ML15224A582
| ML15224A582 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 09/07/1989 |
| From: | Shymlock M, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A580 | List: |
| References | |
| 50-269-89-25, 50-270-89-25, 50-287-89-25, NUDOCS 8909150070 | |
| Download: ML15224A582 (11) | |
See also: IR 05000269/1989025
Text
,t
REG(,
UNITED STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos:
50-269/89-25, 50-270/89-25, 50-287/89-25
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
Inspection Conducted: July 17 - August 19, 1989
Inspectors: .
,
(7
,-
--
Ff)
P. H. Skinner, Seni
Resident Inspector
Date Signed
lieI '2( /~
_")2C
L. D
r, Reside
Inspector
Date Signed
Approved by:
97-9
M B. S
Section Chief
Date Signed
ivision of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection involved resident inspection
on-site in the areas of operations, surveillance testing, maintenance
activities, facility modifications, loss of decay heat removal (GL 88-17) actions, electrical power system self initiated technical
audit and design basis documentation analysis, and inspection of open
items.
Results:
During this period the inspectors noted a weakness in the licensees
program to take appropriate action to assure problems of a similar
nature do not recur and also a weakness in the maintenance of
physical examinations for licensed operators. A strength was noted
in the area of control of activities during the period of the time a
unit is in mid-loop operation as addressed by Generic Letter 88-17.
8909150 070 890808
ADOC:K 05000269
Q
FC
REPORT DETAILS
1. Persons Contacted
Licensee Employees
- M. Tuckman, Station Manager
- S. Baldwin, Compliance
C. Boyd, Site Design Engineer Representative
- T. Curtis, Compliance Manager
- J. Davis, Technical Services Superintendent
D. Deatherage, Operations Support Manager
W. Dukes, Medical Doctor
W. Foster, Maintenance Superintendent
T. Glenn, Instrument and Electrical Support Engineer
- D. Havice, Instrument & Electrical Engineer
D. Hubbard, Performance Engineer
E. Legette, Assistant Engineer Compliance
- H. Lowery, Chairman, Oconee Safety Review Group
- 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.H. Skinner
- L.D. Wert
- Attended exit interview.
2. An Unresolved Item is a matter about which more information is required to
determine whether it is acceptable or may involve a violation. There was
one unresolved item identified in this report (paragraph 3.b).
3. Plant Operations (71707)
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, 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
week days and on weekends.
Some inspections were made during shift
change in order to evaluate shift turnover performance.
3
told that this was covered by Corporate Medical Guidelines.
The
station up until 1984, had Station Directives to address this process
but at that time the medical groups at all sites were shifted to the
direction of the corporate office.
At that time the Station
Directive was deleted. The medical exams were not a problem prior to
1984 since at that time it
was a part of the application for a
license renewal every two years, but when this was changed provisions
for assuring this was done appear to have been inadequate.
A system had been established by corporate to list all Duke required
physicals (crane operators, fire brigade members, licensed operators,
asbestos handlers, etc.)
on a computer system, but it
appears that
this system was incorrect and inefficient in that many operators were
getting as many as three physicals a year (license, fire brigade, and
respirator).
As a result the licensee was
in the process of
correcting this inefficiency when the problem of missed medical
examinations was identified.
Medical
personnel
responsible for
maintaining
operator records would send notification to
the
operations supervision for supervisors to schedule examinations for
their personnel.
Since these notifications did not contain dates the
supervisors did not know that the operators had exceeded their
required dates. Review of the information provided to the operations
department indicated that the operators did obtain their physicals
upon notification by the medical department.
A computer program has now been established on site in the medical
facility that has a list of all operators and the dates that their
physicals are due.
This list has also been provided to the
supervision of each of the groups that has licensed operator
personnel that maintain their license. Another factor affecting this
process was that supervision normally scheduled the medical
examinations for the operators without notification to the operator
concerned until three days prior to the exam.
This was due to the
company policy associated with drug testing.
