ML15224A570
| ML15224A570 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 07/17/1989 |
| From: | Shymlock M, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15224A568 | List: |
| References | |
| 50-269-89-17, 50-270-89-17, 50-287-89-17, GL-88-17, NUDOCS 8908010144 | |
| Download: ML15224A570 (32) | |
See also: IR 05000269/1989017
Text
o
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION 11
101 MARIETTA ST.. N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-269/89-17, 50-270/89-17, 50-287/89-17
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC
28242
Docket Nos.:
50-269, 50-270, 50-287
License Nos.
Facility Name:
Oconee Nuclear Station
Inspection Conducted: May 20 - June 18, 1989
Inspectors:,
(',
1W
P. H. Skinner, Seniop/Resident Inspector
DatVSigned
L.
r,
esi oAt Inspector
e Signed
Approved
'y:
I
7
- '
M. B. Shymlock, Section Chief
ate Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection involved resident inspection on-site in the
areas of operations, surveillance testing, maintenance activities, safeguards
and radiation protection, outage activities, reduced inventory operations and
inspection of open items.
Results:
Two examples of a TS violation concerning procedure inadequacies associated
with the AC power distribution systems were discovered during this period.
Both situations apparently resulted from operating in accordance with
procedures which failed to adequately consider TS operability requirements.
A continuing weakness exists in the operations area due to the complexity of
the TS associated with the EPSL system and the lack of understanding of its
operation.
908 10144 -90717
ADOCK 05000269
CPDC
REPORT DETAILS
1. Persons Contacted
Licensee Employees
- M. Tuckman, Station Manager
- S. Baldwin, Nuclear Production Engineer
- C. Boyd, Site Design Engineer Representative
- T. Curtis, Compliance Manager
J. Davis, Technical Services Superintendent
D. Deatherage, Operations Support Manager
W. Foster, Maintenance Superintendent
T. Glenn, Instrument and Electrical Support Engineer
D. Havice, Instrument & Electrical Engineer
D. Hubbard, Performance Engineer
- E. Legette, Assistant Engineer Compliance
H. Lowery, Chairman, Oconee Safety Review Group
J. McIntosh, Administrative 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.H. Skinner
L.D. Wert
- Attended exit interview.
2. Plant Operations (71707)
a. The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements, technical
specifications (TS), and administrative controls. Control room logs,
shift turnover records, and equipment removal and restoration records
were reviewed routinely.
Discussions were conducted with plant
operations, maintenance, chemistry, health physics, instrument and
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.
2
Actions observed were conducted as required by the Licensee's
Administrative Procedures.
The complement of licensed personnel on
each shift inspected met or exceeded the requirements of TS.
Operators were responsive to plant annunciator alarms and were
cognizant of plant conditions.
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
Keowee Hydro Station
Station Yard Zone within the Protected Area
Standby Shutdown Facility
Units 1/2 Spent Fuel Pool Room
Intake Structure
ISFSI Construction Site
Unit 1 Reactor Building Containment
During the plant tours, ongoing activities, housekeeping, security,
equipment status, and radiation control practices were observed.
Units 1 and 3 operated at 100% power for this reporting period. The
only exception was a reduction to 93 percent power on Unit 3 at the
request of the dispatcher (load following) for about 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> on June
18.
Unit 2 entered End of Cycle 10 refueling outage May 20,
1989.
Presently the outage is scheduled to complete on July 2.
Commissioner Curtiss visited the facility on June 5, 1989.
The
Commissioner toured various areas,
including the Keowee Hydro
Station, and sat in on an outage meeting for Unit 2. The Plant
Manager provided a short briefing which discussed plant design
features,
some Oconee statistics and areas in which the plant
management is concentrating to improve maintenance.
Enclosure 3
contains a copy of the slides used by the licensee for this
presentation.
b. Fire Protection Sprinkler System
On May 22, 1989, the licensee notified the inspectors that the fire
protection sprinkler system for the cable and equipment rooms of each
unit were not properly designed such that their supply pressure
requirements would meet the current guidance for operation.
The
sprinkler system is a portion of the High Pressure Water System
3
(HPSW)
which is used for fire suppression for all units.
The system
is supplied by an elevated storage tank and two pumps. A third pump,
a much smaller jockey pump, is used to maintain level in the tank and
system pressure.
Under normal conditions the sprinkler systems in
the cable and equipment rooms are isolated.
One of the design
requirements for the sprinkler system is to provide 0.1 gpm per
square foot of space in each room.
The original calculations
performed prior to 1980, to assure that the design of the sprinkler
system met this value, used a pressure equivalent to system operation
with a running pump.
Under normal operation, the pumps are run in a
standby configuration and do not start automatically until a set
pressure drop or elevated tank low level setpoint is reached. Upon
identification of this problem, the licensee entered the Limiting
Conditions for Operations
(LCO)
associated with TS 3.17.3 and
immediately notified verbally and by memo the operations personnel
(fire brigade leaders) to start a fire pump upon any fire in the
cable and equipment room that requires the use of the sprinkler
system. This was followed by changes to the applicable fire fighting
procedures on May 23,
1989.
