ML16161A975
| ML16161A975 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 05/02/1988 |
| From: | Peebles T, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16161A973 | List: |
| References | |
| 50-269-88-08, 50-269-88-8, 50-270-88-08, 50-270-88-8, 50-287-88-08, 50-287-88-8, IEB-88-001, IEB-88-1, NUDOCS 8805100036 | |
| Download: ML16161A975 (14) | |
See also: IR 05000269/1988008
Text
pg REGCJ4
UNITED STATES
0 oNUCLEAR
REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos: 50-269/88-08, 50-270/88-08, 50-287/88-08
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
Inspection Conducted:
March 17 -
April 18, 1988
Inspectors:
/(A
A
/
P .
-
ne r
Senior Resident Inspector
L.D.
ert, Residen
Inspector
D e Signed
Approved by:
____
T.A.
Peebles, Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection involved resident inspection on-site
in the areas of operations,
surveillance, maintenance,
physical security,
radiation protection,
engineered safeguards features lineups, nonroutine
reporting, meeting with public officials, and confirmatory order review.
Results: Of the nine areas inspected, one violation was identified (Failure to
provide procedures to perform component verification on components requiring
maintenance, paragraph 6.b).
8805100036 880503
ADOCK 05000269
Q
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- M. Tuckman, Station Manager
J. Davis, Technical Services Superintendent
- W. Foster, Maintenance Superintendent
T. Glenn, Instrument and Electrical Support Engineer
C. Harlin, Compliance Engineer
D. Hubbard, Performance Engineer
J. McIntosh, Administrative Services Superintendent
- F. Owens, Assistant Engineer, Compliance
- R. Sweigart, Operations Superintendent
L. Wilkie, Integrated Scheduling 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.
Exit Interview
The inspection scope and findings were summarized on April 15, 1988, with
those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail the
inspection findings listed below. Dissenting comments were not received
from the licensee.
Proprietary information
is not contained in this
report.
Item Number
Status
Description/Reference Paragraph
IFI 269,270,287/
Open
Improvement in Cable Room Fire
88-08-01
Detection System
UNR 287/88-08-02
Open
All Three Low Pressure Injection
Pumps Inoperable
IFI 269,270,287/
Open
RBCU Dropout Plate Inspection
88-08-03
2
Item Number
Status
Description/Reference Paragraph
(cont'd)
IFI 269/88-08-04
Open
Functional Verification Testing of the
Reactor Building Cooling System
Drop
Out Plate
VIO 269,270,287/
Open
Failure to Provide an Adequate
88-08-05
Procedure to Identify Components
Requiring Maintenance
UNR 287/88-08-06
Open
Runback During CRD System Maintenance
Bulletin 88-BU-01
Closed
Defects in Westinghouse Circuit
Breakers
LIV 269,270,287/
Open
Lack of Adequate Procedures for
88-08-07
Isolation of Equipment Containing EPSL
Components
3.
Licensee Action on Previous Enforcement Matters
This subject was not addressed in this inspection.
4.
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, Unit 2 Refueling 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
week days 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 Licensees 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
3
Units 1,2, and 3 Cable Spreading Rooms
Station Yard Zone within the Protected Area
Standby Shutdown Facility
Units 1,2, and 3 Penetration Rooms
Unit 2 Containment
Condenser Circulating Water Intake Structure
During the plant tours, ongoing activities, housekeeping, security,
equipment status, and radiation control practices were observed.
Unit 1 -
Unit 1.began this reporting period operating at 100%
power. The unit reduced power to about 98% on March 27 dbe
to a problem on the feedwater 1E1 heater drain pump.
The
problem was corrected and the unit returned to 100% on
March
29 where
it
operated for the
remainder of the
reporting period.
Unit 2 -
Unit 2 began this reporting period in an outage condition.
On April 7 the unit was taken critical and zero
power
physics testing was
performed.
On April 12
power
was
increased to 40% and problems developed on the Alterex
coupling and with turbine vibrations causing the generator
to be taken off the line.
The generator was brought back
on the line on April 14 and power was escalated slowly to
100% by April 15.
Unit 3 -
Unit 3 began the reporting period operating at 100%0
power.
The unit experienced a Asymmetric Rod Runback to
96% power on March 29 due to a communications problem
between the operator and a technician.
