at
a grid voltage of 222 KV or lower.
Technical Specification (TS) 3.7.2(i)2, states that if a startup
transformer becomes inoperable for unplanned reasons then one of the
Oconee units shall be in cold shutdown within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. It is important
to note that in the above situation, the startup transformer is inoperable
as a source from the 230 KV switchyard but it is not considered by the
licensee to be inoperable as part of the overhead path from the Keowee
hydro units. The justification for this interpretation is if the grid
degrades to the switchyard isolation circuitry setpoint, the Keowee unit
will then be able to provide power.
(TS 3.7.1(b)2 requires this overhead
path to be normally operable whenever a unit is above 200 degrees F.)
TS 3.7.2.(i)(1) requires that if a startup transformer is inoperable for
tests or maintenance, the underground feeder path must be verified
operable within one hour of the loss and every eight hours thereafter for
periods not exceeding 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
No verification of the underground path
is required by TS if the transformer is inoperable for unplanned reasons.
After continued investigation and further analysis, on March 8, 1990, it
was determined that corrective actions would be necessary. The licensee
promptly initiated specific monitoring procedures and issued guidance to
operators as interim compensatory actions concerning this issue. Guidance
was provided to the control room operators on this issue in the form of a
March 8, 1990, letter which states;
-
If voltage in the 230 KV switchyard is less that 222 KV, the startup
transformer must be considered inoperable, the appropriate limiting
condition for operation entered, and the underground path verified
operable within one hour.
10
-
A restricted change to PT/1/A/0600/01: Periodic Instrument
Surveillance has been implemented to require monitoring switchyard
voltage every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> until further analysis or modifications are
completed.
The inspectors reviewed this guidance, the required actions and the
applicable TS requirements. It appears that the licensee's immediate
actions are conservative and adequate.
The licensee has determined that on several occasions during the past 8-10
years,' Oconee has seen voltages in the 230 KV switchyard degrade to less
than 222 KV. These situations were all of short duration and the
underground power path was not inoperable at those times.
The licensee
currently intends to submit information to NRR supplementing earlier
(1979) documentation discussing Oconee's degraded grid voltage protection.
The inspectors will continue to follow the licensee's actions and are
presently discussing this issue and its implications with the licensee.
No violations or deviations were identified.
6. Public Document Room Review
The inspectors visited the Public Document Room, (PDR) for Oconee Nuclear
Station located in the Oconee County Library in Walhalla, South Carolina.
The inspectors met with the PDR librarian and discussed recent utilization
of the document room, any potential problems with maintenance of the PDR,
and current status of the PDR. The inspectors reviewed the types of
material maintained in the facility. Using the PDR indexing system,
several samples of information were located and reviewed. A random check
of numerous documents was conducted. The facility appears to be
maintained in a very organized and efficient manner in accordance with PDR
directives.
It was noted that some material dated prior to 1986 has been
relocated to the basement of the library due to spacing limitations. The
librarian stated that this material is organized and accessible if an
individual requested any of the material.
The PDR custodian appeared very
knowledgeable of her duties and highly capable of maintaining the PDR.
7.
Inspection of Open Items (92700)(90712)(92701)
The following open items were reviewed using licensee reports, inspection,
record review, and discussions with licensee personnel, as appropriate:
a.
(Closed) Violation 50-269,270,287/89-17-01: Electrical Distribution
TS Violations Due To Inadequate Procedures. The response to this
violation was contained in correspondence dated August 16, 1989.
This response included a commitment to establish a specific procedure
to address emergency power system removal and restoration by
December 1, 1989. The Operations group developed OP/O/A/1107/11,
Removal and Restoration of Auxiliary Electrical Systems, which was
reviewed by the Design Engineering electrical group, and issued
November 21, 1989. It was used during the most recent outage on
Unit 3. Based on this review, this item is closed.
11
b.
(Closed) Violation 50-287/89-36-04:
Inadequate Control of Polar
Crane Operation During Unit 3 Refueling. This violation was
addressed by the licensee in correspondence dated February 7, 1990,
and is also the subject of LER 287/89-06 dated December 27, 1989.
The corrective actions for this violation are also contained as
corrective actions in the LER. To eliminate duplicate review
efforts, the violation is being closed and licensee's actions will be
assessed during review of the LER.
c. (Closed) Inspector Followup Item 50-269,270,287/88-15-01:
Retraining
of Personnel on EPSL Operation. The licensee has conducted Emergency
Power Switching Logic (EPSL) training for the operations shift
personnel and the operations staff. The training included EPSL
logic, related LER's, the electrical TS and its interpretations, and
revised operating and performance procedures. The training was
completed on October 31, 1989.
