ML20128L597
| ML20128L597 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 05/31/1985 |
| From: | Bryant J, Dance H, King L, Sasser M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20128L557 | List: |
| References | |
| 50-269-85-10, 50-270-85-10, 50-287-85-10, NUDOCS 8507110384 | |
| Download: ML20128L597 (14) | |
See also: IR 05000269/1985010
Text
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
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101 MARIETTA STREET, N.W.
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Report Nos.:
50-269/85-10, 50-270/85-10, and 50-287/85-10
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242
Docket Nos.: 50-269, 50-270, and 50-287
License Nos.:
Facility Name: Oconee 1, 2, and 3
Inspection Conducted: Ap il 11 - May 13, 1985
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Approved by:
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H. C. Dance, Section Chief
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Date Sigfied
Division of Reactor Projects
SUMMARY
Scope: This routine, unannounced inspection entailed 353 inspector-hours on site
in the areas of operations, surveillance, plant trips, inspector followup items,
quality assurance, and plant startup from refueling.
Results: Of the six areas inspected, no items of noncompliance or deviations
were identified in five areas; one item of noncompliance was found in one area
(Violation 270/85-10-01; Control rod position limits exceeded).
8507110384 850603
ADOCK 05000269
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- M. S. Tuckman, Station Manager
- J. N. Pope, Superintendent of Operations
T. Barr, Superintendent of Technical Services
- T. Owen, Superintendent of Maintenance
- R. Bond, Compliance Engineer
- T. C. Matthews, Technical Specialist
- R. Ledford, Quality Assurance (QA) Supervisor
- R. Knoerr, Project Services Engineer
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
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- Attended exit interview
2.
Exit Interview
The inspection scope and findings were summarized on May 14, 1985, with
those persons indicated in paragraph 1 above.
The violation (para. 10),
unresolved items (para. 14 and 15),'and inspector followup items (para.12
and 16) were discussed in more detail.
The licensee did not identify as proprietary any of the materials provided
to or reviewed by the inspectors during this inspection.
3.
Licensee Action on Previous Enforcement Matters
Not inspected.
4.
Inspector Followup Items
(Closed) Inspector followup item 269, 270, 287/84-01-01; Review reactivity
balance procedure retention. The reactivity balance procedures have been
changed from operating procedures to periodic test procedures. Information
is retained in the master file. The procedures files for all three units
have all been reviewed by the residents.
5.
Unresolved Items
Unresolved items are matters about which more information is required to
determine whether they are acceptable or may involve violations or
deviations. Two unresolved items were identified during this inspection and
are discussed in paragraphs 14 and 15.
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6.
Plant Operations
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.
Interviews were conducted with plant operations, maintenance,
chemistry, health physics 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 Section 3.18 of the station directives.
The complement of
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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
Station Yard Zone within the Protected Area
Unit 2 Reactor Building
During the plant tours, ongoing activities, housekeeping, security,
equipment status, and radiation control practices were observed.
Unit 1 tripped from 100% power on April 11, 1985, due to a loose connection
of an EHC circuit board. The reactor was taken critical at 7:46 p.m.. on
April 11 and tripped from about 17% power at 10:46 p.m. due to fluctuations
in turbine header pressure and was critical again at 12:57 a.m. on April 12.
These trips are discussed in paragraph 9 of this report. The unit operated
at essentially full power until 5:33 a.m. on April 25. Statalarm power was
lost at 4:48 a.m., and an Alert declared at 5:12 a.m.
The unit was critical
at 3:57 a.m. on April 26, power was later reduced from 6% to subcritical to
permit entry into the reactor building to open a letdown valve that would
not open remotely. The reactor was again critical at 8:51 a.m. on April 26.
This event is discussed in paragraph 12.
The reactor operated at essen-
tially full power for the remainder of the report period.
Unit 2 began the report period in refueling shutdown. The reactor was made
critical at 12:10 a.m. on April 20, and startup physics testing was begun.
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Physics testing was completed and the reactor critical again about 1:00 p.m.
on April 21. Power was increased to 20% and held there due to ICS problems.
At 11:00 a.m. on April 22, the reactor received an anticipatory trip due to
loss of MFWP A, the only feedwater pump in operation.
