ML15224A616
| ML15224A616 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 01/08/1990 |
| From: | Shymlock M, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A614 | List: |
| References | |
| 50-269-89-36, 50-270-89-36, 50-287-89-36, NUDOCS 9001190203 | |
| Download: ML15224A616 (18) | |
See also: IR 05000269/1989036
Text
a REG4
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION 11
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos:
50-269/89-36, 50-270/89-36, 50-287/89-36
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 Conduc ed:
November 12 -
December 16, 1989
Inspectors-
1//
V
n.
er, eni
Resident Inspector
Date Signed
t, esident Inspector
Date Signed
Approved by:
_____
____
____
___-___'
M. B. ShymloW(, Section Chief
Date Signed
Division of Reactor Projects
(I
SUMMARY
Scope:
This routine, announced inspection involved inspection at corporate
offices in the area of licensee self assessment capability and
on-site in the areas of operations, surveillance testing, maintenance
activities,
outage
activities, installation
and
testing of
modifications (Unit 3),
Fitness for Duty program training and
inspection of open items.
Results: A violation addressing two examples of procedural inadequacies was
cited during this period:
Inadequate program to ensure proper operation of safety related
throttle valves which resulted in a spill of reactor coolant
through the reactor building spray system into the reactor
building. (Paragraph 2.b)
-
Inadequate guidance in a switchyard component surveillance
procedure which contributed to a loss of power
on Unit 3.
(Paragraph 2.d)
9?001190*203 90010:3
F=
DR
A:0rIiCK:: 05000269
FDC
2
A violation addressing several
examples of failures to
follow
procedures was cited:
-
Failure to follow procedure during a transfer of power supplies
to an inverter resulted in an Engineered Safeguards actuation on
Unit 3 and led to a TS violation due to isolation of Reactor
Building'fire protection systems. (Paragraph 2.c)
-
Procedural requirements for operation of more than one reactor
coolant pump with reactor coolant temperatures less than
160
degrees F were not met. (Paragraph 2.e)
-
Failure to perform procedural requirements in sequence resulted
in a spill of contaminated water in the Unit 3 High Pressure
Injection Pump room. (Paragraph 2.e)
-
Performing procedural requirements out of sequence during a
cooldown on Unit 2 resulted in the low temperature overpressure
protection watchstander not having correct written procedures
pertaining to the assigned functions. (Paragraph 2.e)
A TS violation involving polar crane operation over the refueling
canal
and flagman positioning during crane operation was cited.
(Paragraph 5)
A weakness was noted concerning procedural compliance by Operations
personnel.
During detailed observation of evolutions the inspectors
noted numerous
instances where procedural
steps were performed
improperly out of sequence or not strictly in accordance with the
controlling procedures. Several instances clearly warranted formal
procedural changes which were not made.
This weakness contributed
directly to most of the violations noted in this report.
A strength was noted in that both the training and interim drawings
provided to operations personnel concerning recently installed
Nuclear -Station Modifications have significantly improved over
previous efforts.
(Paragraph 6)
I.
REPORT DETAILS
1. Persons Contacted
Licensee Employees
- M. Tuckman, Station Manager
0. Couch, Keowee Hydrostation Manager
- B. Barron, Assistant Station. Manager
- J. Davis, Technical Services Superintendent
0. Deatherage, Operations Support Manager
B. Dolan, Site Design Engineer Representative
- W. Foster, Maintenance Superintendent
T. Glenn, Instrument and Electrical Support Engineer
D. Hubbard, Performance Engineer
- E. LeGette, Compliance Engineer
- J. Lentz, Employee Relations Supervisor
t!
- 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
- Attended exit interview.
2.
Plant Operations (71707)(71710)(93702)
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,
reactor engineering, 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.
Actions
De
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.
Plant tours were taken throughout the reporting period on a routine
basis. The areas toured included the following:
Turbine Building
Auxiliary Building
Units 1, 2 and 3 Electrical Equipment Rooms
Units 1, 2 and 3 Cable Spreading Rooms
Unit 3 Penetration Room
Unit 3 Containment
Station Yard Zone within the Protected Area
Standby Shutdown Facility
Units 1, 2 and 3 Spent Fuel Pool Room
During the plant tours, ongoing activities, housekeeping, security,
equipment status, and radiation control practices were observed.
Unit 1 -
Unit 1 operated at 100 percent power for the
entire report period.
Unit 2 -
Unit 2 returned to 100 percent power on November 23, 1989
following a forced outage which began
on
November 10
following a dropped rod. Maintenance efforts were required
due to 2B1 and 2B2 Reactor Coolant Pumps vibration problems
which extended the outage.