The inadequacy of the design of the
cable room sprinklers was identified by Licensee Event Report (LER) 269/87-11 dated January 4, 1988. At that time, piping modifications
were performed and several valves were identified that were labeled
and more closely controlled to correct this problem. Although this
LER stated that the ability to supply a flow of 0.10 gpm per
square foot of floor area was contingent upon the HPSW system
supplying 1238 gpm at a pressure of 92.21 psig to the inlet of the
sprinkler system, this information did not apparently get an adequate
review to assure the pressure at the sprinkler inlet met the design
conditions with the HPSW pumps not operating. This information was
discussed with the Region II fire protection group. This group will
review this area during their next inspection at this plant.
This
is identified as Inspector Followup Item (IFI) 269,270,287/89-17-03:
Adequacy of Fire Protection Sprinkler System Pressure.
c. Emergency Power Switching Logic (EPSL) Issues (71707)
During the report period the licensees Design Engineering (DE) group
discovered, as a result of a Design Basis Document analysis program,
several problems with the Emergency Power Switching Logic (EPSL)
system.
The EPSL system is provided to ensure that a continuous
source of power is supplied to the Oconee units under various
operating conditions. The EPSL system is a complex logic network
which is intended to ensure that the appropriate available power
source is automatically aligned to the essential loads as required
under various conditions/casualties.
The AC power system is an
interconnected set of several subsystems including the following:
-
the auxiliary power systems of each of the units (startup
transformer, main transformer and auxiliary transformer)
-
the Keowee Hydro Station and associated paths
-
the 100 KV Line from Lee Steam Station and Central Switchyard
4
The two unit Keowee Hydrostation provides emergency power when normal
and startup sources are not available. One unit provides a dedicated
underground power path (via transformer CT-4 and the Standby buses)
and the second unit a separate overhead power path (via a safety
related switchyard bus and each units associated startup transformer)
to supply power to the Main Feeder Buses (MFB)
of the
units (2 MFB
per unit which supply essential loads) when required.
The startup
transformers
(CT1,
CT2 and CT3),
which provide power in normal
shutdown conditions, are also available to supply power to the MFB in
certain casualties. The 100 KV system consisting of a 100 KV power
supply line (via CT5 and the standby buses) also provides emergency
power during certain conditions (see Enclosure 4, Oconee Emergency
Power Distribution).
At about 2 p.m. on June 7, 1989, DE identified that the TS governing
operation of the Oconee Electrical Distribution System (including
EPSL) permits an alignment which could cause the plant to be operated
in an unanalyzed condition.
TS 3.7.1(b)1.,
which requires the
underground power path from the Keowee Hydrostation to be operable,
specifically states that only one of the two standby buses is
required to be operable.
DE determined that this permits a
configuration which makes the units susceptible to a single failure
in certain conditions.
If one standby bus is out of service for
maintenance, i.e. its associated feeder breaker from Keowee, (SK1 or
SK2) and each units standby bus breaker (S1 or S2) are open, and a
Loss Of Coolant Accident(LOCA) with a concurrent Loss of Offsite
Power (LOOP) occurs, and a single failure (failure of the standby
breaker to close) from the energized standby bus, the result would be
a loss of automatic power restoration to the MFB.
-
On the LOCA unit after a 12 second delay the EPSL would sense
the voltage on the standby bus energized by a Keowee unit and
supplied via CT4.
The EPSL would not shift to the other
emergency power path (the startup source - which would be
energized from the other Keowee unit via the startup trans
former and a dedicated-switchyard bus) even though the failure
of the S1 or S2 breaker to shut would cause the MFB to remain
deenergized. This is due to a portion of the EPSL which is
called "Retransfer to Startup" which would not be actuated.
This "Retransfer to Startup" logic senses that the EPSL has, or
has tried, to transfer power for the essential loads to the
standby bus during this casualty situation. The "Retransfer to
Startup" enables a retransfer of the MFB's back to the startup
source if the standby bus loses power or if the startup bus
becomes available before power reaches the standby bus. Once the
retransfer logic is satisfied and after a 10 second time delay,
5
the Si and S2 breakers will get a trip signal and the closure of
the El and E2 (startup transformer power path) breakers can
occur. However, if the only operable S breaker does not trip,
this logic will not be satisfied.
The EPSL,
as long as it
senses voltage present on the standby bus, would not shift to
the other available source automatically. The stations Abnormal
Procedure (AP) 1700/11 "Loss of Power" section 502 provides some
guidance to the operators concerning manually energizing MFBs.
In this particular scenario that guidance alone would not have
enabled the operator to restore power to the MFB in a prompt
manner.
-
The non-LOCA units would be supplied power automatically from
their respective El and
E2
breakers via their startup
transformers and the Keowee unit through the switchyard.
(A
system called the Main Feeder Bus Monitor Panel (MFBMP)
logic
would automatically cause this to occur.)
At about 3 p.m. on June 8, 1989, a second issue closely related to
this first situation was identified.
As a part of the compensatory
action to prevent more than one unit loading simultaneously onto the
100KV (SL1 and SL2) line when being supplied by the Lee Steam Station
during a LOCA/LOOP situation, since the 100KV source had been
determined unable to support such loading (see LER 269/88-13),
a
change was made to Operating Procedure (OP) O/A/1107/03, 100 KV Power
Supply.
This change placed the S1 and S2 breaker switches in
"manual" (this action removes automatic closure ability) whenever
the 100 KV line was being utilized to energize the standby buses.
