ML16154A801
| ML16154A801 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/21/1995 |
| From: | Crlenjak R, Harmon P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A799 | List: |
| References | |
| 50-269-95-09, 50-269-95-9, 50-270-95-09, 50-270-95-9, 50-287-95-09, 50-287-95-9, NUDOCS 9507120082 | |
| Download: ML16154A801 (22) | |
See also: IR 05000269/1995009
Text
REGU
lUNITED
STATES
NUCLEAR REGULATORY COMMISSION
REGION II
J 0101
MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.: 50-269/95-09, 50-270/95-09 and 50-287/95-09
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC
28242-0001
Docket Nos.:
50-269, 50-270 and 50-287
License Nos.:
Facility Name: Oconee Units 1, 2 and 3
Inspection Conducted: April 30 - May 27, 1995
Inspectors:
_
_
_
_
_
_
__
_
_
'4>z /
P. E. Harmon, Senior Re;Ydent Inspector
Date Signed
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. G. Hum hrey, Resident Inspector
C. W. p
Reactor Inspector
Approved by:
// f
/
R. .
rlenj a(,' Cief
Dte igned
Reactor Projects Branch
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
onsite engineering and technical assistance, plant support,
inspection of open items, and review of licensee event reports.
Inspections were performed during normal and backshift hours and
on weekends.
Results:
An Inspector Followup Item was identified in Plant Operations
regarding the inability to consistently activate the Standby
Shutdown Facility (SSF) within the time criteria, paragraph 2.f.
The licensee's efforts in cleaning the Unit 2 Main Condenser was
considered a strength, paragraph 2.d.
Within the area of Engineering, two deviations were identified.
The first deviation involved the failure to identify the solenoid
valves which operate the Main Steam Stop Valves as safety-related,
paragraph 6.b. The second deviation involved the failure to
perform a fatigue analysis for portions of reactor coolant system
auxiliary piping, paragraph 6.f.
ENCLOSURE 2
9507120082 950621
ADOCK 05000269
G
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- B. Peele, Station Manager
- E. Burchfield, Regulatory Compliance Manager
- D. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
T. Coutu, Operations Support Manager
- W. Foster, Safety Assurance Manager
- J. Hampton, Vice President, Oconee Site
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Manager
J. Smith, Regulatory Compliance
- G. Rothenberger, Operations Superintendent
R. Sweigart, Work Control Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
- Attended exit interview.
2. Plant Operations (71707)
a.
General
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, temporary modification
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 engineering personnel..
Activities within the control rooms were monitored on an almost
daily basis.
Inspections were conducted on day and night shifts,
during weekdays and on weekends. Inspectors attended some shift
changes to evaluate shift turnover performance. 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. During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation control
practices were observed.
2
b.
Plant Status
Unit 1 commenced the reporting period in cold shutdown for a
control rod drive mechanism refurbishment outage. The unit was
placed back in service on May 9, 1995, and continued to operate at
full power for the remainder of the reporting period.
Unit 2 operated near full power until May 4, 1995, when the unit
was shut down for extraction steam bellows replacement inside the
main condenser. The work was completed and the unit returned to
power on May 23, 1995.
Unit 3 operated at full power throughout the inspection period.
On May 24, 1995, the unit experienced a dropped control rod which
required a power reduction to approximately 50 percent. The unit
returned to full power the next day.
c.
Unit 1 Outage
Unit 1 shutdown on April 27, 1995, to perform control rod drop
time testing (Inspection Report 269,270,287/95-06).
As a result
of the testing, the licensee identified 5 control rods with drop
times greater than the Technical Specification (TS) limit of 1.66
seconds and commenced a cooldown to cold shutdown for a control
rod drive mechanism (CRDM) refurbishment outage. During the
outage the reactor vessel level was maintained between 80 inches
and 100 inches on the reactor vessel level indicator (LT-5).
The
licensee refurbished 9 CRDMs during the outage. These included
the 5 CRDMs that exceeded the TS limit of 1.66 seconds and 4 CRDMs
that exceeded 1.5 seconds. The refurbishment consisted of
replacing the CRDM thermal barriers with modified thermal
barriers. The slow rod drop times were the result of stuck ball
check valves. Modified thermal barriers have larger clearances in
the ball check area. The sticking ball check valves are a
previously identified problem which gets progressively worse.
Accordingly, the licensee has implemented a program to refurbish
CRDMs with drop times greater than 1.4 seconds during refueling
outages.
The licensee determined that the total rod worth and rod worth
versus time were within the Final Safety Analysis Report (FSAR)
assumptions assuming the slow rod drop times. The licensee plans
to submit a Licensee Event Report in accordance with 1OCFR50.73.
The CRDM refurbishment activity was completed on May 8, 1995, and
Unit 1 was returned to service on May 9, 1995. The inspectors
followed the outage activities and monitored plant conditions on a
routine basis. All activities observed were satisfactory.
Ill3
d.
Unit 2 Outage
Ruptured extraction steam piping bellows inside the main condenser
resulted in the shutdown of Unit 2 for approximately 19 days for
repairs. The problem was originally thought to be a ruptured "E"
bleed expansion bellows in the "A" water box. However, after the
unit was shut down and an inspection performed on all three of the
water boxes, the damage was found to be more extensive. As a
result, the expansion bellows were replaced on all of the
extraction lines (24) inside the condenser (A, B, and C Water
Boxes) and 2 bellows were replaced outside the condenser. After
the bellows replacement, a high pressure washdown and cleanup of
the condenser was performed and the Auxiliary Feedwater piping
that takes suction from the bottom of the condenser hotwell was
flushed. This was followed by a walkdown and closeout of the
condenser on May 19, 1995.