The unit operated at
100
percent for the remainder of the report period.
Unit 3 -
Unit 3 remained in a scheduled end of cycle refueling
outage. As of December 16 the unit was proceeding to hot
shutdown condition in preparation for zero power physics
testing.
b. Unit 3 Reactor Coolant System Leak Through Building Spray Valve 3BS-1
On November 9, 1989, seat leakage through valve 3BS-1 resulted in an
approximately 2,000 gallon spill of reactor coolant through the
Reactor Building Spray (RBS) system into the Unit 3 containment (see
Inspection Report 50-269,270,287/89-34). The licensees investigation
into the cause of the seat leakage was initiated after a
comprehensive systematic plan was developed and discussed with the
inspectors.
Valve 3BS-1 had
been
maintained in
an
as
found
condition.
The licensee confirmed that there was excessive seat
leakage by 3BS-1 by using a hydrostatic test pump.
The 8 gpm pump
could not build up any pressure against the valve and leakage was
noted at a downstream drain line. The investigation then focused on
the operation and maintenance of the valve.
3
is
an eight inch motor operated Velan globe throttle valve
which shuts on torque (the
opening of the torque switch stops
movement in the shut direction once the valve is fully seated if the
operator is functioning properly).
By measuring circuit continuity
the licensee determined that the torque switch on 3BS-1 was not open.
Valve stem movement of approximately 1/4 inch (1.81 seconds travel
time) was observed (when the valve's control switch was held in the
shut position) before the torque switch opened. Apparently the Tast
time the valve was shut the control switch had not been held in the
shut position for a sufficient time period.
Since the operator for 3BS-1 has only two limit switch rotors
installed, the close light switch rotor also controls the open torque
switch bypass function. Consequently on a closing stroke the "close"
light will actuate before the valve is fully shut.
Operators are
aware that on this type of valve the control switch must be held in
the close position for an additional period of time after the close
light actuates in order to fully shut the valve.
The inspectors
noted several weaknesses in the operation of this type of valve;
PT/3/A/0150/22A,
Operational/Refueling Valve Functional
Test
(Enclosure 13.1), dated February 23, 1989, states that the 3BS-1
switch must be held in the 'close' position for approximately 3
seconds after the closed light is lit. A review of the MOVATS
signature traces for 3BS-1 indicates that the closed light
actuated at 8.055 seconds and the torque switch opened or
tripped at 11.45 seconds.
This indicates the operator should
have been instructed to hold the switch for at least 3.4 seconds
in order to ensure the valve is fully shut.
Signature trace analysis indicates that on the last operation of
3BS-1 the operator held the switch for about 1.6 seconds in the
closed position after the closed light actuated.
This is only
half of the time required by the procedure.
-
This aspect of the operation of this type of valve is not
discussed in detail in any documented operator training. It is
considered common knowledge of all operators that the switch
must be held in the closed position after the closed light
actuates. The licensee's investigation indicated that operators
use different time periods when operating these valves (values
from 2 to 5 seconds were stated).
-
There are nine valves of this type in various systems on each of
the three units. Only one procedure which requires these valves
to be cycled contains guidance on the time to hold the switch
after the closed light is lit
(BS-1,
BS-2 stroke test).
All
such throttle motor operated valves are distinguished by either
4
a yellow ring around the control switch or the word 'throttle'
on the control pushbutton and this is generally understood by
operators to mean the control switch must be held for 3 seconds
after the close light is received.
The licensee reviewed MOVATS traces on all 27 valves of concern. The
longest time interval from actuation of the close light until torque
switch tripping was found to be 5.28 seconds. Two other valves were
over 5 seconds and one was 4.97 seconds. Operations management will
be issuing written guidance to operators concerning time requirements
to ensure such safety related throttle valves are fully shut.
Discussion of this issue with Regional inspectors and close review of
IP/O/A/3001/10: Maintenance of Limitorque Operators,
dated June 23,
1989, indicated that there are weaknesses in the methods used to set
the valve operator limit switches during maintenance.
The clos.e
switch and the open torque switch bypass function are set by manually
closing the valve and then manually opening the valve until the disc
is free of its seat. A note preceding this step cautions that these
functions must be set to prevent torque switch actuation during
unseating of the valve.
Additional notes require ensuring that the
distance is 5 percent of open direction travel by either handwheel
turns after engagement,
stem travel or traces.