This change, unknowingly, also removed a functional unit required to
be operational for the EPSL system. Under these conditions, if a
LOCA/LOOP occurred, the following would happen:
-
On the LOCA unit, the S1 and S2 breakers would not shut
automatically as required. The EPSL circuitry would sense a
voltage on the standby buses (from Keowee via CT4)
and not
permit actuation completion of the "Retransfer to Startup"
circuitry. The MFB on the LOCA unit would remain de-energized
until the control room operators took action. In this situation
existing procedural guidance would enable the operator to
restore power quickly and easily.
-
On the non LOCA unit, the MFBMP logic would cause power to be
supplied through the overhead path and the associated El and E2
breakers.
A third issue was also identified at about 3:00 p.m. on June 8. If
one unit's MFBs are powered from the Central Switchyard and the 100
KV line via CT5and the SL1, SL2 breakers through the standby buses,
(such as during maintenance on the startup transformer) under certain
degraded voltage conditions, the EPSL would not'be able to provide a
6
power path automatically.
The low voltage signal to EPSL of the
standby bus source will be actuated only if the voltage degrades to
about 50%.
If voltage only degrades to about 60%, many of the ES
required pumps will trip or stall.
Under a LOCA/LOOP scenario, (LOCA
on a unit not supplied by the 100 KV line), since the SL1 and SL2
breakers remain shut, the SK1 and SK2 breakers cannot shut to provide
power to the MFB from the Keowee unit (the SL1,
SL2 and SK1,
SK2
breakers are interlocked).
The EPSL circuitry would continue to
sense that the standby buses are energized and a retransfer to the
startup source would not automatically occur. Operator action would
be required to restore power to the essential loads.
The licensee promptly reported these discoveries to the NRC as
required and initiated corrective actions.
Procedural changes were
made to prevent placing both S breaker switches in manual and
inadvertently effecting EPSL operability.
The CT5 (100 KV) power
path will not be utilized via Central Switchyard unless required by
the applicable Abnormal Procedure. Operators were directed not to
place standby buses out of service for maintenance or testing. A
training package discussing this action has been promulgated.
The first and third issues are relatively complex and only a detailed
examination of all possible EPSL configurations and single failures
would be expected to lead to their discovery. The second situation
(the S1 and S2 breakers being placed in manual) is a more easily
recognized scenario. This action was performed with the concurrence
of the DE group and indicates a significant lack of knowledge
throughout the licensee's work groups concerning EPSL. This lack of
knowledge has been previously addressed by various documentation
including the following:
-
LER 269/87-09 identified a condition where two functional units
of the EPSL system were taken out of service due to apparent
conflicts in TS 3.7. This LER recognized the complexity of this
system and the TS and committed to correcting this problem with
a TS amendment by July 15,1988.
This date was subsequently
changed to March 15,1989.
-
LER 269/88-04 reported that the retransfer to startup logic had
been inhibited on 'several occasions by removing the control
power fuses for the SK1 and SK2 breakers thus placing the plant
in an unanalyzed condition.
An information meeting held with
Region II on April 12, 1988 addressed that incident and included
a discussion of a scheduled Self Initiated Technical Audit among
the corrective actions.
-
In October 1988,
DE had determined several scenarios in which
standby bus voltage may have been inadequate during casualties.
It was calculated that the voltage would have been adequate for
7
2 units at power and the other in cold shutdown as long as the
standby breaker switches remained in "manual"
LER 270/89-01 reported that the station had been operated in an
unanalyzed electrical power configuration because these switches
had been left in "automatic" with the standby bus for one unit
energized
from
CT5 via the Lee station.
(Violation
50-269/89-08-02 was written to address other concerns involved
with that situation.)
-
IFI 269,270,287/88-15-01; In July 1988 the inspectors discussed
their concern about the problems associated with EPSL. At that
time they issued this followup item to assure that the licensee
would conduct additional training to operators in this area.
Although this problem was discovered as a result of a DE study of the
EPSL system, with the attention and significance being given to the
"retransfer of startup" portion of the EPSL, the licensee should have
been aware of the functions of the switch positions within the EPSL
system prior to this time.
Operation with the S1 and S2 control
switches in manual is an apparent violation of TS 3.7.1(c) which
specifies the EPSL circuits must be operable. A functional unit of
Table 3.7-1 requires operability of the S1 and S2 control circuitry
including retransfer to startup circuits. This is identified as one
example of Violation 269,270,287/89-17-01: Electrical Distribution
System TS Violations Due To Inadequate Procedures.
The safety significance of this violation is minor due to the very
low probability of the scenarios required to result in these
accidents. In addition, over the many years of operation the Oconee
electrical distribution system has been very reliable. Also in one of
the projected scenarios, procedures existed to aid the control room
operators to restore power quickly.
The inspectors continue to be concerned that the knowledge of this
complex system appears to be limited at the site. In addition, more
guidance and training should be given to operators in order to assure
their understanding of the complex and sometimes conflicting
requirements of TS 3.7, particularly in the area of EPSL functional
units. The licensee should expedite the changes needed to clarify TS 3.7, develop onsite knowledgeable personnel and train appropriate
operations
personnel
on
this
system and the TS. IFI
269,270,287/88-15-01:
Retraining of Personnel on EPSL Operation
remains open.
d. Inadequate Procedure for Testing Emergency System Actuation
On June 18, 1989 during conduct of PT/2/A/0610/01J, EPSL ES Actuation
Keowee Emergency Start Test, the operators noted that both standby
bus supply breakers from Keowee (SK1
and SK2) were open and their
breaker control selector switches were in manual. Keowee Unit Two was
aligned to the underground path and on an ES signal would not be
8
available to supply power via the overhead path.