Based on this action, this item is
closed.
d.
(Closed) Inspector Followup Item 50-269,270,287/89-05-03:
Cable
Separation Issues. This item addressed a situation of improper
routing of safety related cables. The problem was discovered during
repair work on cables following the January 3, 1989 fire in the ITA
switchgear. An operability evaluation had concluded that.the cables
in question were operable despite not being routed in accordance with
FSAR criteria. The licensee committed to rerouting these particular
cables to correct the problem and also to conduct a detailed survey
of safety related cables selected at random to ensure that the above
identified cables are an isolated case. This survey was completed in
February 1989. Of 116 cables inspected six discrepancies were found.
All were minor problems with the exception of 2 cables utilizing the
same cable room penetration (a Unit 2 Main Feeder Bus 1 cable and a
Unit 1 Main Feeder Bus 2 cable). An operability evaluation was
completed which concluded that these 2 cables are not mutually
redundant in function and simultaneous failures will not
significantly impact any Engineered Safety or Reactor Protection
System functions. A Station Problem Report (SPR-2726) has been
initiated to reroute one of the cables.
The original cable separation issue was the subject of LER 269/89-04:
Deviation From FSAR Cable Separation Criteria Due to Design
Deficiency. This LER contains several extensive, long-term
corrective actions and will be utilized to follow the licensee's
progress on this issue.
Based on this information, this item closed.
e.
(Closed) LER 269/89-01:
Reactor Trip Due to Personnel Error. This
LER was submitted to the NRC in correspondence dated February 1,
1989. The inspectors have reviewed the corrective action taken.
Modification NSM 2804, which corrected switching discrepancies of the
Main Feedwater Block Valves, was completed on February 17, June 29,
and December 17, 1989 for Units 1, 2 and 3 respectively. Based on
this review, this item is closed.
12
f.
(Closed) LER 269/89-05:
Emergency Steam Air Ejector Inoperable Due
to Defective Procedure. This LER was submitted by licensee
correspondence dated March 27, 1989. The planned corrective action
for this report was to do a random comparison of valve checklists on
selected systems for missing valves. This comparison was completed
on January 30, 1990. Several missing valves were identified and
procedures corrected as a result. These valves were all vent and
drain valves. Based on this review, this item is closed.
g.
(Closed) LER 269/89-10, Revision 2:
Central Switchyard Was Used As
An Unacceptable Offsite Power Source As A Result Of A Management
Deficiency. This LER was submitted by correspondence dated July 10,
and revised on August 9, and August 15, 1989. The inspectors
reviewed the actions taken by the licensee. Procedure changes have
been made to the specific procedure involved. In addition, a
specific procedure (OP/0/A/1107/11, Removal and Restoration of
Auxiliary Electrical Systems) has been generated, reviewed by Design
Engineering and approved by station management to preclude recurrence
of this specific problem. Based on this review, this item is closed.
h. (Closed) LER 269/89-11, Revision 1:
Technical Specification 3.7 Was
Violated as a Result of a Defective Procedure. This LER was
submitted in correspondence dated July 28, 1989. Corrective action
included a review and revision of the defective procedure and review
of other procedures associated with Emergency Power Switching Logic
(EPSL).
In addition, new procedures and revisions to existing
procedures associated with EPSL receive a review by the Design
Engineering group. Based on this action, this item is closed.
i. (Closed) LER 270/89-07: Design Oversight Results in a Potential for
Operating in an Unanalyzed Condition During a Dropped Rod Event
Concurrent With Large Tilt and Imbalance. This was a voluntary LER
submitted on January 12, 1990. The concern of this item was the
potential for operating in an unanalyzed condition during a dropped
rod event. Upon further analysis by the Design Engineering group and
discussions with Babcock & Wilcox, a determination was made that
conservatism did exist in the TS limit and the unit had not been
operating in an unanalyzed condition as previously thought. Based on
this analysis, this item is closed.
6. Exit Interview (30703)
The inspection scope and findings were summarized on March 26, 1990, with
those persons indicated in paragraph 1 above. The inspectors described
the areas inspected and discussed in detail the inspection findings. The
licensee did not identify as proprietary any of the material provided to
or reviewed by the inspectors during this inspection.