The procedure
emphasizes setting the switch after the handwheel resistance has
decreased to minimum running load. All of these statements address a
5 percent travel in the open direction as a minimum and no maximum
travel at setpoint is stated.
The information available on 3BS-1
indicates it
was set for a value of about 20 percent.
A longer
travel time in the open direction (before the open torque switch
bypass actuates) translates to the close light actuating with the
disc further from the fully shut position. The licensee is currently
evaluating changes needed to establish a program to control the
torque switch bypass time settings on these valves.
This program
will establish a maximum bypass time limit (less than or equal to 3
seconds) and ensure the valve operation is setup to meet this limit
as well as notification to operators if limit changes occur.
The
inadequacies identified in the review of this item are combined with
the example in paragraph
2.d and are identified
as Violation
50-269,270,287/89-36-01:
Failure to Provide Adequate Procedures as
Required by TS 6.4.1.a and 6.4.1.e.
C. Unit 3 Engineered Safeguards Actuation
At approximately 4:30 p.m.
on November
14,
1989
an Engineered
Safeguards
(ES)
actuation occurred on Unit 3.
The actuation was
caused by operator error during shifting of power supplies to a vital
panelboard. Unit 3 was in cold shutdown undergoing a scheduled 42
day refueling outage when this occurred. Reactor vessel water level
had been lowered to a reduced inventory condition in order to install
cold leg nozzle dams. No loss of decay heat removal capability or ES
injection into the vessel occurred.
After routine preventive maintenance had been performed on a portion
of the vital Instrumentation and Control System, power supplies were
being
transferred
in accordance
with
Operating
Procedure
OP/3/A/1107/04: Operation of the Vital Bus and Auxiliary Inverters.
The operator omitted a clearly designated step and erroneously opened
a switch supplying power prior to aligning the other source.
This
caused the 120VAC vital instrumentation bus to be de-energized which
resulted in the tripping of ES analog channel A.
Since ES analog
channel B was already tripped for unrelated testing, this two out of
three analog channels in a tripped state resulted in an -ES actuation.
The Oconee ES circuitry is designed such that the analog ES channels
trip when de-energized and. the digital channels are energized to
actuate. This resulted in a Keowee Hydrostation emergency start, a
temporary loss of the reactor building purge fan
and
several
radiation monitors,
and other miscellaneous equipment actuation.
Power was restored to the inverter and the ES circuitry was reset.
The event was reported to the NRC Operations Center at about 6:20
p.m.
in accordance-with 50.72(b)2ii.
At approximately 10:30 p.m.,
operators identified that
an
valve had shut during the ES
actuation which secured fire protection to the Reactor Building.
This resulted in the violation of TS 3.17.5.3 for a period of
approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
This failure to follow procedure is combined with the example
identified in paragraph 2.e and will be identified as Violation
50-269,270,287/89-36-02:
Failure
to
Follow Procedures
During
Operation in a Shutdown and Cooled Down Condition.
d. Unit Three Momentary Loss Of Of Electrical Power
Oconee Nuclear Station is connected to the primary transmission
system through two large switching stations. Units 1 and 2 generate
power at 19KV which is stepped up to 230KV to feed the
230KV
transmission switchyard. Each unit is connected to the switchyard by
two breakers. There are eight transmission lines connecting this
switchyard to the remainder of the grid. Unit 3 also generates power
at 19KV, but its output is stepped up to 525KV and-feeds power to a
525KV switchyard through two breakers.
Three transmission lines
connect to this switchyard and the two switchyards are interconnected
through a 230/525 KV autotransformer.
At approximately 3:00 p.m., on December 3, 1989, Unit 3 experienced a
loss of electrical power which lasted for 21 seconds before power was
automatically restored. The unit was in cold shutdown, refueling had
been completed
and the Reactor Coolant System
(RCS)
level
had
recently been increased from a reduced inventory condition.
6
Prior to the loss of power event,
power was being provided to the
Unit 3 Main Feeder Buses (MFB) through the normal source breakers (NI
and N2)
by backfeeding through the generator main transformer from
the 525KV switchyard. The Startup transformer, which receives power
from the 230KV switchyard, was energized but the associated breakers
(El and E2) were open.
A surveillance test involving
the
PT/0/A/0610/05B:
Electro-Mechanical
Relay Breaker
Trip Test, dated August 24,1989,
was being performed.
This is a
routine test conducted monthly. Step 12.26 of the test requires a
total of four breakers in the switchyard to be opened simultaneously.
This action separates the 230KV and 525KV switchyards.