This trip is
discussed in paragraph 11. The reactor was critical at 1:27 p.m. and power
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was increased to 72%. It was limited there due to apparent buildup of crud
in one steam generator and consequent reactor cooling imbalance.
Unit 2
tripped at 11:07 a.m. on April 26 due to a problem in the EHC system. This
trip is discussed in paragraph 13.
The reactor was made critical at 1:38 p.m.
on April 26 and power increased to 72%, as limited by steam generator
levels. On April 29, the reactor coolant pump 2B1 seal pressures began
acting erratically. A subsequent evaluation led to the conclusion that the
first stage seal had failed. After monitoring the seal instrumentation and
through discussions with the seal manufacturer, Bingham, the licensee
decided to continue operations until late June at which time an outage is
scheduled for mechanical cleaning of the steam generators.
The unit remained
at 72% power through the end of the reporting period.
Unit 3 began the reporting period at 100% power, but with a failed reactor
building cooling unit.
The failed unit was repaired with the reactor at
power.
Repairs required longer than the seven days permitted by the TS;
however, an emergency change to the TS permitted the increased time.
The
unit continued operation at 100% power throughout the reporting period.
7.
Surveillance Testing
The surveillance tests listed below were reviewed and/or witnessed 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, prere-
quisites were met, tests were conducted according to procedure, tests were
acceptable and systems restoration was completed.
Surveillances witnessed in whole or in part are as follows:
PT/2/A/015022C Valve functional testing during refueling outage
IP/0/A/3303A Control rod drive rod drop time test, Unit 2
Completed surveillances reviewed are as follows:
WR 90349C Annual fire protection test of warehouse #4 dry pipe valve
system after performance test
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WR 56842 Perform Keowee underground breaker interlock test on ACB 3
and ACB 4
WR 55055B Perform the capability test on the SSF 'DCSF' battery
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WR 55053A Perform E/S system logic sub system 1, LPI channel 3 on line
instrument calibration
WR 55314A RPS Channel A on line test
8.
Maintenance Activities
Maintenance activities were 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.
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.
Portions of several maintenance activities were observed in
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progress.
Completed maintenance work requests reviewed are as follows:
WR 50588 Repair penetratic s 1-N-N-5.
Remove firewall 50 and repair
with RTV foam
WR 501950 Leak repair on B core flood tank .nanway
WR 501090 Cell 8 in battery bank SY-2 reads SG 1.207. Bank average is
1.220.
Install single cell charger.
WR 54326C Install 4 new front frames assemblies on Unit 1, 2, & 3 CRD
breakers
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9.
Unit 1 Trip Due to Intercept Valves Closing
Unit 1 tripped from 100% power at 12:28 p.m. on April 11, 1985, when turbine
intercept valves closed, without known cause, resulting in a reactor high
pressure trip. Reactor systems responded normally to the trip and there was
no ESF actuation.
The events recorder printout was essentially identical to that of the Unit 1
trip of January 22, 1985 (see Report No. 50-269/85-03). Following the trip
in January, a cause was not found for the occurrence.
Following the
April 11 trip, a thorough examination of turbine control circuits was
performed. A loose connection on a card was found which, when manipulated,
signaled shaft overspeed and caused the intercept valves to close.
The reactor was started up at 7:46 p.m. on April 11 and the turbine placed
on line at 10:31 p.m.
At 10:46 p.m. fluctuations in turbine header pressure
caused a swing in RCS pressure and the reactor tripped from low power.
Dirty potentiometers were found in the integrated control system (ICS) which
may have caused the fluctuation. The unit was restarted and was critical at
12:57 a.m. on April 12.
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Following the first trip, main steam relief valves (MSRV) 2 and 10 failed to
close until the secondary system pressure was reduced to about 900 psig and
one of them continued to weep until pressure was reduced to 850 psig.
MSRV's 2 and 10 were tested and relief points reset prior to reactor
startup. Failure of MSRV's to reseat has been a subject in several recent
reports and is being examined by the licensee (see Report No. 50-269/85-07).
No violations or deviations were identified.
10.
Inadequate Shutdown Margin, Unit 2
On 4/21/85 at 10:55 p.m. , the Unit 2 control room received a Statalarm
indication of " rod withdrawal limits".