The licensee expanded their Foreign Material Exclusion (FME)
program to include the condenser and associated equipment. A
detailed procedure, Unit 2 Condenser Hotwell Cleaning Plan, was
prepared which included a step-by-step activity and documentation
for the completion and cleanup. It further included a final
inspection and approval of the completed effort by the following
organizations: Maintenance, Quality Assurance, Operations,
Chemistry, and a signoff by the project leader. The inspectors
performed an inspection of the condenser on May 18 and 19, 1995,
and determined the equipment to have been thoroughly cleaned. The
inspectors concluded that the licensee's inclusion of the Unit 2
Main Condenser in their FME program, and their thorough cleaning
efforts, was a strength.
e.
Unit 3 Dropped Control Rod
On May 24, 1995, Unit 3 experienced a dropped control rod from
full power. During the performance of the monthly control rod
movement performance test (PT/3/A/600/15), rod 2 group 1 was being
exercised to investigate a pre-existing problem with this rod's
100 percent withdrawn limit light. After the rod was placed on
its auxiliary power supply, the operators were attempting to pull
it to its 100 percent position when the rod dropped into the core.
The Integrated Control System (ICS) was in manual for this
evolution. If the ICS had been in automatic when the rod dropped,
there would have been an automatic runback to 55 percent power at
5 percent per minute. Since ICS was in manual, the automatic
runback could not take place. The operators entered AP/3/A/600/15
(Dropped Control Rods) and Reactor Power was manually reduced to
less than 60 percent per the procedure. The licensee attempted to
discover the cause of the dropped rod, but was not successful.
The rod was subsequently pulled back to within its group average
and then the complete group was withdrawn to 100 percent. The
licensee then completed the control rod movement performance test
and slowly returned to full power. The inspectors responded to
4
the control room following the dropped rod and observed the
recovery efforts. All activities observed were satisfactory.
f.
Standby Shutdown Facility (SSF) Activation Time
During the inspection period the inspectors observed drills
conducted by the licensee designed to verify that operators could
man and activate the SSF facility within the time assumed in
associated analysis.
The SSF is designed as a standby system for use under extreme
emergency conditions. The SSF is provided as an alternate means
to achieve and maintain hot shutdown conditions for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
on all three units, following postulated fire, sabotage, or
flooding events.
Loss of all other station power is assumed for
each event. The licensee has taken credit for the SSF to meet the
requirements of 10 CFR 50, Appendix R, and the Station Blackout
Rule (1OCFR50.63).
The SSF is designed in part to: (1) maintain
a minimum water level above the reactor core, with an intact
Reactor Coolant System (RCS); (2) maintain reactor coolant pump
seal cooling; and (3) assure natural circulation and core cooling
by maintaining sufficient secondary side cooling water. RCS
inventory and seal cooling is provided by the SSF Reactor Coolant
Makeup (RCMU) pumps (one per unit).
Core cooling is provided by
the SSF Auxiliary Service Water (ASW) pump which supplies lake
water to the steam generators of the affected unit(s).
Power for
these pumps is provided by the SSF diesel generator. The Oconee
Probability Risk Assessment (PRA) results indicate that the
probability of an SSF event is about 3.0 E-04 per year.
The SSF is normally unmanned and requires manual activation by
operations personnel.
SSF activation includes starting the diesel
generator, SSF ASW pump, RCMU pump(s), and manipulating various
breakers and valves to establish flow paths. The SSF must be
activated within a certain time in order to prevent Reactor
Coolant Pump (RCP) seal damage/failure, or voiding in the RCS such
that natural circulation is lost. RCP seal failure creates a Loss
Of Coolant Accident (LOCA), an accident the SSF is not designed to
mitigate. Therefore, as part of the SSF Emergency Operating
Procedure (AP/O/A/1700/25), SSF makeup flow to the RCP seals and
ASW flow to the steam generators are required to be established
within 10 minutes.
On July 27, 1994, the licensee performed a drill that was written
with the intent of showing how plant personnel and equipment were
prepared to cope with mitigation of an Appendix "R" type event.
The drill scenario included a requirement to activate the SSF.
The SSF activation time for this drill was approximately 28
minutes. During this drill, it took approximately 8 minutes for
the personnel to acknowledge the need to activate the SSF and 20
additional minutes before the SSF was in service.
5
Subsequent to this drill, the inspectors noted that previous
activation times were non-conservative due to the failure to
include the time required for valve stroking (valves were not
actually stroked during the drills, rather the valves were assumed
to go instantly open or closed).
Due to the lack of
documentation, it was impossible to determine if factoring in the
valve stroke times into the previous tests would have resulted in
test failures. The licensee agreed that valve stroke times should
be included in any future drill/test used to verify the SSF could
be placed into operation within 10 minutes. The licensee
concluded that valve stroke times would add 56 seconds to the Unit
1 activation time, 75 seconds to Unit 2, and 58 seconds to Unit 3
(NRC Inspection Report 50-269,270,287/94-38).
On December 7, 1994, the inspectors observed a special drill which
was conducted to verify that the SSF could be placed in service
within 10 minutes with valve stroke times included. The results
of the drill were as follows:
Unit 1-9:46, Unit 2-10:48, Unit 3
10:00 (times in minutes:seconds).
A conference call was held between the licensee, Region II, and
NRR to discuss the drill failures. During the call the licensee
maintained that the recent drill failures indicated the need for
additional operator training and procedural enhancements, but did
not indicate that the SSF was inoperable. The licensee
subsequently conducted additional operator training and revised
the SSF activation procedure. The licensee then performed another
3 unit drill scenario on December 20, 1994, similar to the one
conducted on December 7, 1994. The results of the drill were as
follows:
Unit 1-6:17, Unit 2-6:05, Unit 3-6:18.
The licensee indicated that they would continue to perform
periodic drills in order to test all shift personnel. Based on
the December 20, 1994, drill, the inspectors concluded that the
licensee's training and procedures had improved sufficiently to
provide reasonable assurance that the SSF could be manned within
10 minutes.