Apparently,
due to
incorrect restoration
action following
some previous
maintenance in the 525KV switchyard, the yellow bus of the switchyard
was deenergized when the four breakers were opened (a disconnect had
been previously left open).
This caused the loss of power to the
MFB's.
Each of the MFB's provide power to each of the three
redundant Engineered Safeguards (ES) switchgear busses.
During normal operations, such a trip of the N1 and N2 breakers would
be accompanied by other control signals and a rapid transfer to the
startup transformer path via the El and E2 breakers.
In this case,
as expected, the rapid transfer did not occur.
The Main Feeder Bus
Monitor Panels (MFBMP)
are a non-safety related system designed to
assure a reliable source of power
to the MFB's during non-LOCA loss
of power events. An undervoltage condition for 20 seconds on 2 out
of 3 phases of both MFB's will initiate a MFBMP signal which provides
signals to various other breakers control logic and portions of the
Emergency Power Switching Logic (EPSL) to restore power.
Approximately 21 seconds after the MFB's were deenergized, the E2
breaker closed and energized the number 2 MFB via the startup
transformer. This action also energized the number 1 MFB since the
MFB's are connected through the ES switchgear buses they supply.
Initially there was a concern since some EPSL channel one components
appeared to have not functioned. properly during the event.
Subsequent investigation indicated that the timers involved in the
MFBMP circuitry did not actuate at exactly the expected 20 second
time period. The inspector observed testingwhich confirmed that one
set of timers actuated at about 19 seconds while the other set
actuated at about 21 seconds.
This apparently was sufficient to
cause the observed sequence of events and does not appear to be a
significant problem.
The times were adjusted to a 20 second dropout
time.
PT/0/A/0610/05B did not contain adequate guidance to ensure
electrical switchyard alignment prior to portions of the test during
certain plant conditions. This, in part resulted in the loss of
electrical power for the short duration during this test.
A
contributing factor in this event was the operators not being
aware of the status of the open switchyard disconnect.
An operator
involved in a restoration following switchyard maintenance activities
7
incorrectly performed
the restoration procedure and left the
disconnect open.
Additionally, it was noted that the 525KV
switchyard mimic bus in the Unit 1 and 2 control room does not .depict
this disconnect. This example of an inadequate procedure is combined
with the example identified in paragraph 2.b to constitute Violation
50-269,270,287/89-36-01:
Failure to Provide Adequate Procedures
e. Procedure Adherence Deficiencies
During this period the inspectors noted several incidents associated
with operators not following procedures as provided. The examples
noted are as follows:
On November 10, the inspector noted that a crud burst actuation
process
on Unit 3 was
being
performed
as controlled by
OP/3/A/1102/10, Controlling Procedure for Unit Shutdown.
This
procedure requires temperature to be maintained greater than 160
degrees F if two reactor coolent pumps are running, however, the
temperature observed by the inspectors was 155 degrees F. The
operators knew that the temperature was outside the procedure
requirements and had discussed this with Operations management
to assure no technical problems would exist when operating at a
value less than specified;
however,
the procedure
was not
formally changed to allow this deviation.
On November 11,
during cooldown on Unit 2 in accordance with
OP/2/A/1102/10, Controlling Procedures for Unit Shutdown,
Enclosure 4.2, step 2.9 was performed out of sequence.
Performance
of a step out of sequence is allowed by the
licensee's administrative .procedures. However,
as a result of
this change in the sequence,
the watchstanding procedures
associated with the
Low Temperature Overpressure Protection
(LTOP) were no longer valid. Verbal instructions were provided
to the LTOP operator but changes were not made to the procedure
to incorporate these instructions.
-
On November 17, a spill of contaminated water occurred in the
Unit 3 High Pressure Injection (HPI)
pump room.
Investigation
indicated that this was caused by a failure to follow procedures
in progress prior to performing steps in another procedure. The
licensee had just completed testing a containment penetration in
accordance with PT/3/A/0150/06, Mechanical Penetration Leak Rate
Test, and was returning the valves to the positions specified by
this procedure.
Step
19 of the enclosure being performed
included closing several valves and the installation of pipe
caps. Step 20 cleared tags associated with the component drain
pump. The Nuclear Equipment Operator (NEO)
was given the task
of returning the valves to their appropriate position and also
-nIII-
8
an additional task of performing another lineup to drain a
portion of another system using a portion of the first system.