Although the operators did not get the required medical examinations
during the prescribed period, each did have a physical conducted by a
nurse. This 'nurse physical'
is comprehensive and includes most
checks provided in the physical given by the doctor except for X-ray,
EKG,
blood work, and drug screening.
In addition, if
problems are
identified during the 'nurse physical' the individual is required to
see a doctor. Discussions were held with the doctor that provides
these examinations concerning the individuals that had exceeded their
time intervals. None of these persons had any problems that would
have prevented them from fulfilling their watchstanding duties.
10
CFR 50.54(k) requires
an operator or senior operator licensed
pursuant to Part 55 to be present at the controls at all times during
operation of the facility. 10 CFR 55.21 requires a licensed operator
to have a medical examination by a physician every two years to
determine
that
the
operator
meets
the
requirements
of
10 CFR 55.33(a)(1). Pending further review of these requirements
4
by
this
will
be
identified
as
an
Unresolved
Item
50-269,270,287/89-25-01:
Apparent Failure to Provide
Personnel
Licensed Pursuant to 10 CFR 55 at the Controls at All Times During
Operation of the Facility.
c. Unit 1 Reactor Trip From 40% Power
On August 10,
1989, Unit 1 tripped from 40% full power at 3:41 p.m.
The plant responded as expected. Two main steam relief valves did
not reseat as expected and header pressure was reduced to
approximately 970 psig to allow the valves to reseat.
Upon
evaluation, the licensee determined that the valves reseated within
the prescribed operating tolerance of the valves.
The unit was
returned to critical operation at 9:10 p.m.
on August 10 and was
restored to 100% power operation on August 11.
This trip was caused
by an Instrument and Electrical (I&E) technician placing two Reactor
Protective System (RPS)
channels in a tripped condition at the same
time.
The inspectors reviewed this occurrence in detail.
The
sequence of events was the following:
At approximately 7:00 a.m.
on
August 10,
a low oil level alarm was received on the 1A2 reactor
coolant pump (RCP) motor. The licensee commenced a power reduction
at 7:45 a.m. in order
to
remove
the pump
from service.
At
approximately 10:00 a.m.
the pump was secured and the unit was in
operation in a three pump configuration. At noon the plant exceeded
the steady state quadrant power tilt
(QPT)
limit specified in
TS 3.5.2. Corrective actions were commenced by operations at that
time to try to reduce the QPT to the limits allowed by TS.
At
2:05 p.m. maintenance personnel had entered containment, added oil to
the RCP motor and the pump was restarted.
Also at approximately
2:00 p.m.,
the operators had not been successful in restoring the
QPT, so I&E was contacted to reduce the RPS Nuclear Overpower Trip
Setpoints according to the
requirements of
TS 3.5.2b.2.
I&E
personnel performed procedure IP/O/A/0301/003U,
Procedure To Reset
The Flux/Imbalance/Flow
and High Flux Trips For Operation With
Excessive Power Tilt Or Other Conditions, to adjust the RPS for this
condition.
Discussions with various operating and
IE personnel
identified the following points:
-
The procedure used for this activity is a very complex procedure
-
several
time
consuming calculations prior to actual
manipulations of the RPS controls.
-
It
has been used infrequently and a minimum number of I&E
personnel are qualified to perform this activity.
-
Sign offs in the procedure for step tracking are infrequent.
-
Several steps have multiple action steps within the step.
In addition to the problems described above with the procedure and
personnel qualifications, the individual performing the procedure
6
EHC trip circuitry and shorted out some components causing the loss
of EHC signal.
The plant responded normally to the trip although one
main
steam relief valve . (3MS-6)
did not reseat properly
and
operations personnel
had to reduce main steam header pressure to
approximately 970 psig to reseat the valve.
The licensee dried out
the panel,
replaced the faulted components in the EHC system and
restarted the unit.
The unit was taken critical at 5:47 p.m.
and
returned to 100% at 6:15 p.m. on August 19. The relief valve has
been identified as a work item for the upcoming outage presently
scheduled to start on November 15, 1989.
One violation was identified.
4.