On May 24, 1995, the inspectors observed the first drill conducted
since the December 20, 1994, drill.
This was a single unit drill
utilizing operating shift personnel.
The drill was unsuccessful
in that the activation times were in excess of 10 minutes (10
minutes 18 seconds for RCMU, 11 minutes 4 seconds for ASW).
The
primary problem noted in this drill was the amount of time
required by the breaker operator to complete the required breaker
manipulations and notify the SSF control room operator. The
licensee initiated Problem Investigation Process (PIP) report
95-0596 to disposition the drill failure. As of the end of the
inspection period this evaluation was not complete. On May 25,
1995, a follow-up drill was performed successfully. The
inspectors continue to be concerned with the licensee's inability
to consistently meet the SSF activation time requirements.
II
6
The inspectors concluded that it is physically possible to
man the SSF within 10 minutes, but there is very little margin
for error. The inspectors will continue to follow the licensee's
efforts to ensure that training for SSF activation is adequate.
This matter is identified as Inspector Followup Item (IFI)
50-269,270,287/95-09-01: SSF Activation Time.
Within the areas reviewed, an IFI was identified regarding the
licensee's inability to consistently meet the SSF activation time
criteria, paragraph 2.f. The licensee's efforts in cleaning the Unit 2
Main Condenser was considered a strength, paragraph 2.d. All other
activities observed were satisfactory.
3.
Maintenance and Surveillance Testing (62703 and 61726)
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 adequately described work
that was not within the skill of the craft. Activities,
procedures and work orders (WO) were examined to verify that
proper authorization and clearance to begin work was given,
cleanliness was maintained, contamination exposure was controlled,
equipment was properly returned to service, and limiting
conditions for operation were met.
Maintenance activities observed or reviewed in whole or in part
are as follows:
(1) Perform Lubrication PM U2 TDEFWP (Annual), WO 95015174
The inspectors observed lubrication of the Unit 2 Turbine
Driven Emergency Feedwater Pump (TDEFWP) on May 17, 1995.
The activity was performed per maintenance procedure,
MP/0/A/1840/040, Pumps - Miscellaneous Components
Lubrication. Documentation was complete and work was
performed according to the procedure. The work was in
accordance with acceptable standards.
(2) Inspect/Clean 2FDW-FE-2B 'B' Venturi Flowmeter, WO 95034150,
Task 01
The inspector observed maintenance activities during the
removal and cleaning of the Unit 2, 'B' feedwater venturi.
The effort was in response to a high pressure differential
observed across the 2B Feedwater Control Valve during plant
operation. The problem was suspected to be a buildup of
magnetite in the feedwater nozzles in the steam generators.
Craftsmen were utilizing procedures, and documentation was
current for the work in progress. Torquing Procedure,
MP/0/A/1800/003, was included in the work package for re-
7
assembly of the equipment. The activity was performed to
acceptable standards.
(3) Power Range NI Calibration, WO 95033961
The inspectors observed Unit 2 nuclear instrumentation
calibration on May 23, 1995, during power ascension. The
activity was per IP/0/0301/003T, Reactor Protective System
Power Range Calibration At Power Instrument Procedure.
The
equipment was removed and returned to service in accordance
with instrument procedure IP/0/A/0305/015, Nuclear
Instrumentation RPS 'Removal From And Return To Service For
Channels A,B,C, and D. The effort was performed according
Ito the procedures and to acceptable standards.
(4) Motor Driven Emergency Feedwater (MDEFW) Pump Instrument
Calibration, WO 95031394
The inspectors observed portions of the calibration of the
low pressure service water flow instrument associated with
the 2A MDEFW Pump. The work activity was accomplished in
accordance with approved procedures. No deficiencies were
noted.
(5) Installation of Portable Reactor Building Chilled Water
System from the "B" Reactor Building Cooling Unit (RBCU) Low
Pressure Service Water (LPSW) Header, WO 95003828, Task 04
The installation of this portable chilled water system
allows for accelerated cooldown of the containment building
during unit shutdown, in order to allow work to begin inside
the containment building as soon as possible.
The work was
accomplished in accordance with MP/0/A/3007/050:
Installation, Operation, And Removal - Temporary Cooling Of
Reactor Building. The inspector reviewed the licensee's
10CFR50.59 evaluation associated with this task and
concluded that it was adequate. The inspector verified that
the installation of the temporary piping did not compromise
penetration room integrity. The licensee stated that the
chilled water would not be valved in until after the reactor
was subcritical.
The inspector concluded that the work was
done in accordance with approved procedures and did not
adversely affect plant safety.
b.
The inspectors observed surveillance activities to ensure they
were conducted with approved procedures and in accordance with
site directives. The inspectors reviewed surveillance
performance, as well as system alignments and restorations. The
inspectors assessed the licensee's disposition of any
discrepancies which were identified during the surveillance.
- II8
Surveillance activities observed or reviewed in whole or in part
are as follows:
(1) Control Rod Drive Trip Time Testing, PT/O/A/0300/01
The inspector observed Unit 2 Control Rod Drive Mechanism
(CRDM) trip time testing on May 22, 1995. The test was
conducted per the procedure and all rod drop times were
within acceptable limits. TS requires that CRDMs fall into
the reactor core at a time not to exceed 1.66 seconds with
the reactor at full flow conditions.
Twelve CRDMs were modified during the reporting period while
Unit 2 was in an outage. Nine additional CRDMs were
modified during the last refueling outage, which brings the
total of Unit 2 modified CRDMs to 21.
The modification was
necessary to eliminate excessive drop times and consisted of
replacing of the thermal barrier with one which has larger
clearances at the ball check. The larger clearances prevent
ball valve sticking, thus allowing the rods to fall into the
reactor core at a faster speed. All activities observed
were satisfactory.