The nuclear control operator (NCO)
compared the control rod positions with the station procedure for the
allowable limits for maintaining adequate shutdown margin and determined
that the rods were in the unallowable region. At the time, reactor power
was 15% and group 5 control rods were 70% withdrawn. Boron addition to the
RCS was initiated immediately and the control rods were within limits by
12:55 a.m., 4/22/85. A subsequent evaluation by licensee Compliance staff
determined the control rod position had violated TS 3.5.2.5, control rod
positions.
Earlier during the day of this event, zero power physics testing (ZPPT) had
been completed at which time the reactor was lef t at 0% power with control
rod positions of group 5 at 0% withdrawn.
That position, although not in
violation of shutdown margin, was close to the limits. During the following
power escalation to 15% the RCS was not adequately borated to withdraw
control rods enough to remain within position limits. Operations estimated
the limits were exceeded sometime after 5:00 p.m. on 4/21/85. The condition
was not discovered during shift surveillances during and after shift
turnover.
The basis for the TS limit is to maintain a shutdown margin of at least 1%
delta k over k.
The maintaining of adequate shutdown margin through control
rod position is an operational and TS requirement.
Failure to do so is
cited as Violation 270/85-10-01, Exceeding control rod position limits.
11.
Unit 2 Trip From 20% Power
Unit 2 tripped form 20% power on 4/22/85 at 11:00 a.m.
The unit had started
up from refueling outage and was maintaining power at 20% due to diffi-
culties with the integrated control system (ICS). Only one main feedwater
pump was operating at that power level.
The event was initiated while
attempting to close a breaker to place ventilation equipment in service.
Upon closing the breaker, power to the 600V motor control center (MCC)
feeding the breaker was lost. This led to the feedwater pump auxiliary oil
pump, also fed from the MCC, being tripped resulting in low oil pressure on
the feedwater pump turbine control system. The feedwater pump then tripped
and the reactor tripped due to loss of feedwater (anticipatory trip).
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Emergency feedwater responded as required to maintain steam generator water
levels. There was no ESF actuation. All main steam relief valves reseated
properly and other systems responded as designed.
Troubleshooting located a ground fault in the ventilation equipment breaker.
Upon correction of the ground fault and completion of all post trip
evaluations the reactor was made critical at 1:27 p.m. on April 22.
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No violations or deviations wuee identified.
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12. Unit 1 - Alert and Trip Due to Loss of Control Room Annunciators
Brief Description
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An alert was declared at 5:12 a.m. on 4/25/85 in accordance with the Oconee
emergency plan after most of the Unit I control room Statalarms were lost
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due to failure of an inverter power supply at 4:48 a.m.
The plant remained
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stable and instrumentation and controls were operable.
Loss of Statalarms
was due to loss of the Ikx inverter, and its failure to transfer, which
feeds the 120 Vac auxiliary panel board.
Power was restored at 5:31 a.m.
and at 5:33 a.m. the reactor tripped due to feedwater oscillations which
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occurred when feedwater began responding to a signal which was generated
while power was off. All systems responded normally and there was no ESF
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actuation.
Cause of Failure
The event was initiated by an electrical short, apparently due to heat
deterioration of insulation, in the ikx inverter feeding the 120 Vac
auxiliary panel board.
This short interrupted power output from the
inverter. There should have been an automatic switchover to the regulated
AC power source; however, this did not occur because of broken solder joints
which had apparently failed due to vibration.
As a result of the failure, Statalarms were received indicating trouble with
the 120 Vac power supply. Also, most of the control room Statalarms were
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lost. This AC power also supplied the turbine driven feedwater pump speed
controller gear unit.
Operator Action
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An operator, followed by I&E personnel, was immediately dispatched to the
equipment room to check the inverter, as required by procedure. Assessment
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of conditions revealed that all plant controls appeared to be functioning
properly, indicating the reactor to be in a stable condition. Concurrent
with assessment of plant conditions, operations personnel reviewed the
appropriate emergency procedures to determine what action was required. At
5:12 a.m. it was determined that, in accordance with the emergency plan,
loss of most or all alarms in the control room required declaration of an
alert.
The alert was declared, site assembly procedures initiated, and
notification of required local, state, and NRC officials begun.