The unit returned
to 100% power on March 30.
On April 5, power was reduced
to 88% due to load considerations.
The unit continued to
operate at that level until April 17 when the tube leak in
3A steam generator increased from
.08 gpm to 1.35.
An
Unusual Event was declared at 0115 on April 18 and the unit
was
shutdown
and cooled down to cold conditions.
The
shutdown was performed in accordance with the licensees
emergency operating procedures and operating procedures.
The unit was on line for 351 days prior to this event.
b.
Fire In Unit 1 Cable Room
At approximately 8:30 a.m.
on
March 22,
1988,
a small fire was
discovered in a Unit 2 computer cabinet (not safety related), in the
Unit 1 cable room which is located just beneath the Unit 1/Unit 2
Control
Room.
Unit 2 was at cold shutdown.
Initial discovery of
the fire was due to an individual working in the Unit 2 cable room
reporting smoke. The unit supervisor and shift supervisor identified
the source of the smoke as a smoldering computer terminal board in
j.
4
Unit 2 computer cabinet G-2.
Apparently incorrect wiring during
recent maintenance caused the fire. The fire brigade was dispatched
and
the computer board
was maintained cool with carbon dioxide
extinguishers until smoldering was extinguished within five minutes
by cutting the terminal
leads to the board.
No open flames were
observed but smoke was described as light to medium and could be
smelled in the control room.
After the initial fire brigade efforts
were completed, the resident inspector entered the cable room.
Some
smoke still remained
in the cable room and deposits on adjacent
surfaces and cables indicated that the smoke emitted was more than a
minimal amount. The inspector along with operating supervisors was
concerned that a fire detector located approximately five feet away
in the overhead did not alarm.
Subsequent Instrument and Electrical
testing of the detector indicated that it
was functioning properly.
An hourly fire watch was stationed in the cable rooms as a pre
cautionary measure and the licensee requested their fire protection
engineers review the
situation.
After evaluation
by the fire
protection engineers,
it
was concluded that the system is fully
operable and meets
all current requirements.
The fire watch was
secured. The licensee feels strongly that detector sensitivity and
testing could be improved through installation of a more up to date
detection system and is considering a Nuclear Station Modification
to accomplish this. During the review by fire protection and safety
engineers a fire door was discovered open in the vertical cable shaft
in the Unit 1 cable room. This shaft connects several levels of the
auxiliary building including the equipment room and cable room and
is posted with a fire barrier sign.
The door was shut immediately
upon discovery.
The issue was promptly reported to the resident
inspector.
The licensee has
been
unable to determine how long
the door was open or why it
was opened.
The resident inscectors
routinely check fire barriers on a daily basis and this door is often
checked and has not previously been found open. The inspectors have
not frequently found fire barrier doors left open and feel that
generally a high level of attention is given to fire protection
equipment at the station.
Because of the serious potential con
sequences of a fire in the cable room, resolution of future action
on the detection system is identified as an Inspection Followup Item
50-269,270,287/88-08-01; Improvement of Cable Room Fire Detection
Systems. The inspectors will continue to monitor the status of fire
barriers particularly in the cable and equipment room areas.
c.
All Three
Low Pressure Injection Pumps Administratively Inoperable
(Unit 3)
At 8:00 a.m.
on April 6,
1988,
it
was discovered that during the
previous night shift maintenance personnel had lubricated the fast
couplings of all three low pressure injection (LPI)
pumps and post
maintenance performance testing had not been completed.
Unit 3 was
5
at 88% power during this period.
requires under the existing plant conditions that two independent
Additionally it
permits tests or
maintenance to be performed on any component of the LPI system if the
redundant LPI train is operable.
All three LPI pumps were declared
inoperable at 8:00 a.m.
because if
incorrect lubrication had been
performed the ability of the pumps to function as required would
have been impaired.
The resident inspector was in the Unit 1/2
Control Room at the time and was immediately informed.
The licensee
called the NRC Operations Center as required by 50.72.b.2. iii(B).
Performance testing to verify proper lubrication and pump operability
was completed on one LPI pump
by 10:30 a.m.
and by approximately
11:30 testing of all three pumps had been satisfactorily completed.
Due to the short time. interval required to verify operability and
no reason to suspect that the pumps would not actually perform as
required if
necessary, Unit 3 remained at 88% power.