(2) Low Pressure Injection Pump Test - Decay Heat,
PT/2/A/0203/06B
On April 10, 1995, the inspector observed testing and
reviewed the completed documentation of PT/2/A/0203/06B, Low
Pressure Injection Pump Test - Decay Heat .
The test was
performed on the 2B LPI pump while the reactor was at cold
shutdown as required by the procedure. The test was to
demonstrate operability of the pump, identify problem areas
as early as possible, stroke test the discharge check
valves, and perform a partial stroke of the A and B reactor
vessel LPI header check valves. Test results were
determined to be acceptable and the testing activity was
adequate.
(3) Control Rod Drive Trip Time Testing, PT/0/A/0300/01
The inspector observed portions of the Unit 1 CRDM testing
performed on May 9, 1995, following an outage to replace 9
CRDMs due to slow drop times. The drop times of the 9 CRDMs
that had been replaced during the outage improved
significantly, with the slowest rod drop time at 1.384
seconds. The slowest rod in the core dropped in 1.420
seconds. During performance of the test, Rod 10 Group 5 did
not record a drop time. Investigation by the licensee
determined that the position indication switch was
defective. The licensee replaced the switch and
successfully retested the rod.
9
(4) Keowee Hydro Emergency Start Test, PT/0/A/0620/16
The inspector observed the subject test on May 24, 1995.
This annual test is required by TS 4.6.2. The purposes of
this test were: (1) demonstrate operability of each Keowee
Hydro Unit's (KHU) emergency start circuitry from each
control room; (2) demonstrate each KHU will reach rated
speed and voltage within 23 seconds of emergency start
initiation; and (3) demonstrate each KHU can supply greater
than 25 MW to the system grid. The inspector reviewed the
test procedure, attended the pre-test briefing, and observed
the test from the Keowee Control Room. The inspector
concluded that all test acceptance criteria were met and
that procedural compliance was adequate.
Within the areas reviewed, licensee activities were satisfactory.
4.
Onsite Engineering (37551)
During the inspection period, the inspectors assessed the effectiveness
of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other
areas involving the Engineering Department.
a.
Unit 2 Feedwater Control Pressures
During the Unit 2 outage for condenser repairs, an investigation
of a problem with high pressure differential across the 2B
Feedwater Control Valve was performed. Main feedwater spray
nozzle N in the 2A steam generator header ring was evaluated and
the results indicated a magnetite buildup of approximately 0.070
inches in the inside diameter of the holes measured. Each steam
generator has a total of 32 Feedwater spray nozzles with 82 holes
each that were originally drilled to a diameter of 0.188 inches.
The licensee decided to restart the unit and change the feedwater
chemistry in an effort to eliminate the magnetite buildup. The
changes included: (1) raising the ammonia concentration from 400
600 ppb to 1500 ppb; (2) adding dimethylamine on a continuous
basis at <1 ppm; and (3) adding a mixture of dimethylamine and
trimethylamine on a continuous basis at <1 ppm. The effects of
the chemical addition will be evaluated by monitoring feedwater
system pressures.
Within the areas reviewed, licensee activities were satisfactory.
5.
Plant Support (71750 and 40500)
The inspectors assessed selected activities of licensee programs to
ensure conformance with facility policies and regulatory requirements.
During the inspection period, the areas of Radiological Controls,
Physical security and Fire protection were reviewed.
10
a.
Unit 3 Fire Drill
The inspectors observed a fire drill on May 16, 1995. The drill
was for a simulated fire within Unit 3 at the stator coolant pump
in the basement level of the Turbine Building. A total number of
14 fire brigade members responded to the fire. The simulated fire
involved the 600 volt pump motor and a maximum of 0.5 gallons of
After the drill was completed, the licensee evaluated the activity
with the team members. The critique considered the area selected
as a command post, personnel accountability, communications with
the main control room, type of extinguisher utilized, and the
approach taken by the team. The inspector concluded that the
drill constituted effective training, and that the licensee's
self-assessment of the drill was adequate.
b.
Equipment Located Adjacent to Unit 3 Main Transformer
The inspectors questioned the licensee's decision to park a
semi-trailer (box type) adjacent to the Unit 3 main transformers.
The trailer contained equipment necessary for transformer
re-blocking and oil purification. The spare transformer was
scheduled to be reworked and put in service when Unit 3 is taken
off-line June 6, 1995, for its refueling outage, in order to make
another transformer available for re-blocking and oil
purification. Although the transformers were not safety-related,
the inspectors were concerned that the trailer could collide with
the transformer as a result of high winds, maneuvering, or other
type of accident, and cause a loss of generator output and
subsequent unit trip.
The inspectors learned that associated risks had been evaluated by
the licensee prior to locating the trailer in that area and that
the activity was allowed per Oconee Nuclear Site Directive 1.3.7,
Conduct Of Operations In The Switchyard. The entire trailer
moving process was coordinated with the Operations staff and was
under the control of the Switchyard Coordinator. The process was
well planned and controlled.
No violations or deviations were identified.
6.
Inspection of Open Items (92901, 92902 and 92903)
The following open items were reviewed using licensee reports,
inspection record review, and discussions with licensee personnel, as
appropriate:
11
a.
(Closed) Deviation 50-269,270,287/93-31-01:
Potential Single
Failure Could Blowdown Both Steam Generators
This deviation involved a postulated break in the line downstream
of the motor operated valves from the steam supply to the
Auxiliary Steam header (MS-24 and MS-33). As the licensee
maintained both MS-24 and MS-33 open for the unit supplying
auxiliary steam, the postulated break would potentially result in
the simultaneous blowdown of a unit's steam generators. This was
contrary to statements contained in Section 10.3.2 of the FSAR
that indicated the arrangement of the isolation valves on
Auxiliary Steam lines (i.e., MS-24 and 33) prevents blowdown of
both steam generators from a single leak in the system. The focus
of Deviation 93-31-01 was the blowdown of both steam generators
through the auxiliary steam header, although the issue was also
relevant to a break downstream of MS-82 and MS-84 (TDEFWP steam
header isolation valves).