Since Unit One of
Keowee had been placed in a locked out condition (inability to
startup on any signal) as part of the test, the positioning of these
selector switches in manual removed the circuitry that would allow
the main feeder buses to be automatically energized on an emergency
signal if a LOOP occurred.
Although this was identified by the
operators and only existed for 20 minutes, this placed the units in
an unanalyzed condition. This condition removed all automatic
emergency power restoration capabilities to the essential loads of
the two operating units. Both units one and three were aware of the
test and the actions involved by the test. Control room operators
could have rapidly restored power by operating the appropriate
breaker switches.
This condition has existed during previous
refueling outages since similar procedures are used on units one and
three. This is another example of a lack of understanding of all
aspects of the facilities complex electrical distribution system.
TS 3.7.6 requires that if all the conditions of TS 3.7.1 are not met
and planned tests or maintenance are required which will make both
Keowee units unavailable, the Standby buses shall first be energized
by a Lee gas turbine via the dedicated 100KV line.
In this case a
planned test resulted in both Keowee units being unavailable and the
conditions of TS 3.7.6 were not met. This condition could not have
been met during this test since portions of the test require the
standby buses being deenergized. However, the procedural requirement
to have the remaining Keowee unit in a locked out condition during
this part of the test was inappropriate. Keowee Unit One could have
been available to preclude this condition. This is another example of
violation 269,270,287/89-17-01: Electrical Distribution System TS
Violations Due To Inadequate Procedures,
and will be combined with
the example discussed in 2.c discussed above.
Procedures exist to
aid the operator in restoration of power had this condition occurred.
e. Discretionary Enforcement
On June 16,
1989, the licensee requested discretionary enforcement
associated with TS 4.8.2.
This TS requires that during each
refueling outage the Main Steam Stop Valves (MSSV's) be leak tested
at 59 psig. The specified allowable leakage rate is limited to less
th'an 0.25 cubic feet per hour.
In the past the licensee had
collected this leakage as a liquid and had not converted the obtained
leakage into a vapor. In converting the results of previous tests to
a vapor, the licensee determined that this TS has not been met. An
analysis conducted by the licensee had determined that there is no
design basis for this requirement and that the leakage criteria is
not required to mitigate the consequences of any accident.
The
safety function of the valves is tested by the inservice test program
(stroke time testing).
A conference call between members of the
licensee, NRC Region II management, NRC Headquarters management, and
9
the Resident Inspector was conducted on June 16,
in which the
licensee provided information concerning this subject.
Following
this discussion, the NRC granted the enforcement discretion for this
outage on Unit 2, based on the information provided and confirmation
that the licensee would generate a proposed change to the TS to
remove this requirement by July 14,
1989.
Based on the licensee's
report that a violation of TS 4.8.2 has occurred on past unit
outages, a violation will be identified associated with this problem.
This violation is not being cited because the criteria specified in
Section V.G of the Enforcement Policy were satified. This item is
being identified as a non-cited violation (NCV)
50-269,270,287/
89-17-02, Failure to Perform Appropriate Testing As Required By TS 4.8.2. and based on the actions taken by the licensee and review by
the inspectors, this item is closed.
No additional violations or deviations were identified.
3. Surveillance Testing (61726)
a. Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy.
The completed tests reviewed
were
examined for necessary test prerequisites,
instructions,
acceptance criteria, technical content, authorization to begin work,
data collection, independent verification where required, handling of
deficiencies noted,
and review of completed work.
The tests
witnessed, in whole or in part, were inspected to determine that
approved procedures were available, test equipment was calibrated,
prerequisites were met, tests were conducted according to procedure,
test results were acceptable and systems restoration was completed.
Surveillances reviewed and witnessed in whole or in part:
IP/2/A/305/1K
RPS Ch. 'C' RC Flow Inst. Calibration
IP/0/A/375/01B ASW System Steam Generator Level
Indication (SSF)
TT/2/A/375/01B Motor Driven Emergency Feedwater Pump Head
Curve Verification Test
PT/2/A/0610/01J EPSL Emergency Switchgear Actuation Keowee
Emergency Start Test
PT/2/A/0610/01H EPSL Standby Breaker Closure Channel A,B
b. Motor Driven Emergency Feedwater Pump Testing
On May 22,
1989 a performance test was conducted on the 2A and 2B
Motor Driven Emergency Feedwater Pumps
(MDEFWP)
in accordance with
Performance Test (PT)
2/A/0600/22,
Motor Driven Feedwater
Pump
Suction Check Valve Test, dated January 26,
1988.
The purpose of
this test was to demonstrate the ability of the MDEFWP to take a
suction from the hotwell,
to check several valves to verify full
10
cycling capability and collect head curve data for Design Engineering
(DE)
under full flow conditions. The data obtained by this test
indicated the 2A pump was marginally acceptable and that the 2B pump
was unacceptable. Further testing was performed following calibra
tion checks and installing test instrumentation. The results again
indicated that the 2B pump was unsatisfactory and the pump had
degraded even further than the earlier test. Calibration checks of
all instrumentation, disassembly and inspection of the pump, removal
and inspection of various in line valves, and boroscope inspection of
the suction and discharge piping to the pump was performed and no
deficiencies were identified. Since the outage had progressed to the
point of removing portions of the original flowpath, the licensee
developed an alternate flowpath by removal of the internals of two
check valves. A special test procedure was developed to rerun the
test using high accuracy test equipment in parallel with the
installed instruments. This test was performed on both MDEFWP's. The
data indicated that although some deterioration was identified as
expected, the pumps met all requirements necessary to perform their
safety related function. As a result, DE will provide new acceptance
criteria for testing by the performance personnel.