No guidance was provided to the NEO as to the sequence of valve
manipulations. The operators cleared the component drain pump
tags and operated the system before Step 19 was completed by the
NE0. This caused the spill of water in the HPI pump room. The
NEO discovered the leak when he proceeded to the HPI room to
complete his assigned tasks. If the NEO had been redirected .to
a different job or had been delayed in entering the HPI pump
room,
the spill of water could have resulted in damage to
safety-related equipment.
These examples are being combined with the example discussed in
paragraph
2.c
and
will
be
identified
as
Violation
50-269,270,287/89-36-02:
Failure
to
Follow
Procedures During
Operation in a Shutdown and Cooled Down Condition.
f. Resolution of Concerns Relating to Operation With A Dropped Rod
Inspection Report 50-269,270,287/89-34 discussed a dropped rod event
which occurred on November 10, 1989 on Unit 2. The licensee's Design
Engineering (DE) group at that time had identified a concern that the
automatic protective system may not have had sufficiently low enough
setpoints to prevent local fuel damage under certain conditions of
high
power imbalance.
Consequently Unit 2 was placed in a hot
shutdown condition.
On
November 27,
1989,
the inspectors were
informed that the licensees
DE group
had completed a detailed
analysis of continued unit operation with a dropped rod. The results
indicated that the current TS required Reactor Protective System
Setpoints are set low enough to prevent any problems relative to
Departure
From Nuclear Boiling Ratio (DNBR)
and linear heat rate
limits.
Two violations were identified.
3. 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 witnessed in whole or in part:
<II
9
PT/3/A/0610/01A Emergency Power Switching Logic Normal Source
Voltage Sensing Circuits dated November 8, 1989
PT/3/A/0610/01B Emergency Power Switching Logic Startup Source
Voltage Sensing Circuit dated November 21, 1989
PT/O/A/0202/12
High Pressure Injection System ES Test dated
PT/3/A/0150/22BDecember 4, 1989
PT/3/A/0150/22
Shutdown Valve Functional Test dated
January 25, 1989
PT/3/A/0150/22A Operational/Refueling Valve Functional Test dated
February 23,1989
PT/3/A/E600/22
Motor Driven Emergency Feedwater Pump Suction Check
Valve Test dated Juliy 14, 1988
PT/O/A/0230/16
Auxiliary Shutdown Panel Operability Test (Unit 3)
dated May 27,1987
IP/O/A/310/08A
Engineered Safeguards System Logic Subsystem 2 HPI
& RB Isolation Channel 2 Functional Test dated
September 17,1987
No violations or deviations were identified.
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:
MP/O/A/1800/14
Freeze Seal - NSM 2640 dated March 22, 1989
TN/3/A/2640/o/AM1 NSM 2640 -
Unit 3 Emergency Feedwater Upgrade
TN/3/A/2803/h/e
NSM 2803 - Main Feeder Bus Safety Train Cable
Separation dated Nov. 23, 1989
WR 57259D
Clean Emergency Feedwater Pump Turbine Oil Cooler
(MP/O/A/1100/12 dated January 23, 1988)
No violations or deviations were identified.
5. Unit 3 Refueling Outage (71707)
The inspectors conducted a tour of containment on November 27,
1989, to
observe activities in progress in this area. The refueling process had
begun and the inspectors were specifically monitoring this effort. During
this observation the inspectors noted that work was being performed,
III
10
simultaneously with fuel movement, using the small hook on the polar crane
to- support a ventilation fan adjacent to the transfer canal.
The
inspectors noted that the large hook, although nothing was attached to it,
was above the reactor vessel. Personnel working on the fan were using a
scaffold to allow access to the fan.
TS 3.12.1 requires that the
reactor building polar crane not be operated over the fuel transfer canal
when any fuel assembly is being moved.
When the fan was in position and
partially secured, the polar crane was moved from over the transfer canal.
The flagman, in communication with the crane operator, was located on the
third floor level.
TS 3.12.4 requires when the reactor vessel head is
removed and the polar crane is being operated in areas away from the fuel
transfer canal, the flagman shall be located on the top of the secondary
shield wall
(fourth floor) when the polar crane hook is above the
elevation of the fuel transfer canal. The inspectors notified the reactor
operator on the fuel handling crane and the senior reactor operator in
charge of refueling.
The licensee stopped the refueling process to
investigate this activity and take appropriate corrective actions prior to
continuing fuel
loading.
This finding is identified as Violation
50-287/89-36-04:
Inadequate Control
of Polar Crane Operation During
Unit 3 Refueling.
One violation was identified.
6.
Installation and Testing of Modifications (37828,37701)(Unit 3)
The inspectors selected several modifications concerning safety related
components which were not required to be submitted for approval to the NRC
(No modifications were being installed which required prior NRC approval).