(Technical
Specification 3.0 would have required the unit to be in hot shut
down within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.)
Initial investigation indicates that the
maintenance workers did not correctly follow station- procedures
and that poor training and/or communications contributed to this
incident.
Pending licensee and inspector followup investigation,
this item is identified as Unresolved Item 287/88-08-02:
All Three
Low Pressure Injection Pumps Inoperable.*
5. 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 or witnessed in whole or in part:
PT/2/A/261/07
Emergency Condenser Cooling Water Gravity Flow
Test (Unit 2)
PT/3/A/202/11
High Pressure Injection Pump Performance Test
(Unit 3)
PT/0/A/160/03
Reactor Building Cooling System Engineered
Safeguards Test (Unit 2)
PT/2/A/600/22 Motor Driven Emergency Feedwater Pump Suction
Check Valve Test (Unit 2)
- Unresolved
items are matters about which more information is required to
determine whether they are acceptable or may involve violations or deviations.
6
PT/0/A/600/15 Control Rod Drive Movement (Unit 1)
TT/2/A/0711/10 Low Power Physics Testing-Measurement of
Temperature Coefficients.
b.
Reactor Building Cooling System Dropout Plates
In response to observations made during the review of a licensee's
Problem Investigation Report (PIR)
concerning maintenance
on the
Reactor Building Cooling Unit (RBCU)
the inspectors looked
into the operation and testing of the RBCUs.
The Reactor Building
Cooling
(RBC)
System is provided to remove heat from the reactor
building (RB) following an accident and to cool the RB during normal
operation. The Reactor Building Spray system also removes
RB heat
following an accident. The RBCU system consists primarily of 3 axial
flow fans, motor-operated discharge damper.s,
fusible linked dropout
plates and associated distribution ductwork. The discharge dampers
are not treated as safety related components because between the
outlet of each cooler and its motor-operator discharge damper is a
dropout plate. These plates are a'ttached to the RBCU ductwork with a
hinged bracket and fusible metal link arrangement. The fusible links
are designed to melt at approximately 150 degrees F, releasing the
hinged brackets and allowing the plates to drop clean of the ductwork
to provide an
RBCU exhaust path (regardless of damper or lower
ductwork condition).
The inspector after discussion with the
licensee noted that functional testing of the dropout plates had not
been
performed,
and
no preventive maintenance
or surveillances
had been performed
on these plates since their installation.
It
should be noted that the licensee had recently formulated a plan to
functionally test the RBC system. This test will probably include a
test of the fusible dropout plate, operation of the fans and coolers
and airflow measurements
through the fusible patch
pathways at
elevated containment pressures (simulating
"accident" pressures)
following conduct of the Integrated Leakrate Test (ILRT).
This test
is tentatively scheduled for the End of Cycle 11 Unit 1 outage (the
next scheduled ILRT outage).
The inspector during a tour of the RB examined the dropout plates,
particularly the hinged bracket and fusible link arrangements. As a
result of concerns expressed by the inspector, the licensee also
conducted an inspection of the dropout plates (Work Request 53447G)
just prior to RB closeout. This inspection verified that the path
way was clear for the plates to drop,
connecting hardware
on the
fusible links was correctly installed, and retaining cables were of
sufficient length to allow the plate to drop free of the opening if
actuated. A sampling of the fusible links was examined to ensure
that the links were the proper type. The bracket hinges were cleaned
and lubricated.
While the favorable results of this inspection
answered the inspector's questions about the operability of the
7
dropout plates,
such operability checks should be performed each
refueling cycle. Although each plate is 30 square feet in area, with
full fan outlet pressure against it
if
the dampers or ductwork are
blocked and the plates operation is mostly passive in nature, their
correct functioning is relied upon for removal of
RB heat under
accident conditions. A simple verification that the ability of the
plates to dropout has not been defeated should be required.
This
item is identified as Inspection Followup Item 269,270,287/88-08-03:
RBCU Dropout Plate Inspection.
The inspectors agree that the licensees planned functional testing of
the RBCU's will more thoroughly verify the post-accident capabilities
of the RBC system and should be conducted as planned at the next ILRT
outage. This item is identified as Inspection Followup Item 269/88
08-04:
Functional Verification Testing of the Reactor Building
Cooling System Dropout Plates.