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Upon loss of the annunciators, the operations supervisor decided not to trip
the reactor since there was positive indication that the reactor was stable
and to trip the unit would introduce a transient during the time when vital
annunciators were not available.
Personnel in the equipment room determined immediately that an indicator
light was illuminated, indicating that power had switched to the regulated
power supply.
It developed later that this light was powered by a logic
circuit and only indicated that the demand for automatic switchover had been
made. After finding no reason for ac power failing to reach the annunciator
panel, it was discovered that the transfer to regulated ac had not actually
occurred, despite the indication that it had.
Upon checking with the
control room, operators transferred power with the manual switch at 5:31 a.m.,
restoring the Statalarms.
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Restoration of power initiated oscillations in the ICS, primarily in the
feedwater system.
In an attempt to control feedwater swings, the RO took
manual control of feedwater. However, FWP A tripped seconds later and FWP B
tripped at 5:33 a.m. , resulting in an anticipatory reactor trip.
All
systems responded normally to the trip with the exception of two main steam
relief valves which did not reseat at the proper pressure. One did not
reseat completely until pressure was reduced to 825 psig.
Main feedwater was restored at 6:02 a.m. and the alert was terminated at
6:33 a.m. on April 25.
Cause of Feedwater Trip
Apparently, during the 40 minutes without power a small, normal feedwater
oscillation caused a demand from the ICS for increased FW flow, causing the
FW valves to begin opening.
Decreased pressure drop across the FW valves
gives a signal to the FW pumps to increase speed. However due to loss of
power to the FWP turbine gear controller, the FW pumps were unable to
respond. When power was restored, FW pumps accelerated in response to the
then fully open FW valves.
Six seconds after powar was restored the
operators began a series of operations of taking FW pumps and valves to
manual, back to auto, and the pumps back to auto in an attempt to balance
the system.
Valve operation is considerably faster than pump response,
which contributed to failure of their efforts.
FWP A tripped on high discharge pressure one minute and six seconds after
power was restored, and a reactor power runback began.
FWP B tripped 19
seconds later followed immediately by a reactor anticipatory trip.
Summary
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Modifications to the inverters to improve circuit reliability have been
completed on Units 1 & 3 and partially completed on Unit 2.
These modifi-
cations will be completed as soon as possible.
The inverter transfer
indicating light will be modified to give a positive indication of transfor.
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Operator training concentrates primarily on safety related issues.
The
operators receive considerable training on loss of instrumentation in the
classroom and on the simulator. Training covers power supplies to basic
equipment including power supplied by inverters.
Power supplied by
inverters is covered, dealing mainly with basic equipment such as integrated
control system and electro-hydraulic control system, but is not detailed
about specific parts of the basic equipment.
Training does not deal in
detail on what to do with losses of power to specific parts of non safety
related equipment.
The licensee is reviewing the incident to determine
possible changes to the training program, particularly concerning the ICS
and EHC systems, to improve response to similar events.
procedures are being reviewed by the licensee to determine what changes
might be made which could have been of assistance in handling the loss of
inverter power or similar events.
In retrospect, the trip probably could have been avoided by taking the FWP
turbines and FW valves to manual mode before restoration of power, balancing
the error signal, then returning to automatic and restoring power. However,
there are 12 auto / manual stations for the ICS. Normally, only one at a time
is placed in manual in order to maintain plant stability. To attempt to
balance all of these prior to restoring inverter power would have extended
the time without power prohibitively. The licensee will evaluate procedures
to determine possible improvements.
The inspectors determined that the operating staff was responsive and
performed correctly under the conditions given.
The safety valves which
were slow to reseat are scheduled for rework on the next cold shutdown of
sufficient duration.
No violations or deviations were identified.
The resident inspectors will
followup on licensee actions described above: namely, (1) modifications to
inverters, (2) changes to operator training program, and (3) procedure
changes. This is identified as an inspector followup item 269, 270, 287/
85-10-02, Modifications and training concerning power loss.
13.
Unit 2 Trip Due to Electro Hydraulic Control (EHC) System
Unit 2 tripped at 11:07 a.m. on April 26, 1985 due to a problem in the EHC
system. At the time of the trip, maintenance personnel were working in the
EHC cabinet.
Cause of the malfunction has not been determined and no
questionable component has been identified; however, the turbine received a
load imbalance signal and began running back to reduce steam flow.