Portions of the following Nuclear Station Modifications (NSMs),
their
related installation procedures, and testing procedures were inspected.
NSM 32803 Main Feeder Bus Safety Train Cable Separation
NSM 32640
Emergency Feedwater (EFW) Seismic Upgrade
NSM 32844 Auxiliary Reactor Building Coolers Seismic Upgrade
Of these three NSMs,
the EFW seismic upgrade was the most extensive and
was the most closely followed by the inspectors.
The NSM included the
replacement of several major large valves in the condensate system, the
addition of vent and drain lines to the Upper Storage Tank (UST) supply to
the Turbine Driven Emergency Feedwater Pump (TOEFWP),
removal of several
plant heating lines from the USTs,
and rerouting of some Low Pressure
Service Water piping which required a large freeze seal as well as some
other modifications. Many of these tasks were observed on a daily basis
during the modification work.
The inspectors reviewed portions of these NSM packages for compliance with
the Oconee
NSM Manual.
The required 10 CFR 50.59 documentation was
closely reviewed and no major discrepancies were noted.
The approved
implementation procedures were
reviewed and work observed to insure
compliance.
The
inspector noted that work within
sections of
TN/3/A/2640/0/AM1:
NSM 2640, Unit 3 Emergency Feedwater Seismic Upgrade,
- 0
11
(October 9, 1989)
was being performed out of sequence despite a note
specifically requiring the steps within a section to be performed in
order. In this instance this did not adversely effect the quality of the
modification installation or personnel safety.
Report 269,270,287/89-25
discussed.two concerns associated with modifications which had also been
identified by a licensee QA surveillance.
The concerns involved interim
drawings and training provided to operators.
The
inspector noted that plant drawings which were effected by
modifications were correctly addressed by these interim drawings.
Improvements
were noted in the training of operators
on
installed
modifications.
The inspectors will review portions of the installation testing packages
during the next inspection period.
No violations or deviations were identified.
7. Resident Inspector Observation of Initial Licensee Fitness for Duty
Training (TI 2515/104)
The inspectors obtained copies of the licensee's Fitness for Duty (FFD)
initial training lesson plans and FFD program booklet.
The inspectors
reviewed this material and the requirements of Temporary Instruction
2515/104. On December 5, 1989, the resident inspector observed a training
session for employees who have unescorted access to a nuclear station.
The training consisted primarily of a lecturer reading the lesson plan
entitled "FFD
Training for Supervisors" (FFD-001
dated October 16,
1989)
with modifications to tailor the presentation to general
employees.
Several short videotapes were viewed and a question and answer session
followed the session. The training strongly emphasized that the licensee
is revising its.FFD policy and procedures based on the requirements of 10
CFR 26. The observed session lasted slightly over two hours. Along with
the printed material distributed this training should provide the
employees with a good fundamental knowledge of the licensees revised FFD
program.
Oconee's FFD initial training program consists primarily of presentations
made to two separate groups.
Lesson plan FFD-001:
FFD Training for
Supervisors,
is presented to supervisory personnel while FFD-002:
Training for Employees and Escorts, is given to other employees authorized
unescorted access. The inspector noted that section 4.0 of FFD-002:
Training for Employees and
Escorts, specifically
emphasized
the
responsibilities of an escort in observing and detecting fitness for duty
of individuals under escort. Section 4.1 of FFD-002 discusses a videotape
( shown as part of the training) entitled "Drugs in the Workplace." This
is intended to help employees recognize possible possession, use, or sale
of drugs. The observed session, which utilized a modified FFD-001:
12
Training
for
Supervisors, did
not specifically emphasize escort
responsibilities (Section
4.0 of
FFD-001
does not discuss escort
responsibilities). The Drugs in the Workplace videotape was shown during
the training.
10 CFR 26.22(b) requires that persons assigned to escort
duties be provided appropriate training in techniques for recognizing
drugs and indications of drug use,
sale or possession along with
techniques for observing aberrant behavior and procedures for reporting
problems. The inspector noted that section 4.2: Behavior Observation, of
FFD-002 was not covered in the observed session. These observations were
discussed with the Oconee Nuclear Station FFD Coordinator and the Oconee
Employees Relations Supervisor. The inspector emphasized his concern that
the training provided to employees and supervisors may not sufficiently
emphasize escort responsibilities.
The FFD Coordinator stated it would
be ensured that future training would emphasize escort duties.
In the near future FFD training session for supervisors will be observed.