Surveillance Testing (61726)
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 witnessedin whole or in part:
WR 57855A
Perform Test on Keowee Line Relays (Annual Testing)
(21L1,50P,51,50,51G,67G,87L,74PW)
PT/O/A/0610/02
Electrical Grid Trouble Protection System Logic
and Switchyard Isolation Testing
MP/1/A/2200/06
Inspection and Maintenance of Keowee Unit 1
Permanent Magnetic Generator
IP/3/A/305/9
RPS 'A' Main Feedwater to Main Turbine Trip
Calibration
PT/1/A/0202/11
High Pressure Injection System Performance Test
IP/0/A/0310/013C
Engineered Safeguards System Logic Subsystem 2 RB
Isolation and Cooling Channel 6 On Line Test
(Unit 3)
IP/1/A/0305/001E
Reactor Protective System Channel 'A' RC
Temperature Instrument Calibration
No violations or deviations were identified.
5. Maintenance Activities (62703)
a. 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,
7
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:
WR 55162B PM Control Rod Drive Breaker for Units 2 & 3 AC-3
WR 55406B PM Control Rod Drive Breaker for Units 2 & 3 AC-6
WR 22434C Investigate lB LPSW Pump Abnormal Start
WR 22405C Repack Outboard Rearing LPSW Pump 2B
b.
Inadequate Retesting of Valve 3LWD-1 (62703)
On August 11, 1989, the licensee discovered that valve 3LWD-1 (Normal
Reactor Building Sump Suction, Unit 3) had been returned to service
following maintenance without all required retests having been
performed. The torque switch on the valve's operator had
been
adjusted and no leak rate test was performed before this Engineered
Safeguards Containment Isolation valve was returned to service. The
leak rate test is required by TS 4.0.4 which requires testing in
accordance with Section XI of the ASME Code.
The leak test was
subsequently
performed with satisfactory results.
Since this
incident is similar to a previous
issue (LER
269/88-01:
TS
Violations Due to Missed ASME Section XI Testing Resulting From
Management Deficiency), involving valve 1RC-7, the
inspectors
examined the circumstances in detail.
At Oconee, the control and
planning of maintenance including
retesting
requirements
is
accomplished through the Work ,Request (WR)
process.
SD 3.2.1: Work
Request, and Maintenance Directives (MD) 7.5.1 through 7.5.5 contain
most of the applicable guidance concerning WRs.
The root cause of
the 1RC-7 incident as stated in the LER was a management deficiency
due to the failure of management to insure the proper implementation
of the station WR program used to control the work on 1RC-7. Several
problems including inadequate training, failure to follow WR
procedures,
problems
with
the
directives,
and
inadequate
communications
caused that
incident.
The
LER
states
that
programmatic problems associated with the directives and individual
groups methods of implementing these directives caused the majority
of the mistakes. Numerous corrective actions were identified and
implemented.
After investigation,
the inspectors
concluded that the
incident occurred primarily due to a miscommunication between the job
supervisor and the Performance
(PE)
representative concerning the
scope of the maintenance actually performed on the valve.
Although
the fact that adjustment had been made to the torque switch is
clearly documented in the "action taken" section of the WR,
a phone
conversation between the job supervisor and PE failed to communicate
to
that the torque
switch
had
been adjusted.
This PE
representative was well aware of the 1RC-7 incident and its causes.
9
NSM 2458 AL Replace Valves 2FDW-107 and 2RC-7
NSM 2458 AM Replace Valves 2FDW-107 and 2RC-7
NSM 2759 AK1 PORV Low Range Pressure Control Instrumentation
NSM 2755 AL1 Replace Pneumatic Control Loop For PORV (RC 66) With
Electrical Current Control Loop and Add Time Delay
Two areas of concern were identified associated with returning a system to
operation following a modification.
These were training provided to
operations personnel and interim drawings potentially needed by operations
upon restart of the system.
These problems were recently identified by
the Quality Assurance group on-site following a surveillance (0-S8853) of
the startup following the Unit 1 outage and a surveillance (0-S89/ST-5)
conducted during the Unit 2 outage.