Since
there was no actual imbalance, reduction of steam flow created an imbalance.
The reactor began power reduction but apparently could not reduce rapidly
enough and tripped on high pressure. All systems responded normally and
there was no ESF actuation.
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The inspectors witnessed the startup to criticality which was achieved at
1:38 p.m. on April 26.
The generator was placed on line at 5:29 p.m.
No violations or deviations were identified.
14.
Unit 2 Reactor Coolant Pump (RCP) Stud Procurement
On April 24, 1985, the resident inspectors were informed by the licensee of
an evaluation in progress of apparent document discrepancies which involved
procurement of Unit 2 RCP studs from Rocky Mountain Nuclear (RMN) of Salt
Lake City, Utah. The studs had been installed and the unit was then at 60%
power following a refueling shutdown.
On April 25, the residents and a
Region II inspector reviewed QA documents, discussed the situation with site
QA personnel, and discussed it with corporate licensing personnel in order
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to evaluate the engineering decision which permitted continued reactor
operation.
The inspectors concurred with the licensee's decision to
continue operation. The sequence of events and basis for the decision are
described in the following text.
On March 15, 1985 the licensee's general office (GO) vendor QA section gave
Oconee site QA a verbal release for use of the RCP studs, even though a
documentation problem had been identified in which the QA paperwork did not
contain the required statement that weld repair had not been done on the
stud material.
The G0 had verified with RMN that the documents could be
corrected.
Oconee QA then released the studs for installation after
ompletion of visual and UT examination.
On April 17, GO QA notified site QA of a continuing problem with RMN
paperwork and that a GO vendor audit of RMil would be conducted on April 22.
Since the problem appeared to be in the paperwork, the QA department decided
not to delay Unit 2 startup.
Based on results of the April 22 audit of RMN the QA department initiated a
nonconforming item report (NCIR) to document what then appeared to be
problems of a more serious nature than previously thought. The NCIR stated
that the RCP studs were not supplied in accordance with ASME section III
based on the following:
1.
Material for the studs was procured by RMN from an unapproved
supplier.
2.
Material supplied to RMN was not ordered ASME.
3.
RMN vendor, Fry, procured material from Timken and altered
Timken's Certified Mill Test Report (CMTR).
4.
Timken's CMTR did not reference ASME III, NCA 3800 program.
5.
RMN tested each heat lot, not each piece of stock as required by
ASME III, NCA 3867.4 e.
The licensee's procurement document had
specified the ASME requirement but had also specified that each
heat / lot be tested.
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The Duke engineering evaluation which determined the studs to be acceptable
was based on several reasons which included the following:
1.
The results of the Oconee visual and ultrasonic examinations were
acceptable.
2.
RMN had elected not to purchase the material as ASME certified but
to upgrade it at RMN to meet requirements of NCA 3867.4 e.
3.
RMN had heat treated the material, composed of 14 pieces of bar
stock all from the same heat, and had met the requirements of
ASME III except that it had tested only five pieces of the stock.
Testing of five pieces exceeded the requirements of the Duke
purchase order.
The Duke auditor found that alteration of the Timken CMTR was an attempt to
correct a mistake on the original QA documents which should have been
corrected by an official letter from Timken rather than by checking with
Timken and then altering their documents as was done by Fry. No evidence of
intentional falsification or fraud was found by the QA auditor and RMN acted
in good faith to correctly supply the materials and documentation. The
engineering decision is being documented in detail in a Duke evaluation
report.
The inspectors verified that RMN is on the Duke approved vendors list, and
has been audited by Duke within the prescribed time frame.
The Duke Power
Company QA Manual, Duke-1, as implemented by the QA Department QC procedures
manual, procedure QCG-1, step 4.4.1.c,
states, " Items shall be verbally
released when the required documents above are not present on-site, but are
located within the Duke system". It appears that step 'c' was not followed
in that verbal release of the studs for use prior to having QA approved
documents in the Duke system was in violation of Duke procedures. Also, the
purchase order appears to be ambiguous in referencing a code which required
testing of each piece of stock material while also requiring that only each
heat / lot be tested. Further review is needed to determine if violations of
NRC regulations occurred; therefore this item will be held at present as an
unresolved item, (UNR) 270/85-10-03, Documentation concerning reactor
coolant pump studs.