All scheduled classes have already been given and a makeup session will be
attended. This will complete the requirements of TI 2515/104.
No violations or deviations were identified.
8.
Evaluation of Licensee Self - Assessment Capability (40500)
The inspector went to the general offices to perform a review of the
activities associated with the Nuclear Safety Review Board (NSRB).
This
review consisted of the following:
-
a review of meeting minutes for the past two years
-
a
review of meeting frequencies and composition to assure TS
requirements have been met
a review of qualifications and expertise of individual committee
members and their designated alternates
-
a review of selected audits and the audit schedule conducted under
the cognizance of the NSRB since January 1987
-
a review of the tracking mechanisms used by the NSRB for open items
-
-
a review of actions taken by the NSRB pertaining to proposed changes
to Oconee's TS.
In conjunction with this review the following specific documents were
reviewed:
-
Charter of the Nuclear Safety Review Board, Revision 8
-
NSRB Administrative Procedure (NSRB)/1,
dated 12/9/86,
Processing
Nuclear Safety Review Board Material
13
-
NSRB/2, dated 12/9/86, Conduct of On-Site Reviews and Audits
-
NSRB/3, dated 6/3/88, Record Retention and Handling
-
NSRB/4, dated 5/13/83, NSRB Outstanding Items Accountability
-
NSRB/5, dated 12/5/86, NSRB Review of Documentary Material
-
NSRB/6,
dated 12/5/86,
Conduct of Nuclear Safety Review Board
Meetings
NSRB/7,
dated 8/14/89,
Rev-iew of Nuclear Safety Evaluations for
Station Procedures, Procedure Changes, and Completed NSMs
NSRB/8, dated 9/12/88, NSRB Procedure for Processing Required Audits
During this review the inspector identified that there was no individual
appointed to the NSRB with expertise in the field of non-destructive
examination and testing. This was discussed. with the NSRB Chairman who
acknowledged this point, and stated this expertise had not been needed in
the past several years. If problems were submitted to the NSRB associated
with this area,
he was authorized to use consultants for this review.
Another inspector concern was that NRC inspection reports that did not
contain a Notice of Violation, were not reviewed by the NSRB.
Since
information addressed in these reports may provide insight to areas the
NRC considers to be strengths or weaknesses, the inspector recommended to
the chairman that they be considered in the review process. TS 6.1.3.3.b
and c states that the NSRB is to review proposed changes to procedures,
systems
or components,
and tests and experiments which involve an
unreviewed safety question.
This review is accomplished by use of a
subcommittee.
The results are then submitted to the NSRB for its review.
This process was discussed with regional management and considered to be
an acceptable method to meet the TS requirement.
The results of this
review indicate that the licensee has a self assessment capability that
meets the requirements of TS 6.1.3.
No violations or deviations were identified.
9. Inspection of Open Items (92700)(92701)
The following open items were reviewed using licensee reports,.inspection,
record review, and discussions with licensee personnel, as appropriate:
a. (Closed)
Unresolved
Item 50-269,270,287/89-34-04:
Resolution of
Apparently Incorrect Low Temperature Overpressure Protection (LTOP)
TS. This item addressed conflicts with TS 3.1.2.9 and the NRC Safety
Evaluation Report
(SER)
concerning that TS.
Inspection reports
50-269,270,287/88-34 and
89-05
provide additional
details and
document licensee commitments required to meet the SER assumptions.
During this inspection period the licensee discussed changing the
commitments made previously. A telephone discussion was held between
14
the licensee, NRR representatives and the inspectors on November 28,
1989, to discuss the proposed changes. A portion of the proposal was
to use some of the corrective action statements included in the
licensee's submittal of November 15, 1989 to change TS 3.1.2.9. The
discussion resulted in the following commitments:
-
The licensee will adhere to the present TS 3.1.2.9.a and b
except that both trains of LTOP must- be operable when Reactor
Coolant System (RCS)
temperature is less than 325 degrees F
(except when the reactor vessel head is removed).
The present
TS requires only one of the trains to be operable. This action
by the licensee is more conservative than the present TS and is
in agreement with the proposed TS.
This is not a change from
the previous commitment.
-
If
one of the LTOP trains become inoperable, the licensee will
take action as identified in the proposed TS
submittal .
At
present the inoperability of one LTOP train is not addressed in
the present TS (the inoperability of both trains is addressed).
This is also more conservative than the present TS requirements.
This is a change to the previous commitment.
The previous
commitment was to take the corrective action identified in TS if
either of the LTOP systems became inoperable.