Problem Investigation Report (PIR)
2-089-0114 has been issued with the response to be provided by the
operations and projects groups management.
Licensee management has
indicated that these problems will be corrected prior to the upcoming
refueling outage for Unit 3 which is scheduled to begin in mid - November.
Pending satisfactory resolution of this PIR, the inspector is identifying
this concern as
an
Inspector Followup Item
269,270,287/89-25-04:
Resolution of PIR 2-089-0114.
No violations or deviations were identified.
7.
TI 2515/101 Loss of Decay Heat Removal (GL88-17) (71707)
Inspection Report 50-269,270,287/89-17 discussed the review of two of the
six applicable expeditious action items required by Generic Letter(GL) 88-17. During this report period the inspectors completed the remaining
requirements of TI 2515/101.
The third applicable expeditious action item requires at least two
independent,
continuous temperature indications whenever the Reactor
Coolant System (RCS)
is in a mid-loop condition and the reactor vessel
(RV)
head is on the vessel.
The GL requires that these temperature
indications be periodically checked and recorded by
an operator or
automatically and continuously monitored and alarmed,
depending on the
location of the monitoring.
The licensee committed to monitoring of the
temperature indications by control room operators and formally logging
those indications every two
hours.
Enclosure 4.7 of Operating
Procedure(OP)/2/A/1103/11: Requirements for Reducing RV level Less Than
50 Inches On LT-5 (LT-5 is Oconee's RV level instrument: 50 inches on LT-5
corresponds to about 32 inches above the top of the hot leg flow area),
contains independence criteria for temperature indications and monitoring
requirements if
the RV head is in place.
indications from each train of the Inadequate Core Cooling Monitor (ICCM)
are normally selected.
If
both trains of ICCM are not available, an
operable CETC output is selected from the Operator Aid Computer (OAC)
to
be utilized along with an operable ICCM train CETC.
The alarm setpoints
of the selected CETC's are reduced to 140 degrees F.
Performance Test
(PT)/2/A/600/01:
Periodic Instrument Surveillance, requires recording of
the selected two primary CETC indications every two hours.
During the
10
last Unit 2 refueling outage the inspectors observed operator compliance
with these procedures and noted no problems.
The fourth expeditious action item requires at least two independent,
continuous RCS water level indications whenever the RCS is in a reduced
inventory condition (below about 48 inches on LT-5 at Oconee).
These
indications should also be either periodically checked and recorded by an
operator or automatically and continuously monitored and alarmed. In the
response to the GL, the licensee stated that only one permanent RCS water
level indication is available per unit in the control room, with other
alternatives being evaluated.
The installed RV
level instrumentation
(LT-5)
operable during draindown is a differential pressure transmitter
which is connected to a water filled reference leg (which is
open to
containment atmosphere) and to the RCS cold leg piping.
The connection
tap is on the elevation center line of the cold leg piping.
These
characteristics make LT-5 very sensitive to variations in containment
pressure or RCS pressure. In discussions with the inspectors, operators
indicate that they are well aware of the limitations of LT-5.
The
inspectors have observed some problems with the LT-5 indication system
during past outages.
It
was noted that although normally a temporary
level indication system (tygon tubing) is installed before level
is
reduced below 28 inches, during the most recent outage due to a high
radiation area near the connection point, this installation was
not
performed.
The tygon tubing level *indicator system,
due to its RCS
connection location and complications involved with running tubing over
such a large elevation, has not been a reliable level indication system.
During an inspection visit to McGuire Nuclear Station the inspector
observed an ultrasonic detector (temporary installation) in operation.
This system, based on control room operator comments,
works very well.
Oconee
management
has indicated similar options (as
well as other
alternatives)
are
being
considered for Oconee.
Enclosure 4.7 of
OP/2/A/1103/11:
Requirements for Reducing RV Level Less Than 50 Inches On
LT-5,
requires that LT-5 (and
any other redundant level
indication,
excluding tygon tubing) be verified operable.