The DE and
performance personnel met with the inspectors to discuss in detail
the problems encountered and the resolutions of these issues.
Although the investigation of this occurrence is still in progress,
the preliminary analysis indicates that the original data taken was
obtained with a faulty instrumentation block valve associated with
the flow instrument.
The inspectors will continue to follow the
licensee's efforts associated with this problem.
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:
WR 524381 Repair Leaking Inboard Seal on 2B MDEFWP
WR 54139G Replace Disc in 2MS161
WR 92926C 2B MDEFWP Investigate Low Discharge Header
WR 57270C Breaker Testing Per PT/0/A/4980/52A
WR 57271C Breaker Testing Per PT/0/A/4980/52A
WR 57273C Breaker Testing Per PT/0/A/4980/52A
WR 577858 Perform Test on CT2 Relays
WR 50297F Stem Replacement on Valve 2C-158
S
11
Various other outage related work.
No violations or deviations were identified
5. Safeguards and Radiological Controls Activities (71707)
In the course of the monthly activities, the 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. The
inspectors observed protected area lighting, protected and vital areas
and verified interfaces between
the security
organization and other organizations.
No violations or deviations were identified.
6. Unit 2 End of Cycle 10 Refueling Outage
Unit 2 performed a normal reduction in power and took the generator off
line at about 2:00 a.m. on May 20.
Cooldown was continued to establish
plant conditions for the beginning of the overhaul.
Higher than expected
contamination levels were encountered in the reactor building due
primarily to several minor leaks on instrument lines and control rod drive
mechanism flanges.
Major work items to be performed during this outage
are overhaul of two low pressure turbines,
approximately 50% of the tubes in each steam generator, rebuild two
reactor coolant pump seals, and refurbish the condenser cooling water
inlet piping.
At this time there has been no significant problems
identified and the outage is proceeding as scheduled.
The outage is
scheduled to complete and the unit returned to service on July 2. At
present the person-rem expended has been less the projected.
7. TI 2515/101 Loss of Decay Heat Removal (GL88-17) (71707)
The inspectors reviewed the licensee's implementation of Generic Letter
(GL) 88-17 expeditious actions in accordance with the submitted response.
The inspectors focused on verification that the licensee is complying with
its submitted response and did not evaluate whether or not the response
meets all the requirements of the GL since a NRC audit will do this in the
future.
The first item committed to in the response concerned training.
The
response states that a training package will be developed on the Diablo
Canyon event. All appropriate personnel,
including shift operators and
supervisors, licensed staff and Operations Section Heads will be trained
on the event. The training will include the Diablo Canyon event, related
events and lessons learned.
Operations Training Package 89-01 was a
12
one-time administered discussion of Oconee's response to GL 88-17.
It
included a detailed review of each of the six expeditious actions
applicable to Oconee.
Additionally it
reviewed all procedural
and
administrative changes implemented as response to GL 88-17.
The package
also contained graphs depicting loss of decay heat removal consequences
specific to Oconee. Graphs of time to boiling, time to core uncovering,
and time to core damage for various RCS inventories and different elapsed
times after shutdown were included. The inspectors had observed some of
this training being administered to on-shift personnel prior to draindown
of Unit 1 during its last outage in early 1989. The training package has
been reviewed by all on shift licensed operators and supervisors, licensed
operations staff personnel and many individuals training to be licensed.
Although these personnel do comprise the final level of control over plant
evolutions and maintenance that could affect decay heat removal operation,
there are other appropriate personnel which should be trained on this
issue.
For instance, section heads and supervising engineers in the
fields of performance testing and NSM implementation should be aware of
their possible impact on decay heat removal system operation.
While
operations personnel have the overall responsibility of coordination and
implementation of work in regards to decay heat removal capability, it
seems that knowledge of the potential problems and consequences within
other work groups could also be valuable. The inspectors also noted that
while the commitment stated that the training will include the Diablo
Canyon event (the requirement specifically stated this also), that event
in itself was not discussed in the training package. The inspectors also
reviewed the requalification program training lesson plans on the Low
Pressure Injection System and Draining and Filling of the RCS.
These
lesson plans, while thorough and detailed concerning loss of decay heat
removal and drained down issues, did not specifically address the Diablo
Canyon event (several other events including problems at ANO2,
Trojan,
Zion and McGuire were briefly discussed along with INPO SOER 85-04
conclusions).
The second of the six applicable expeditious action items addressed
implementation of procedures and controls to ensure containment closure
will be achieved prior to the time at which a core uncovering could result
from an extended loss of DHR. These actions are required (for B&W units)
just prior to draining RCS to a level lower than four inches below the top
of the hot leg flow area (or else do not drain to this level or keep the
containment closed).