In a letter dated February 24, 1994, the licensee agreed that the
deviation existed, but maintained that the vulnerability in
question did not constitute an Unreviewed Safety Question (USQ)
because it was bounded by the FSAR Chapter 15 steam line break.
The only corrective action proposed in this response was to change
the wording in the FSAR to indicate that certain pipe breaks could
blow down both steam generators. Due to continued NRC concerns,
the licensee agreed to provide the NRC their engineering analysis
that provided the basis for concluding that there was no USQ, and
that no corrective action was necessary (other than amending the
FSAR).
The office of NRR subsequently reviewed the licensee's
analysis and determined that the postulated event involved an USQ
per 10 CFR 50.59, in that it presented the possibility for an
accident of a different type than any evaluated in the safety
analysis report.
On January 6, 1995, the licensee was provided with the results of
NRR's review. On January 9, 1995, a conference call was held
between Region II, NRR and the licensee. During the call the
licensee stated that they would conservatively consider the
vulnerability to be an USQ, pending further review. The
licensee's immediate corrective actions were to close one of the
two steam supply valves to the common steam headers (Auxiliary
Steam and Turbine Driven Emergency Feedwater supply) on all 3
units. This effectively eliminated the vulnerability in question.
In a letter dated February 8, 1995, the licensee submitted a
revised response to the deviation. In this response the licensee
indicated that this potential scenario had been identified to the
NRC in a High Energy Line Break (HELB) submittal dated April 25,
1972. The HELB submittal was reviewed and found acceptable by the
NRC, as documented in the Oconee plant licensing safety
evaluation. Based on this additional information, the NRC
concluded that this potential failure scenario did not constitute
an USQ.
12
The revised deviation response also indicated that the licensee
would perform an engineering analysis, using probabilistic risk
analysis (PRA), to determine the safest configuration of valves
MS-24, MS-33, MS-82, and MS-84 during normal operation. On April
20, 1995, the licensee determined that future steam lineups would
maintain either MS-24 or MS-33 closed, and both MS-82 and MS-84
open. The inspector reviewed the FSAR changes relative to this
issue and concluded that they effectively resolved the deviation.
b.
(Closed) Unresolved Item 50-269,270,287/93-30-02:
Main Steam Stop
Valve (MSSV) Requirements
On November 3, 1993, the Unit 1 Main Steam Stop Valves (MSSVs)
inadvertently closed due to an electrical fault.
When the fault
cleared, 2 of the 4 MSSVs did not reopen per design.
This
resulted in a severe secondary transient, which included
depressurizing the "B" Once Through Steam Generator (OTSG) to the
point where all the feedwater in the steam generator flashed to
steam, and a resultant dryout of the steam generator. The plant
was manually tripped due to low steam generator water level.
The
licensee's post trip investigation revealed that the failure of
the MSSVs to reopen was due to stuck test solenoid valves (channel
B), caused by Electro-Hydraulic Control (EHC) system fluid residue
formation internal to the solenoids. The licensee also discovered
that they were not meeting the solenoid vendor's recommendations
for cycling the solenoid valves (both channels A and B), and that
the lack of cycling resulted in the EHC fluid residue formation
which ultimately led to the test solenoid failures. The resident
staff questioned why these test solenoid valves were not safety
related since they were the backup, or channel B, actuation
devices for closing the MSSVs. The licensee subsequently stated
that the test solenoids were not required to be safety-related.
However, the master trip solenoid valves and disk dump valves
(channel "A") were definitely required to be safety-related but
had never been identified or treated as such.
The NRC subsequently determined that both the Channel "A" and "B"
solenoid valves should have been classified as safety-related.
This determination was based on the current licensing basis for
Oconee. The original licensing basis for Oconee only identified
the reactor coolant system, reactor vessel internals, reactor
building, engineered safeguards systems, and emergency electric
power sources as essential systems and components. The MSSV
solenoids would not have been classified as safety-related under
this criteria. However, evolutionary requirements, specifically
the licensee's commitments to Generic Letter 83-28, Section 2.2,
would result in these solenoid valves being classified as safety
related. Section 2.2 of the licensee's generic letter response
indicates that portions of the Main Steam System from the steam
generator to, and including, the first normally closed or
automatic isolation valve, are safety-related. Failure to
classify the MSSV solenoid valves (Channels A and B) as safety-
13
related is identified as Deviation 50-269,270,287/95-09-02:
Generic Letter 83-28 Commitment Relating to MSSV Solenoids.
c.
(Closed) Violation 50-287/93-24-01: Inadequate Post Modification
Test Program
This violation identified that an adequate post modification test
program had not been established following a modification of the
Unit 3 Load Shed Channel 1 circuitry resulting in the channel
being inoperable from March 1987 to August 1993.
The licensee corrected the specific wiring discrepancy identified.
Enhancements had been implemented to the modification and testing
program prior to this violation being issued. These enhancements
included the development of a Modification Test Plan and issuance
of Test Acceptance Criteria by design engineering. The licensee
also implemented a configuration control inspection to ensure that
the as-built configuration matched the drawings. This
configuration control inspection identified the subject wiring
discrepancy. Accordingly, this item is considered closed.
d.
(Closed) Violation 50-270/93-21-01: Inadequate Modification
Procedure
This violation identified that the Torque Switch Bypass
Modification procedure for the PORV Block Valve 2RC-4 was
inadequate in that the procedure inadvertently deleted the valve
open indication in the Standby Shutdown Facility.