No violations or deviations were identified.
6.
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,
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.
b. Failure to Properly Identify Component Prior to Performing Mainte
nance
On February 11, 1988, a spill of 400-600 gallons of radioactive water
occurred as a result of operator error during maintenance on a High
Pressure Injection (HPI)
System instrument root valve.
Details of
the incident are set forth in Inspection Report 269,270,287/88-01.
.The inspectors have reviewed the results of the licensees investiga
tion into the incident and the completed and planned corrective
actions.
Although errors
made
by personnel
in the
operation,
maintenance,
and planning and scheduling departments contributed to
this incident, the inspectors concur with the root cause identified
as failure on management's part to ensure an adequate component
verification program was implemented. Through a series of errors,
an orange tag (used to help locate and identify equipment needing
repairs) was attached to the incorrect instrument root valve (Unit 1
instead of Unit 2).
The procedure which addresses orange tags gives
no guidance as to how this tag is to be used.
Additionally, a
8
photograph of the wrong valve was attached to the work request and
some incorrect location guidance was written on the work request.
These errors occurred primarily due to poor communications, personnel
error and the fact that both valves (Unit 1 HPI instrument root valve
and Unit 2 HPI instrument root valve) are located at opposite ends of
the same room and are identical unlabeled valves.
When maintenance
workers entered the HPI room to work on the Unit 2 HPI instrument
root valve, they compared the number on the work request with the work
request number on the posted orange tag.
They also compared the
photograph of the valve to the actual valve. Satisfied that they had
located the correct component,
they began mistakenly working on the
Unit 1 HPI instrument root valve. Since Unit 1 was operating at full
power the ensuing spill occurred as the valve packing was loosened.
Despite the numerous personnel errors which contributed to this
incident, the emphasis must always be placed on the vital role of
absolute correct component verification by workers about to begin
maintenance on any safety related equipment.
The
importance of
this verification process has long been recognized as an essential
contribution to plant safety especially at this three unit site. The
resident inspectors closely monitor the
implementation of this
process and other licensee measures to prevent wrong unit or wrong
train events.
On February 25,
1988, valve 2MS-83,
a 6" main steam check valve in
the supply line to the turbine driven emergency feedwater pump on
Unit 2, was
removed in error.
The valve that was supposed to be
removed was 2MS-85 (another 6" check valve). This problem occurred,
in part, because the orange tag was on a column in the general area
of the valve and a photograph was taken of MS-83 not MS-85.
Adding
to this problem was that the tags and labels had been removed when
the lagging was removed.
On
February 20,
1988,
workers entered an incorrect room to begin
maintenance on an important primary valve, discovered their mistake
during component verification and immediately corrected themselves.
This error was recognized by the workers although no procedure has
been developed for assuring that correct component verification has
been performed prior to commencing work on a component.
The licensee has implemented a component verification documentation
system to provide some assurance that the component is the correct
component, but there are
no instructions provided to workers
detailing methods to perform this verification.
This is
a very
important process,
especially at a three unit station where many
instrumentation valves are not labeled.
The lack of a formal
documented program for performing correct component verification is
identified as Violation 269,270,287/88-08-05; Failure to Provide
Procedures to Perform Component Verification on Components Requiring
Maintenance.
9
c.
Runback During Control Rod Drive system Maintenance (Unit 3)
A Unit 3 control rod (Group 4, Rod 2) position indication reed switch
malfunctioned on March 27, 1988. This caused an erroneous indication
of that rods Absolute Position Indication (indicated less than fully
withdrawn).
Since the rod was indicating greater than 7 inches
difference between its position and the average position of Group 4
rods,
an "asymmetric
fault" signal was generated within the rod
control circuitry.
Since the unit was operating at greater than
60 percent of full power a Control Rod Drive (CRD)
"Out Inhibit"
condition was activated. The Integrated Control System (ICS) cannot
automatically move Group 7 rods outward.
Under normal operation the
ICS automatically positions Group 7 rods to control reactivity as
required by the ICS generated "neutron error'" signal.
Operation of
Unit 3 has continued with the rod control station being placed in
manual if outward rod motion is required. Inward rod motion and rod
trip functions have not been affected. On March 29 at approximately
1:00 p.m.
an Instrument and Electrical (I&E)
Technician performing
trouble shooting of this problem inadvertently caused
a reactor
runback.