This corresponds to about 14 inches on LT-5
(Oconee's Reactor Vessel (RV) level instrument). The licensee has revised
OP/1,2,3/A/1103/11; Draining and Nitrogen Purging of Reactor Coolant
System to provide the administrative controls and guidance committed to in
the response.
Enclosure 4.7 of this procedure is entitled:
Requirements
for Reducing Reactor Vessel Level Less Than 50 Inches on LT-5
(50 inches
on LT-5 corresponds to about 34 inches below the RV lip, 32 inches above
the top of the hot leg flow area.)
This enclosure requires that
containment closure ability be established prior to draining to less than
50 inches on LT-5. This is accomplished by ensuring that the necessary
containment isolation valves outside the Reactor Building (RB) are intact
13
(Enclosures of AP/1,2,3/A/1700/07 "Loss of LPI"
System lists these
components) or equivalently isolated in accordance with a Removal and
Restoration (R&R) procedure. This is called a Containment Closure Survey.
Another enclosure of OP/1,2,3/A/1103/11 requires that the OTSG secondary
side is isolated or controlled by R&R. The Shift Engineer is responsible
for ensuring that the major work groups are aware of their roles if DHR is
lost. Mechanical Maintenance must be ready to secure all secondary side
shut the hatches and secure any temporary
openings into the RB within the 2.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> period.
Instrument and
Electrical are responsible for all instrument penetrations and Performance
controls electrical and Leak Rate Testing penetrations. If a loss of DHR
were to occur with the RCS open and containment integrity not existing,
containment closure would be established.
Operators would complete
enclosures of AP/1,2,3/A/1700/07, (shutting outside RB isolation Valves,
primarily in the penetration rooms) while the above groups would complete
their assigned tasks,
other actions of AP/1,2,3/A/1700/07 would be
completed. Based on observation of most of these tasks, it appears that
containment isolation could be achieved within the 2.5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> limit. During
the current Unit 2 outage the inspectors observed closely the implementa
tion of these requirements.
No significant deficiencies were noted.
Successful completion of these procedures does require close and extremely
detailed coordination, particularly on the part of Operations Staff
personnel.
At daily outage meetings, draindown to less than 50 inches and
the required precautions were discussed between the work groups.
The
outage coordinators made all reasonable efforts to ensure that draindown
conditions (LT-5 less than 50 inches) were limited as much as possible.
Due to a problem with the OTSG nozzle drains (cold legs) the RCS had to be
drained down less than 50 inches an additional time.
Since it had been
only about 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> since the last drained down period, the OTSG secondary
side checklist was not completed again.
Two valves (feedwater drain
valves) had been manipulated in the interim and were not properly
positioned but OTSG secondary side level was sufficiently high enough such
that a flow path from the-RB out to the steam line did not exist.
The review of the remaining four applicable expeditious actions
temperature indications, level indications, limiting operations during
draindown,
and two other means of adding inventory will be completed
during the next inspection period.
8. Inspection of Open Items (92702)
The following open item is being closed based on review of licensee
reports,
inspection,
record review,
and discussions with licensee
personnel, as appropriate:
(Closed) Violation 269/89-08-02:
Performance of Testing Without The
Use of An Approved Test Procedure.
The licensee responded to this
violation in correspondence dated May 4, 1989. The corrective action
has been completed and reviewed by the inspector.
Based on this
review, this item is closed.
14
9. Exit Interview (30703)
The inspection scope and findings were summarized on June 19, 1989,
with those persons indicated in paragraph 1 above.
The inspectors
described the areas inspected and discussed in detail the inspection
findings listed below. The licensee did not identify as proprietary any
of the material provided to or reviewed by the inspectors during this
inspection. Dissenting comments were not received from the licensee.
Item Number
Description/Reference Paragraph
a. VIO 269,270,287/89-17-01
Electrical
Distribution System TS
Violations
Due
To
Inadequate
Procedures, paragraph 2
b. NCV 269,270,287/89-17-02
Failure to perform appropriate testing
as required by TS 4.8.2, paragraph 2.e
c. IFI 269,270,287/89-17-03
Adequacy of Fire Protection Sprinkler
System Pressure, paragraph 2.b.
Licensee management was informed that one previous violation discussed in
paragraph 8 was closed during this inspection.
ENCLOSURE 3
OCONEE NUCLEAR STATION
COMMISSIONER CURTISS VISIT
JUNE 5, 1989
PLANT BRIEFING
-
ORGANIZATION
-
MAJOR PLANT DESIGN FEATURES
-
SELECTED PLANT STATISTICS
-
AREAS OF INCREASED EMPHASIS
-
SELF EVALUATION EFFORTS
-
MAINTENANCE
OCONEE NUCLEAR STATION
ORGANIZATION
ORGANIZATIONAL CHART
DO IT OURSELVES
- MINIMAL VENDORS
ADEQUATE RESOURCES -
ONSITE AND OFFSITE
LOW TURNOVER -
HIGH EXPERIENCE
NON UNION STATUS
SHIFT RESOURCES - 12 HOUR SCHEDULE
TRAINING COMMITMENT
USE OF ENGINEERS/TECHNICAL STAFF
DUKE POWER COMPANY
CHAIRMAN OF Tas BOARD
D. W. BOOTH
PRESIDENT
W. H. RL.D
T'rECUTIVE VICE PRESIDENT
POWER GROUP
R. L. DICK
G. W. (MIER
E. S.
TUCKER.