-
The licensee will continue to use a dedicated operator with no
other responsibilities when plant conditions are such that LTOP
requirements are in effect.
This action will *be taken until
such
time
as other administrative procedures and hardware
modifications are implemented that would eliminate the necessity
of a dedicated operator.
(The
vulnerability to overpressure
transients with less than 10 minutes of operator action time
will be eliminated.)
Prior to removal of this dedicated LTOP
watchstander,
the
administrative
actions
and
necessary
modifications will
be discussed with the inspectors.
The
removal of the dedicated operator will be a change to the
previous commitment.
Based on the actions taken the unresolved item is being downgraded to
an Inspector Followup Item,
50-269,270,287/89-36-03:
Revised Low
Temperature Overpressure Protection System Operability Requirements.
b.
(Closed)
IFI 50-269,270,287/89-03-08:
Evaluation of Once Through
Steam Generator (OTSG) Rapid Cooling. This item documented a concern
of the Augmented Inspection Team (AIT)
investigating the fire in
switchgear 1TA (and related events) which occurred in January 1989.
The AIT asked the licensee to determine if
the subsequent rapid
introduction of subcooled water into the 1A OTSG negatively impacted
OTSG structural integrity. The inspectors reviewed documentation of
15
an OTSG transient assessment performed by Babcock and Wilcox (B&W)
dated January 16, 1989. The assessment considered the OTSG tubes,
main feedwater nozzles
nozzles.
Usage
factors for this event were very small and it was concluded that this
transient had resulted in
no adverse effect on the structural
integrity of the OTSG. This item is closed.
C.
(Closed) IFI. 50-269,270,287/89-22-01: Update of Keowee Hydro Station
Alarm Response Procedures. This item addressed the concern that the
Keowee Procedures had not been updated since 1973. Modifications to
systems and changes in operating practices have been made during that
time. The Alarm Response Procedures have been completely reviewed
and updated. The response procedures are organized according to the
clearly labeled annunciator titles. This item is closed.
d.
(Closed) LER 50-269/86-02: EFW And LPSW Piping And Valves Not In Full
Compliance With FSAR Seismic Criteria. This LER was submitted in
correspondence dated March 5,
1986.
Modification
NSM
2640
was
completed on Unit 1 on February 24, 1989, on Unit 2 on June 29, 1989,
and was completed on Unit 3 during the present outage. Based on the
completion of these modifications, this item is closed.
e.
(Closed) LER 50-269/87-09: Two Functional Units Of Emergency Power
Switching Logic Taken Out Of Service Due To A Management Deficiency.
This LER was submitted in correspondence dated December 15,1987. The
corrective action for this item included a TS change which was due to
be submitted by July 15, 1988. Changes to this commitment were made
in subsequent correspondence by the licensee. The proposed change to
the TS was submitted August 31,
1989.
Based on this action in
conjunction with the earlier completion of the other prescribed
corrective actions, this item is closed.
f. (Closed) LER 50-269/88-04: Emergency Power Switching Logic Retransfer
To Startup Logic Defeated Due To Design Deficiency.
This LER was
submitted in correspondence dated April 6, 1988.
A portion of the
corrective action for this problem was to complete a self initiated
internal Quality Assurance audit. This was originally scheduled to
be accomplished in the third and fourth quarters of 1988, but was
delayed until the third quarter of 1989. This audit was completed in
September 1989,
and completes all corrective action for this item.
Based on this action, this item is closed.
g.
(Closed)
LER 50-270/88-02: Inoperability Of A Portion Of Emergency
Power Switching Logic Due To A Design Deficiency.
This LER was
submitted in correspondence dated May 26,
1988.
The licensee has
completed
all corrective actions identified in this LER.
The
inspector reviewed the corrective actions and considers this item
closed.
16
10.
Exit Interview (30703)
The inspection scope and findings were summarized on December 18, 1989,
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.
Item Number
Description/Reference Paragraph
269,270,287/89-36-01
Violation - Failure to Provide Adequate
Procedures as Required By TS 6.4.1.a
and 6.4.1.e, paragraph 2.c and 2.e
269,270,287/89-36-02
Violation
-
Failure
to
Follow
Procedures
During
Operation
in a
Shutdown
and Cooled
Down
Condition,
paragraph 2.d and 2.b
287/89-36-04
Violation - Inadequate Control of Polar
Crane
Operation
During
Unit 3
Refueling, paragraph 5
269,270,287/89-36-03
IFI -
Revised LTOP System Operability
Requirements, paragraph 9.a