The apparent cause of the runback was that the outlimit
fuse for Rod 2 of Group 4 was pulled out of the circuit.
Since the
ICS was in automatic and an "asymmetric fault signal" was present, a
runback was initiated. The control room operators immediately took
action to verify that an actual dropped rod had not occurred and
began taking the ICS to manual.
The technician replaced the fuse
and the runback was terminated at about 96 percent full power.
The
licensee has initiated a Problem Investigation Report addressing the
event. The reason for the fuse being pulled while the ICS was still
in automatic is being investigated.
Pending further examination
by the licensee and the inspectors,
this item is identified as
Unresolved Item 287/88-08-06: Runback During CRD System Maintenance.
7.
Resident Inspector Safeguards Inspection (71881)
In the course of the monthly activities, the Resident Inspectors included
review of portions of the licensee's physical security activities.
The
performance of various shifts of the security force was observed in the
conduct of daily activities which included; protected and vital areas
access controls, searching of personnel,
packages and vehicles, badge
issuance and retrieval, escorting of visitors, patrols and compensatory
posts. In addition, the inspectors observed protected area lighting and
protected and vital areas barrier integrity,
and verified interfaces
between the security organization and operations or maintenance.
No violations or deviations were identified.
10
8.
Inspection of Open Items (92701)
The following open items are being closed based on review of licensee
reports,
inspection,
record review, and discussions with licensee
personnel, as appropriate:
(Closed) 88-BU-01:
Defects in Westinghouse Circuit Breakers.
Based
on the licensee's response dated March 7, 1988, which states that
Oconee Nuclear Station does not utilize Westinghouse
DS circuit
breakers in any class 1E applications, this item is closed.
9.
Radiation Protection Procedures for the Resident Inspector (71709)
The inspector continued to look closely at selected radiological protec
tion program activities to ensure compliance with requirements
and
licensee procedures.
Because of the Unit 2 refueling outage and its
associated work
in radiological
areas, the inspector had frequent
opportunities to
observe implementation of radiological
protection
procedures. The inspectors noted an apparent inconsistency in the wearing
of personnel monitoring equipment. It was observed that many personnel
wear both their film badge and direct reading dosimeter on a neck chain
inside their Anti-C coveralls. This is contrary to posted examples and
training conducted on the proper way to don coveralls and wear dosimetry
equipment. The concerns are that the beta detection window on the film
badge may not be facing outward and also that it
is difficult for
personnel to check the reading on their pocket dosimeter once inside
areas if
it
is worn inside the coveralls on a neck chain. The inspector
discussed these observations with licensee management.
After some
analysis, the licensee acknowledged that enforcement of proper wearing of
personnel monitoring equipment has been inconsistent. The station manager
issued a Staff Note to all station personnel prohibiting the use of neck
chains for dosimetry devices whenever cloth coveralls (with a pocket) are
being worn.
The inspectors will continue to observe radiological protection activities
with emphasis on correct wearing of dosimetry equipment.
10.
Meeting With Public Officials (94600)
On March 21 at 4:00 p.m.,
the inspectors met with local officials from
Pickens County.
At the county council meeting
held in the Pickens
Courthouse,
the residents made a presentation that introduced the
inspectors and discussed the NRC responsibilities both in Washington and
Region II. The inspectors also provided the officials with names of NRC
supervisory personnel and phone numbers locally and in Atlanta.
The following local representatives were present at the meeting:
Mr. Robert R. Nash, Pickens County Council Chairmen
Mr. Weyman B. Dublin, Jr., Vice Chairman
Mr. Charlie D. Grant, Councilman
Mr. 'Claude V. Marchbanks, Councilman
Mr. Marion C. Owens, Councilman
Mr. Weldon Day, Administrator
Mr. Bill Hendricks, S.C. State Representative
Copies of the outline.attached to Inspection Report 269,270,287/88-01 were
provided to interested personnel present at the meeting.
The resident inspector met individually with Mr. Larry Abernathy, Mayor of
Clemson at Clemson City Hall on March 31. Mr. Abernathy was given a copy
of the above outline and the inspector held a discussion with him covering
the material presented at the two previous county council meetings.
11.