R. B. PR- ORY
Vice President
Manager
Vice President
Sr. Vice President
Const. & Maint.
Corporate Q.A.
Nuclear Production
J. B. GROGAN
T. MOUKEKIN
J. C. L5A
S
General Manager
Vice President
Vice President
Const. & Maint.
Design
Prod. Support
SITE
DP.
R. M.FKOERB
an Dsign
Gen. Manager
SSIE
(309)
Training
D. L. FREZE
R. J. BRAKETT
N. S. TUCKNAN
C. V. BD
T. S' BARR
Superintendent
ue.ItnetSprnednSueitnetSeiteet
MaintenanceSer
Tatio Merager
Sta
tion
vcs.
(59)
(170)
(235Stff
(79)
(50)
+
(2000
CoContrcctors
I
I
I
V. V FOkX.
L. SGR
JM.
VI
0 TUCKER
R B. PR
ORT
Supritenen
ueMnanagenVicerneident
Sr.ernt e Prsdentean
Maintenanceoperation Q.A
N ch.a SrducestiontdSclg
Sain
y
VicePresdent
2ic Conractoent
OCONEE NUCLEAR STATION
MAJOR PLANT DESIGN FEATURES
3 VIRTUALLY IDENTICAL UNITS
EMERGENCY POWER SOURCE
-
KEOWEE HYDRO STATION
-
FLEXIBILITY/RELIABILITY
SAFE SHUTDOWN FACILITY
EMERGENCY CONDENSER CIRCULATION WATER SYSTEM
OCONEE NUCLEAR STATION
PLANT STATISTICS
HISTORICAL CAPACITY FACTORS
UNIT 1
66.5%
UNIT 2
66.6%
UNIT 3
67.6%
RECENT CAPACITY FACTORS
1983
79.0%
1984
83.0%
1985
75.0%
1986
73.6%
1987
72.3%
1988
83.8%
SIX YEAR AVERAGE
78.3%
SIGNIFICANT RECORDS
OCONEE HAS PRODUCED MORE ELECTRICITY THAN ANY OTHER NUCLEAR PLANT IN U.S.
.
983
UNIT 3 HIGHEST U.S. CAPACITY FACTOR -----
94.7%
1984
UNIT 2 HIGHEST U.S. CAPACITY FACTOR -----
96.6%
1985
UNIT 2 SETS WORLD RECORD
-
439 CONTINUOUS DAYS
1988
BEST EVER UNIT 3 RUN
- 351 DAYS
BEST EVER UNIT 1 RUN
- 235 DAYS
UNIT 1 1988 CAPACITY FACTOR 96.78%
STATION WILL BE AMONG HIGHEST U.S. CAPACITY FACTOR FOR MULTI-UNIT
STATIONS IN 1988
HEAT RATE HISTORICALLY AMONG LOWEST IN U.S.
1983
12
1984
7
1985
10
1986
8
1987
3
1988
4
INPO EVALUATIONS -- CATEGORY 1 -- EXCELLENT PLANT LAST FOUR YEARS
NRC VIOLATIONS -- 5 PER YEAR PER UNIT ---------------
LAST 6 YEARS
- ER'S
-- 8.8 PER YEAR PER UNIT
--
LAST 6 YEARS
NDUSTRIAL SAFETY
-
3 MILLION
3 MILLION
6 MILLION
1 MILLION
OCONEE NUCLEAR STATION
RECENT EMPHASIS
- CHEMICALLY CLEANED SECONDARY-- UNITS 1 AND 2
- TUBE SLEEVING TO REDUCE PROBABILITY OF LEAKS
--
UNITS 1 AND 3
- INSTALLED COLD LEG DAMS (MINIMIZE TIME IN DRAINED CONDITION)
- DECON OF CHANNEL HEADS TO REDUCE DOSE
MOTOR OPERATED VALVES
- OVERHAUL APPROXIMATELY 100 LIMITORQUES PER REFUELING
- EXTENSIVE USE OF MOTOR OPERATED VALVE ANALYSIS TEST SYSTEM (MOVATS)
VALVE OUALITY
- EXTENSIVE PROGRAM FOR IMPROVEMENT OF' VALVE PERFORMANCE
BINGHAM REACTOR COOLANT PUMP UPGRADE
- REBUILT 8 BINGHAM REACTOR COOLANT PUMPS DUE TO FAILURE OF 1
AREA- DECONTAMINATION
- RECOVERED MANY SQ. FT. OF CONTAMINATED AREA IN AUXILIARY BUILDING
HOUSEKEEPING/MATERIAL CONDITION
-
UPGRADING PAINTING, INSULATION, HOUSEKEEPING STANDARDS
A LONG WAY TO GO
OCONEE NUCLEAR STATION
RECENT EMPHASIS
(CONTINUED)
SIMULAT.OR-TRAINING
- SIGNIFICANTLY INCREASED THE TIME FOR SIMULATOR TRAINING
SYSTEM/COMPONENT OWNERSHIP
- ENHANCING THE OWNERSHIP OF COMPONENTS/SYSTEMS BY ENGINEERS/STAFF
EXPOSURE CONTROL
- SIGNIFICANT REDUCTIONS IN TOTAL EXPOSURE --1988 LOWEST YEAR IN 14 YEARS
OUTAGE MANAGEMENT
- UNIT 2 REFUELING IN 66 DAYS INCLUDED REBUILDING 4 REACTOR COOLANT PUMPS
- OUTAGE MANAGEMENT HAS IMPROVED-LAST 2 OUTAGES 43 DAYS AND 42 DAYS