The inspector determined that the licensee corrected the wiring
discrepancy and counseled the individuals involved in the original
wiring modification. The licensee also circulated the Notice of
Violation response to other individuals responsible for developing
modification packages. This item is closed.
e.
(Closed) Unresolved Item 50-269,270,287/93-30-03: Emergency
Condenser Cooling Water System Requirements
This item questioned the adequacy of isolating the Continuous
Vacuum Priming system from the Condenser Circulating Water system
intake piping. Subsequent to this item being opened, the NRC
conducted a service water inspection and the licensee deleted the
TS requirement that the Emergency Condenser Circulating Water
system be operable with respect to decay heat removal.
Accordingly, this item is considered closed.
f.
(Closed) Unresolved Item 50-269,270,287/94-08-03:
Fatigue
Analysis for RCS Auxiliary Piping
During a visit to Oconee on March 1994, members of the NRC staff
identified an apparent nonconformance with a licensing basis
requirement. Specifically, the Oconee FSAR states that the RCS
II
14
pressure boundary piping including the attachment piping to the
first isolation valve, is required to be designed to USAS B31.7,
Class I standards. However, the staff identified that the
attached piping was designed to USAS B31.7, Class II standards.
As such, the RCS attached piping did not have fatigue analysis as
required by B31.7 I. Unresolved Item 50-269,270,287/94-08-03 was
written to track this issue.
In a letter dated October 3, 1994, the licensee provided the NRC
with the conclusion that a nonconformance did not exist, and the
rationale for that conclusion. In response, NRC concluded in a
letter to the licensee dated April 27, 1995, that the
nonconformance does in fact exist, and that an evaluation should
be performed by the licensee to demonstrate compliance with the
FSAR criteria. FSAR section 3.2.2.1 contains a definition of the
Class I system under the Nuclear Power Piping Code, USAS B31.7.
The definition also contains the statement that the class includes
connection piping up to and including the first isolation valve.
The letter further requested a schedule for either performing the
analysis or additional justification for not performing the
analysis within 60 days of the date of the NRC letter.
This unresolved issue has been determined to be a Deviation from
requirements contained in the FSAR, and will be tracked as
Deviation 50-269,270,287/95-09-03:
Fatigue Analysis for RCS
Auxiliary Piping.
g.
(Closed) Inspector Followup Item 50-269,270,287/93-13-05:
Failure
of Keowee Voltage Regulator
In 1993, several intermittent failures of the Keowee voltage
regulators to switch to Automatic during routine starts occurred.
The root cause could not be identified, but appeared to be due to
an unreliable voltage regulator cam switch. Three failures
occurred on Unit 2 between September 1992 and November 1992.
Failures also occurred three times on Unit 1 between December 1992
and May 1993. The Keowee units were evaluated and considered
Conditionally Operable by Problem Identification Process (PIP)
report 0-093-0385. As a compensatory measure and a condition of
the Operability Determination accompanying the PIP, the Keowee
operator was required to manually verify the position of the cam
switches after the unit was shut down.
After the Conditional Operability was imposed, no further failures
occurred until April 20, 1995, when Unit 1 failed again. At that
time, troubleshooting found that a bad module in the synchronizer
was the root cause of the failures. The module was delivering a
continuous raise pulse instead of an intermittent raise pulse to
the Keowee voltage regulator when attempting to match machine
voltage to grid voltage. This caused the machine voltage to be
driven out of the preset position before the regulator could be
switched to Automatic. The synchronizer for Unit 1 had been
15
replaced with the one from Unit 2 in December 1992. The single
bad module was responsible for the failures on both Keowee units.
These failures would have affected the Keowee unit's ability to
generate to the grid, but not their safety functions. The
Conditional Operability and compensatory measures were closed by
the licensee after the module was replaced and tested. This item
is closed.
h.
(Closed) Escalated Action 91-167:
Failure to Follow
Procedures/Inadequate Procedures
This Notice of Violation and Imposition of Civil Penalties, was
the result of violations identified during inspections which
reviewed the degradation of decay heat removal that occurred on
September 7, 1991, and the over-pressurization of the Low Pressure
Injection (LPI) System piping which occurred on September 19-20,
1991.
This escalated action combined the three apparent
violations identified in NRC Inspection Report 50-269,270,287/91
32.
The inspector reviewed the licensee's commitments as provided
in the response to the above Escalated Action. These commitments
were: (1) provide guidance for changing operating trains while in
decay heat removal and adjusting low pressure service water flows;
(2) increase surveillance frequency of critical parameters during
shutdown operations; (3) reduce the cold shutdown temperature
alarm setpoint to provide for earlier indication of inadequate
decay heat removal; (4) increase control room personnel control
over remote testing of valves in a system that had not been
removed from service; (5) provide supplemental training to
licensed operators on the operating procedures used for shutdown,
startup, and cold shutdown; (6) improve management of control room
workload; (7) identify a single individual as having
responsibility for monitoring critical core parameters;
(8) increase Unit Supervisor oversite of control room activities
that may impact operator performance; (9)
delineate proper chain
of command and communications channels; (10) communicate
management expectations of supervisor and operator
responsibilities; and (11) conduct of pre-job briefings before
performing evolutions that significantly affect plant
configuration.
Based on a review of current plant procedures and other
documentation available at the time of inspection, the inspector
found the licensee had met these commitments. This item is
closed.
Two deviations from commitments were identified. The first deviation
involved the safety-related classification of the solenoid valves used
to actuate the Main Steam Stop Valves (paragraph 6.b). The second
deviation involved the failure to perform a fatigue analysis for certain
portions of RCS auxiliary piping (paragraph 6.f).
16
7.
Review of Licensee Event Reports (92700)
The below listed Licensee Event Reports (LER) were reviewed to determine
if the information provided met NRC requirements. The determination
included:
adequacy of description, compliance with Technical
Specification and regulatory requirements, corrective actions taken,
existence of potential generic problems, reporting requirements
satisfied, and the relative safety significance of each event. The
following LERs were reviewed:
a.