Confirmatory Order Concerning Reactor Building and Decay Heat Removal
Coolers
Problems caused by fouling of reactor building cooling units (RBCU)
and
low pressure injection (LPI)
decay heat removal coolers and lake water
temperatures have been a subject in several reports in 1987,
including
Report Nos.
50-269,270,287/87-13,17,25,29,30 and 44.
NRC Confirmatory
Orders of April 10,
1987 and August 19,
1987,
placed restrictions of
Operation
on Oconee Unit 2.
The orders required that Unit 2 not be
operated at any power levels after the end of cycle 9 until the LPI and
RBCU coolers had been cleaned and tested and had been approved for full
power operation by Region II.
The licensee cleaned and tested the coolers during the EOC 9 refueling
shutdown.
The licensee determined that Unit 2 could be safely operated
at power levels up to 100% with Lake Keowee water temperatures up to 85
degrees F.
Region II
personnel
witnessed cleaning and testing
and
reviewed the findings.
On April 7,
Region II
lifted the restrictions
imposed by the Confirmatory Orders.
12.
Information Meeting With DPC Staff Concerning Emergency Power Switching
Logic At Oconee
On April 12,
1988,
Duke Power Company met with Region II staff in the
Atlanta office to provide information concerning a situation identified
by DPC in which Oconee had operated outside of their design basis for a
limited period of time. This concerned the very complex Emergency
Power
Switching Logic (EPSL)
which is designed to insure a reliable source of
power is available to safety-related components required to maintain the
plant in a safe condition.
At this meeting, DPC personnel provided a
12
basic explanation of how the EPSL system functioned and the events that
identified how the operation outside of the design basis occurred.
The
information provided showed that the conditions needed to place the plant
in this situation were very rare and had occurred only five times since
the plant commenced operation and each of these times were for less than
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
In addition, a probabilistic risk analysis was performed for
this condition and the results indicated an E-7 core melt frequency.
The
licensee is developing detailed procedures to assure the plant is not
placed into this condition during future maintenance involving components
associated with the EPSL system.
Additional information concerning this
occurrence is contained in LER 269/88-04 dated April 6, 1988.
The licensee has performed additional review of this subject and has
concluded that the root cause of this problem is not a design deficiency
as described in LER 269/88-04,
but is due to an inadequate procedure.
They will be submitting a revision to this LER in the near future. Based
on the Licensee's discussion in Region II, the information provided in LER 269/88-04, and the resident inspectors in depth review of this occurrence,
this item is identified as a Licensee Identified Violation (LIV) 269,270,
287/88-08-07:
Lack of Adequate Procedures for Isolation of Equipment
Containing EPSL Components.
This is based on the guidance provided in
10 CFR 2 Appendix C section V.A which allows the
NRC to not issue a
violation that meets the following tests:
(1) It
was identified by the licensee -
this was identified by the
licensee while performing a design engineering review of a Technical
Specification Interpretation requested by the operating staff at the
plant.
(2) It fits a severity level IV or V -
due to the extreme improbability
of this series of events occurring (i.e. a LOCA and a loss of offsite
power within 20 to 25 seconds -
anything less than 20 seconds or
greater than 25 seconds would not create this problem, while work was
being conducted causing these control power fuses to be removed),
which was calculated to be E-7, the severity level would appearto be
level IV.
(3) It
was reported -
the report was made as required by 10 CFR 50.72
section (2)(iii)(D).
(4) It
is being corrected -
procedures are being developed to prohibit
activities
that will
allow this condition to occur.
Interim
corrective actions have also been established.
(5) It
was not a violation that- could reasonably be expected to have
been
prevented by the licensee's corrective action for a previolus
violation.
13
13.
Unit 2 End of Cycle 9 Refueling Outage (71711) (Unit 2)
The Unit 2 refueling outage was completed on April 6 approximately 4
days ahead of schedule.
Major work reformed during the outage included
chemical cleaning both OTSG's,
refueling, installing dams in the primary
side of cold legs, eddy current testing and plugging and sleeving of steam
generator tubes, work on all four reactor coolant pumps and motors,
and
various non-safety related work.
Portions of the startup and power
escalation following the outage were observed by the inspectors.
The
evolutions observed were conducted in accordance with approved procedures
that had been appropriately revised to reflect changes made during the
outage period.
No violations or deviations were identified.