- PRESENT OUTAGE SCHEDULED FOR 42 DAYS
-
STRONG EMPHASIS WITH 5 FULL SCALE DRILLS PER YEAR--MANY USING SIMULATOR
SELF EVALUATION EFFORTS
-
SITA AUDITS
-
-
DESIGN BASIS DOCUMENTATION
-
B&W OWNERS GROUP SPIP
BWOG RECOMMENDATIONS
Oconee Status as of 4-6-89
Evaluating
Evaluating
for
for
Closed
Closed Not
Closed
Applicability
Implementation
Implementing
Applicable
Rejected
TRfTRIP*
0
18
34
93
54
26
AVAILABILITY
0
3
4
24
0
0
ECONOMIC
0
0
0
1
0
0
REGULATORY
0
0
0
4
0
0
ALL PROGRAMS
0
21
38
122
54
26
Reference: BWOG Recommendation Tracking System
- Trip Reduction/Transient Response Improvement Program (includes safety and performance improvement program)
BWOG GOALS
GOAL - 1990
OCONEE NUCLEAR STATION
AVAILABILITY - 78%
78.16%
(1985-1987)
85.39%
(1988)
REACTOR TRIPS - 1.5/UNIT/YEAR
2.3/UNIT (1985-1987)
1.3/UNIT (1988)
CATEGORY C EVENTS - <.1/YEAR
ONE IN HISTORY (ITA FIRE EVENT)
FORCED OUTAGE RATE 4%
4.6%
(1985-1987)
(3 YEAR AVERAGE)
2.9%
(1988)
SUPERI TENDENT OF
MAINTENANCE
W. W. Foster
PHONE: 3163
-518
Clay A. Little
GROUP CLERK
Phone: 3416
T. Darlene Chapman (A)
In Training
PHONE: 3164
MECHANICAL MAINTENANCE
INSTRUMENT & ELECTRICAL
MAINTENANCE ENGINEERING
PLANNING & MATERIALS
MANAGER
MANAGER
MANAGER
MANAGER
Ronnie M. Weatherford
Don E. Havice
Barry K. Millsaps
M. Dendy Clardy
Phone: 3146
Phone: 3115
Phone: 3133
Phone: 3160
Beeper: 450
Beeper: 350
Beeper: 469
-Craft Organization
-Craft Organization
-Engineering & Technical Support
-Planning/Scheduling
-220
-130
-45
-Materials
-110
05/31/89
FUNCTIONAL ARRANGEMENT
ENGINEERIN!G
-
ONE ENGINEERING MANAGER IN MAINTENANCE
-
MECHANICAL - BY COMPONENTS
-
ELECTRICAL/I&C - BY SYSTEM
-
CLOSE TIE BETWEEN TECH SUPPORT/CRAFT/PLANNERS
PLANNING
-
ORGANIZED BY COMPONENT OR SYSTEM
-
PLANS AND SCHEDULES ALL MAINTENANCE WORK
-
INCLUDES MATERIALS AND DATABASES
EXECUTION
-
STAFFED TO SUPPORT ALL NON-OUTAGE WORK
REFUELING OUTAGES
-
MOST WORKFORCE FROM DUKE RESOURCES
- NPD
- CMD (350)
- TRANSMISSION (30)
- QA/QC
-
LIMITED VENDORS
- I&E (25)
-MACHINISTS (10)
-INSULATORS
(15)
-VALVE (10-30)
- B&W (25-50)
-
ALL WORK PLANNED, SCHEDULED AND MANAGED BY
ONS ORGANIZATION
TRAINING AND QUALIFICATION
-
NPD INPO ACCREDITED MAINTENANCE PROGRAM
-
PSD ORGANIZATION ONSITE FOR TRAINING
-
CORPORATE TRAINING PROGRAMS
- BASIC
- SPECIALIZED
- ALIGNMENT AND COUPLING
- RIGGING
-
CMD / TRANSMISSION
-
SPECIALIZED TRAINING PROGRAMS
-
ALL TRAINING CONSISTENT ACROSS COMPANY
MAINTENANCE RESULTS
-
HIGH CAPACITY FACTORS
-
SHORT OUTAGE LENGTHS
-
SHORT AND FEW FORCED OUTAGES
-
RADIATION EXPOSURE DECREASING
-
CONTAINMENT PERFORMANCE IMPROVING
-
IMPROVED PLANT MATERIAL CONDITION
-
RECLAMATION OF CONTAMINATED AREAS
-
SMALL BACKLOG <250 >90 DAYS OLD
-
PM/CM APPROXIMATELY 70%
-
FEW PM DEFERRALS
-
FEW PRIORITY 1 WORK REQUESTS <10/MONTH
RECENT ISSUES
-
MAINTENANCE TEAM INSPECTION
-
QUALITY VERIFICATION TEAM
ENVIRONMENTAL QUALIFICATION TEAM
-
-
INPO EVALUATION
PICLOSUJPE 4
INorth
Greenvills, )- (Control)
(Contral)
South
Asbury
Trp
Docus
Oconee
Calhoun
Mountain Newport Wotrcross
Tr.a2
Trams
to
/.*
-23'*V 525OKu
No.2
No. IR
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16
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