15. Response to Regional Office Notice (RON) No. 2201, " Station Battery
Operation, Maintenance and Inspection"
The inspection by the residents covered three main areas:
Review of all procedures and vendor manuals against identified problems
in the RON. The procedures reviewed are identified in enclosure to
this paragraph.
Visual inspection of the battery areas for likely problems identified
in the RON.
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Observation of the daily, monthly, and annual tests on the power and
control batteries.
Results of the procedures review indicated that tests are conducted on a
more frequent basis than required. The weekly tests are done daily and the
quarterly tests are done monthly.
Problems identified were:
Both IEEE 450 and the battery manual 0M-320-0012001 require that an
equalizing charge must be given at least three days and not more than
seven days before a capacity test. The capacity tests for Oconee do
not require an equalizing test be performed prior to a capacity test.
The procedure for operation of individual cell chargers, IP/0/A/
3000/12, does not require jumpering out of the cell or independence of
the cell charger as specified in IEEE 384-1977.
A visual inspection of the batteries revealed the following:
The filler material (styrofoam) between the cells is missing or in
pieces between the cells on the lower banks of batteries 1CA, ICB, and
2CB.
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An individual cell charger was in use on 4/10/85 which violated class
IE independence as specified in IEEE 384-1977. The charger was being
used on cell 46 of 2CA while the cell was connected in line to the rest
of the cells.
Procedure IP/0/A/3000/12, " Operation of Individual Cell Chargers", step
10.4, requires the voltage to be adjusted between 2.35 - 2.7 Vdc and
current limited to 1-10 amps. The amperage reading was 11.5 amps and
there was no needle on the voltmeter gage.
The inspectors could find no criteria as to when to change out a cell
due to its failing surveillance test (s).
Observation of daily, monthly and annual tests detected no problems.
The inspectors were informed that Oconee has made no commitment to meet IEEE 450. A search of the FSAR and TS corroborates that there is no commitment
to IEEE 450.
Until resolution to the questions raised in this paragraph have been
determined, this will be listed as an unresolved item; UNR 269, 270,
287/85-10-04; Station battery operation and maintenance.
The following procedures were reviewed:
1.
IP/0/A/400/11 Keowee 125 Vdc Control Battery Capability Test
Using EPE Battery Analyzer
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2.
IP/0/A/385/1A SSF 125 Vdc Batteries DCSF and DCSFS Daily
Surveillance
3.
IP/0/A/0385/01B SSF 125 Vdc Battery Capability Test
4.
IP/0/A/385/IC Instructions for Conducting Equalizing Charge for
SSF Batteries
5.
IP/0/A/385/1D SSF 125 Vdc Batteries DCSF and DCSFS Monthly
Surveillance
6.
IP/0/A/385/1E SSF Preventative Maintenance Procedure for Power
Conversion 35-130-1000 CE Float Charge
7.
IP/0/A/3000/1
125 Vdc I&C Battery Daily Surveillance
8.
IP/0/B/3000/1A Power Battery Daily Test
9.
IP/0/A/3000/C Removal, Installation and Jumpering of Cells
10.
IP/0/8/3000/18 525 kv Switchyard Battery Daily Test
,
11.
IP/0/A/3000/1D 230 kv Switchyard Battery Daily Test
12.
IP/0/A/3000/11
125 Vdc I&C Battery Monthly Surveillance
13.
IP/0/B/3000/11A 125 Vdc Power Battery Monthly Test
14.
IP/0/B/3000/110 230 kv Switchyard Battery Monthly Test
15.
IP/0/B/3000/11B 525 kv Switchyard Battery Monthly Surveillance
16.
IP/0/A/3000/B Cleaning and Inspection of Battery Terminals and
Intercell Connections
17.
IP/0/A/3000/1C Station Battery Capacity Test
18.
IP/0/A/3000/2A Operation of EPE Constant Current Battery Charger
19.
IP/0/A/3000/3 125 Vdc I&C Battery capability Test
20.
IP/0/A/3000/4 Instructions for Conducting Equalizing Charge for
Station Power Battery and 525 kv Batteries
21.
IP/0/A/3000/4B Instruction for Conducting Equalizing Charge for
230 kv System Batteries
l
.