PT/2/A/600/01:
Periodic
Instrument Surveillance, requires recording of this level indication every
two hours whenever level is less than 50 inches.
The fifth applicable expeditious action requires the implementation of
procedures and administrative controls to generally avoid operations
which knowingly lead to perturbations to the RCS or to systems necessary
to keep the RCS stable while in a reduced inventory condition. Enclosure
4.7 of OP/2/A/1103/11 requires that the Operating Engineer or designee
sign a step which states that testing or maintenance which may adversely
affect the performance of systems or components required for decay heat
removal is not scheduled for the period of operation less than 50 inches.
While this step appears very broadly worded and requires significant
judgement and coordination effort on the part of the Operating Engineer's
staff, no problems have been noted in this area to date. During the last
outage the inspectors followed several maintenance activities which could
have affected decay heat removal capability. In all cases work was either,
12
particularly rely on extensive coordination and involvement on the part of
the operating staff, no significant problems have been noted by the
inspectors. During the inspection the observations included in the NRR
letter dated May 17,
1989,
in response to the licensees' submittal that
were considered. While the licensee's formal response appeared to contain
insufficient detailed information in several areas, a closer onsite review
into each of the applicable actions resulted in most of the comments being
fully resolved. The licensee is continuing to evaluate installation of an
additional, more reliable water level indication system in order to fully
comply with the GL recommendation on water level indications.
No violations or deviations were identified.
8.
Electrical Power System Self Initiated Technical Audit (SITA)
and Design
Basis Documentation (DBD) Analysis Programs
During this report period the licensee continued both of these programs.
A meeting with NRR was held on June 22,
1989 in Washington,
D.C.
to
discuss Oconee's Electrical
Power System and related Licensee Events
Reports.
Followup meetings were held onsite on July 13,
1989 with AEOD
personnel and July 19-21, 1989 to discuss the SITA process in more detail.
Inspection Report 269,270,287/89-17 contains details of several additional
electrical system problems identified by these efforts.
On August 4, 1989, as a result of the DBD effort on the 4 KV System, the
licensee identified that the '2B' Reactor Building Spray (RBS) pump motor
had been
replaced with another motor which had different starting
characteristics from the original motor. A DBD review of the calculation
disclosed that under a Loss of Coolant Accident coincident with a Loss of
Offsite Power
event
(LOCA/LOOP),
the motor may
have tripped while
starting. The licensee immediately declared the spray pump inoperable and
entered a 7 day Limiting Condition for Operation in accordance with TS 3.3.6.c.(2).
The overcurrent relays were reset to the new calculated
settings and the pump was declared operable at 1155 on August 5, 1989.
Because incorrect or inappropriate motor overcurrent settings have been a
problem in the recent past at Oconee (LER
269/87-05: High Pressure
Injection (HPI) Pumps Potential Tripping, LER 269/88-13: Lee Gas Turbines
Unacceptable as Backup Emergency Power), the inspectors examined closely
this latest issue in regards to the corrective actions of the earlier
issues.
The licensee informed the inspectors that after the HPI pump
motor overcurrent issue had been identified, all safety equipment that
would be actuated on a LOOP or a LOCA was reviewed to ensure that the
overcurrent relays were set correctly.
During those reviews the Design
Engineering (DE)
personnel involved utilized the starting characteristics
of the original spray pump motors.
Review of the spray pump motor
calculations as part of the DBD analysis revealed that the motors had been
replaced with motors of different starting characteristics.
Although
several spray pump motors had been replaced, analysis revealed that only
the '2B' motor had this incorrect overcurrent setting problem. The motor
had been replaced in 1980 which was prior to the licensee's initiation of
The Overall Plan for Organizational Review of Modifications (TOPFORM)
13
program which contains requirements specifically designed to prevent such
occurrences during modifications. The licensee informed the inspectors
that all other safety related motors have been examined to ensure that
their overcurrent settings are correct. The
'2B'
RBS pump motor appears
to have been a unique problem caused by an error during the analysis
(after the HPI motor incident) of LOCA loads fed via the underground
emergency power path. The licensee's present modification process ensures
that this problem would not occur on a pump motor replaced or added in the
future. This item will be identified as a Noncited Violation;
270/89-25-03:
Reactor Building Spray Pump Motor Incorrect Overcurrent
Relay Settings.