(Closed) LER 270/93-03:
Design Deficiency Results in Technical
Inoperability of the Reactor Coolant Makeup (RCMU) System
The inoperability was due to the RCMU system letdown line orifices
being too small to pass adequate flow during certain Standby
Shutdown Facility (SSF) accident scenarios. With full letdown
flow there would be an increase in Reactor Coolant System (RCS)
volume. Assuming no operator action, no RCS leakage, and little
or no designed leakage through the Reactor Coolant Pump (RCP)
seals, the potential existed to overfill the pressurizer in an SSF
event. Licensee analysis indicated that it would take
approximately nine hours for this scenario to occur. This
vulnerability existed since initial SSF operation and was the
result of a design oversight. The licensee initially compensated
for the vulnerability by adding steps to the SSF Emergency
operating procedure. These changes included the use of the
reactor vessel head vent valves to control pressurizer level
during an SSF event. The TS LCO was exited after these procedure
changes were made. Subsequently, the licensee has eliminated the
vulnerability on Units 1 & 2 by replacing their RCMU letdown
orifices with the appropriately sized orifices. The Unit 3 RCMU
letdown orifice is scheduled to be replaced during the upcoming
refueling outage (3EOC15). The inspector considered the
determination that the RCMU systems were technically past
inoperable to be conservative. Despite the lack of specific
procedural guidance, the inspector concluded that over a 9 hour1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />
time frame mitigating actions would have been accomplished to
prevent the pressurizer from becoming water solid (i.e.,
increasing the cooldown of the RCS in order to shrink the water
volume).
The inspector concluded that the licensee's corrective
actions were acceptable.
b.
(Closed) LER 269-93-05, Inoperable Control Rods Due To Defective
Procedure Results In Technical Specification Violation
Three control rods, 2 in Unit 1 and 1 in Unit 2, initially failed
to meet the TS required drop time during their refueling outages
in January 1993 and March 1992, but were successfully tested prior
to restart.
On April 29, 1993, Unit 2 began a refueling outage which included
rod drop time testing while at hot shutdown. One control rod
17
dropped at approximately 1.9 seconds. The TS limit is less than
or equal to 1.66 seconds. This rod had been identified during the
previous refueling outage as being slow and was repeatedly dropped
until the drop time came within TS limits. As a result of the
Unit 2 rod's performance, the Unit 1 test data was reevaluated and
two rods were declared inoperable on May 4, 1993, while Unit 1 was
at 100% power. Discretionary Enforcement was obtained to continue
operation of Unit 1 until the end of the cycle, ending April 1994.
The slow control rod on Unit 2 was replaced prior to startup.
The Root Cause of this event was determined to be a procedural
deficiency, with a contributing cause of equipment
failure/malfunction. The procedural deficiency was found to be a
change made to the Control Rod Drop Time Test Procedure
(IP/0/A/0330/003A).
Prior to that change, a rod that dropped
slower than 1.40 seconds (but within the TS requirements) was
required to be evaluated by Reactor Engineering. That evaluation
requirement was deleted, such that a rod that dropped at 1.65
seconds was deemed acceptable with no evaluation. The testing of
the slow Unit 2 rod confirmed that a rod which had dropped slower
than 1.40 seconds should be expected to become slower during the
operating cycle. Conversely, rods that dropped with times less
than 1.40 seconds would not exhibit any appreciable slowing during
the cycle. An Engineering evaluation taking this phenomena into
account should have concluded that the two slow (but within the TS
limits) rods on Unit 1 would eventually have exceeded the 1.66
second drop times at some point in the operating cycle. However,
since the criteria to perform evaluations of rods slower than 1.40
seconds had been deleted, an evaluation was not performed.
The corrective actions included removal and repair of the slow
CRDM mechanisms during the next refueling outage, and the revision
of IP/0/A/0330/033A. The inspector determined that the corrective
actions had been completed for this event.
c.
(Open) LER 269/93-06, Design Deficiency Results In A Condition
Outside The Design Basis Of Containment For A Main Steam Line
Break
On June 2, 1993, the licensee determined that the main steam line
break analysis in the FSAR had not taken into account either the
heat added to the event by RCS structural metal, or the continued
feedwater addition.
In February 1980, Inspection & Enforcement (IE) Bulletin (BU)
80-04 required review of the steam line break accident to
determine if the potential for containment overpressure existed as
a result of runout flow from the Emergency Feedwater system or
from other energy sources such as continuation of Main Feedwater
or Condensate flow. The licensee's response dated May 7, 1980,
concluded that containment overpressure would not result from the
described scenario.
18
In 1993, the licensee performed a reanalysis of the scenario and
concluded that containment pressures could reach values in excess
of 2.5 times the containment design pressure. The licensee had
not considered several energy addition sources in their original
BU 80-04 submittal. Those sources included continued addition of
feedwater to the faulted steam generator and heat added by the
passive metal structure of the Reactor Coolant System. The
licensee submitted a Supplemental Response to BU 80-04, dated
August 19, 1993, which detailed the results of the reanalysis.
The Supplemental Response committed to implement modifications to
all three Oconee units to provide automatic isolation of Main
Feedwater during a main steam line break. The implementation of
the modifications is currently scheduled to begin with the
refueling outage for Unit 3, beginning June 1995. Units 1 and 2
are scheduled for modification in October 1995, and March 1996,
respectively.
LER 269/93-06 does not address the role of continued feedwater
supply to the faulted steam generator, but instead describes the
deficiency in the original calculation as a failure to consider
the heat added by the RCS metal structure. Sensitivity studies
indicate that the continued feedwater addition is the major source
of the additional energy considered in the new calculation. The
inspector determined that LER 269/93-06 does not adequately
describe the reasons for the original calculational error or the
corrective actions planned to isolate feedwater. The licensee has
agreed to supplement LER 269/93-06 to clarify the role of
continued feedwater.