This licens identified violation is not being cited
because criteria specified in Section V.G.1 of the NRC Enforcement Policy
were satisfied.
Another potential problem was identified by the SITA team on July 20, 1989
during the onsite portion of their 4160V system audit. During a tour of
the Keowee Hydro Station battery room, the team identified that cable
trays and
HVAC duct work above the batteries appeared to not
be
seismically qualified.
A Problem Identification Report (PIR) was
initiated. A subsequent DE review found that the cable trays and ductwork
are not seismically designed.
Although the FSAR does not specifically
require review of interactions between
QA Condition I components and
non-seismic components,
DE looked into this issue and concluded that
seismic interaction between the trays or ducts and the Keowee batteries
are not a safety concern.
A memorandum to file documents this conclusion
and supporting information. This memo notes that the overall issue of
seismic interaction for equipment necessary for safe shutdown will be
addressed when Unresolved Safety Issue (USI) A-46 is resolved by walkdowns
in accordance with Seismic Qualification Utilities Group (SQUG)
guidelines.
In response to observations stated during the July 19-21 meeting between
NRR representatives and the licensee and the inspectors concerns (see
Inspection Report 269,270,287/89-17 and
the licensee
established a task force to revise TS 3.7, Auxiliary Electrical Systems.
The inspectors were concerned that significant problems with the TS which
had recently been discovered would not be corrected in a timely matter.
While it would be premature to submit a complete detailed revision to TS 3.7 before the DBD and SITA efforts are complete, the significant concerns
recently discovered should be addressed promptly such that operation in an
unanalyzed or not permitted configuration is prevented.
The task force
met on July 19, 1989 and decided that the recent TS 3.7 submittal will be
revised and
resubmitted
by about September 1, 1989.
The licensee
discussed these changes with the inspectors and ensured that their
immediate concerns would be satisfied. A complete rewrite of the TS is
expected to be submitted about June 1991. This revision is intended to
improve the format of the TS, make it less confusing and improve its ease
of use for the operators, in addition to incorporating the results of the
SITA/DBD programs and other concerns of the operators.
The inspectors
will continue to closely follow the SITA and DBD efforts and results.
'
15
be complete by June 1, 1989. The inspectors conducted a review to
determine if this LER could be closed. The chemistry department had
initiated action to have the degraded valves replaced.
Five valves
had been identified but only two had been replaced.
The second
action had also been accomplished, in that, the chemistry department
had performed an evaluation and determined that the facility was
understaffed, but no action has been taken by management to address
this problem. Since the LER implies, although not stated, that the
actions taken will preclude a similar occurrence from happening, the
inspectors considers that insufficient actions have been taken to
prevent this problem.from recurring although the specific action was
taken. The inspectors discussed this with upper management
and a
review of this issue is being performed. This item will remain open
pending further review and action taken by management.
10.
Exit Interview (30703)
The inspection scope and findings were summarized on August 19, 1989,
with those persons indicated in paragraph 1 above.
The inspectors
described the areas inspected and discussed in detail the inspection
findings listed below. The licensee did not identify as proprietary any
of the material provided to or reviewed by the inspectors during this
inspection. Dissenting comments were not received from the licensee.
Item Number
Description/Reference Paragraph
UNR 269,270,287/89-25-01
Apparent Failure to Provide Personnel
Licensed Pursuant to 10 CFR 55 At The
Controls At All Times During Operations
Of The Facility, paragraph 3.b.
VIO 269,270,287/89-25-02
Inadequate
Corrective
Action
to
Preclude
Recurrence of Events
(two
examples) paragraphs 3.c and 5.b.
NCV 270/89-25-03
Reactor Building Pump Motor Incorrect
Relay
Settings,
paragraph 8.
IFI 269,270,287/89-25-04
Resolution
of
2-089-0114,
paragraph 6.