Pending implementation of the modification to provide feedwater
isolation and resolution of LER adequacy, this LER will remain
open.
d.
(Open) LER 270/93-02:
Loss of Air Testing For Accumulator Valves
Not Performed Per SOER 88-1
Air operated valves with backup accumulators, High Pressure
Injection valves HP-5 and HP-21, were evaluated as to their
ability to maintain containment isolation during a loss of
instrument air. Acceptance criteria for testing these valves was
a pressure loss of <5 pounds per square inch (psi) over a 15
minute time period for the air accumulator leakage. The test
method and acceptance criteria was questioned by the system
engineer as to the ability of these valves to maintain containment
integrity over a long period of time with a loss of the control
air system.
Oconee engineering evaluated several scenarios with respect to the
effect of the accumulator leakage and determined that the system
pressure would tend to keep the HP-5 valves closed and would tend
to open the HP-21 valves. However, HP-21 was determined to be
operable on Unit 1 because of a relief valve in the system that
19
would prevent system pressure building high enough to open the
valve. Units 2 and 3 would stay closed for a minimum of 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />
with the control air accumulator pressure and after that time the
system pressure would tend to open these valves. Units 2 and 3
HP-21 valves were determined to be conditionally operable due to a
change to the Unit 2 and 3 Abnormal Operating Procedure which
requires that these valves be manually closed within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />
following a Small Break Loss Of Coolant Accident and a single
failure of the redundant isolation valve.
Replacement of Units 1, 2, and 3 High Pressure Injection valves,
HP-5 and HP-21, is scheduled to be completed by June 1, 1996.
Therefore, this LER will remain open until the replacement is
completed.
e.
(Closed) LER 270/93-05: Operator Isolated Potential Transformers
On The Wrong Unit Resulting In A Reactor Trip
This LER involved a Unit 2 reactor trip that occurred on August
25, 1993. The unit tripped from 100% power when an operator
mistakenly pulled the generator metering relay and regulating
equipment drawers to the disconnect position on Unit 2 instead of
pulling those on Unit 1.
The immediate corrective actions included controlling the unit
after the trip and closing the Unit 2 potential transformer
drawers. In addition, a telephone in the immediate area of the
equipment was repaired to improve communications between the
control room and operators taking equipment out of service in that
area. Unit designations were attached to the surge
capacitor/potential transformer cubicles for all 3 units. The
inspector verified these corrective actions had been completed.
The licensee completed additional actions which included
enhancement of Operations Procedure OP/0/A/1107/05, Backcharging
Unit Main And Auxiliary Transformers, in an attempt to lessen the
possibility of operator error and added labeling to the equipment
that matched nomenclature in the procedure. The inspector
observed this activity and determined it to be complete.
A second part of the commitment was to reinforce the use of the
Stop-Think-Act-Review (STAR) process with emphasis on ensuring the
correct unit is verified.
The remainder of the licensee's commitment was to install unit
specific locks on the unit potential drawers. This effort has
been completed on Units 1 & 2, but not on Unit 3. However, work
has been scheduled to be completed on Unit 3 during the upcoming
refueling outage.
)
20
8.
Exit Interview
The inspection scope and findings were summarized on May 31, 1995, with
those persons indicated in paragraph I above. The inspectors described
the areas inspected and discussed in detail the inspection findings
addressed in the summary and listed below. No dissenting comments were
received from the licensee. The licensee did not identify as
proprietary any of the material provided to or reviewed by the
inspectors during this inspection.
Item Number
Status
Description/Reference Paragraph
Inspector Followup Item
Open
SSF Activation lime
269,270,287/95-09-01
(paragraph 2.f)
Deviation
Closed
Potential Single Failure Could
269,270,287/93-31-01
Blowdown Both Steam
Generators (paragraph 6.a)
Unresolved Item
Closed
Main Steam Stop Valve
269,270,287/93-30-02
Requirements (paragraph 6.b)
Deviation
Open
269,270,287/95-09-02
Commitment Relating to MSSV
Solenoids (paragraph 6.b)
Violation 287/93-24-01
Closed
Inadequate Post Modification
Test
Program (paragraph 6.c)
Violation 270/93-21-01
Closed
Inadequate Modification
Procedure (paragraph 6.d)
Unresolved Item
Closed
Emergency Condenser Cooling
269,270,287/93-30-03
Water System Requirements
(paragraph 6.e)
Unresolved Item
Closed
Fatigue Analysis for RCS
269,270,287/94-08-03
Auxiliary Piping (paragraph
6. f)
Deviation
Open
Fatigue Analysis for RCS
269,270,287/95-09-03
Auxiliary Piping (paragraph
6. f)
Inspector Followup Item
Closed
Failure of Keowee Voltage
269,270,287/93-13-05
Regulator (paragraph 6.g)
Escalated Action 91-167
Closed
Failure to Follow
Procedures/Inadequate
Procedures (paragraph 6.h)
I
21
Closed
Design Deficiency Results in
Technical Inoperability of the
Reactor Coolant Makeup (RCMU)
System (paragraph 7.a)
LER 269-93-05
Closed
Inoperable Control Rods Due To
Defective Procedure Results In
Technical Specification
Violation (paragraph 7.b)
Open
Design Deficiency Results In A
Condition Outside The Design
Basis Of Containment For A
Main Steam Line Break
(paragraph 7.c)
Open
Loss of Air Testing For
Accumulator Valves Not
Performed Per SOER 88-1
(paragraph 7.d)
Closed
Operator Isolated Potential
Transformers On The Wrong Unit
Resulting In A Reactor Trip
Paragraph 7.e)