ML16154A718
| ML16154A718 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 11/23/1994 |
| From: | Harmon P, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A716 | List: |
| References | |
| 50-269-94-32, 50-270-94-32, 50-287-94-32, NUDOCS 9412060072 | |
| Download: ML16154A718 (15) | |
See also: IR 05000269/1994032
Text
V REG(
UNITED STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/94-32, 50-270/94-32 and 50-287/94-32
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: September 25 - ,October 29, 1994
Inspectors:
P. E. Har
,
enior e dent I pector
DaeSigi~d
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. G H
hr y, Resident Inspector
Approved by:
) L '4/_
C,
M. V. Sinkule, Chief,
Dat Si ned
Reactor Projects Branch 3
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, maintenance and surveillance testing, onsite
engineering, and plant support. As part of this effort, backshift
inspections were conducted.
Results:
During the inspection period one violation and one non-cited
violation were identified. The violation involved two examples of
failure to follow maintenance procedures (paragraph 3.a).
The
non-cited violation involved an inoperable containment isolation
valve due to post maintenance testng not being performed because
of a maintenance error (paragraph 2.f).
An Inspector Followup Item was identified concerning an
inadvertent venting of the Unit 2 quench tank (paragraph 2.e).
A strength was identified in the area of conduct of testing
(paragraph 3.b).
A weakness was identified in the procedure for operation of the
safe shutdown facility diesel generator (paragraph 3.b).
A weakness was-identified in the health physics program concerning
the control of radiation control zones (paragraph 5).
9412060072 941123
ENCLOSURE 2
PDR ADOCR 05000269
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
B. Dolan, Safety Assurance Manager
- W. Foster, Superintendent, Mechanical Maintenance
J. Hampton, Vice President, Oconee Site
- 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.
b.
Plant Status
Unit 1 essentially operated at 100% power the entire reporting period.
2
Unit 2 conducted normal power operations until October 6, 1994,
when the generator was taken off line at 12:49 a.m. to begin a
scheduled 40-day refueling outage (U2EOC-14). The refueling
outage continued throughout the remainder of the reporting period.
Unit 3 essentially operated at 100% power the entire reporting
period.
c.
Unit 2 Midloop Operation
On October 9, 1994, the inspectors reviewed the licensee's
procedure for reduced reactor coolant (RCS) inventory during the
Unit 2 outage. The procedure (OP/2/A/1103/11, Draining And
Nitrogen Purging Of RC System, revised July 28, 1994) sets forth
the requirements for reducing RCS inventory. These include: a
minimum of two methods of alarmed level indications utilized to
monitor vessel levels; boron concentrations for safe shutdown
margin; availability of safety equipment; alignment and tagging of
systems and equipment; and two independent RCS temperature
indications.
The inspectors verified that the licensee met the requirements
specified in the procedure prior to entering a reduced RCS
inventory status. The low pressure injection flow rates were
being monitored in the control room via the operator aid computer,
flow indicators, and alarms on annunciator panel 3SA-3 (windows A8
and A9).
RCS temperatures were monitored on the operator aid
computer with alarms set at 125 degrees F, on the inadequate core
cooling monitor display, and on the control room instrument panel
The RCS levels were monitored by permanent instrumentation (LT-5A
and B) and ultrasonic level indicators that were installed
temporarily for mid-loop operating conditions. Levels were
alarmed and monitored on control room instruments and on the
operator aid computer.
In addition, the inspectors verified that configuration control of
containment penetrations was maintained. The equipment hatch was
only opened during the outage as necessary to move equipment in
and out of the reactor building. For the remainder of the time,
the hatch remained-closed. However, it was necessary for some
penetrations to remain open to support the outage work schedule
(i.e., cable penetrations for eddy current testing of the steam
generator tubes). A required closure time was addressed in the
event of a loss of decay heat removal capability.
The licensee maintained a Risk Summary Sheet for the availability
of equipment required to support the plant during reduced
inventory. This sheet included the status of systems, electrical
power sources, RCS makeup supplies, and containment penetrations
with the amount of time anticipated for closure. Based on the RCS
inventory, the "time to boil" was calculated in the event of a
loss of decay heat removal cooling. Overall, the licensee's
3
efforts were determined to be adequate in controlling and
monitoring plant conditions while the RCS inventory was maintained
at mid-loop.
d.
Primary Instrument Air Compressor Fails to Load
On September 28, 1994, the inspector observed the Unit 3 control
room operators respond to a drop in the instrument air header
pressure. The instrument air header pressure dropped to less than
80 psig, which resulted in an automatic swapover to service air
and an.automatic start of the auxiliary instrument air
compressors. The cause of the drop in air pressure was the
failure of the primary air compressor to properly-load after it
was started following maintenance.
Subsequent to maintenance, the primary air compressor was-started
and the backup air compressors were secured using OP/O/A/1106/27,
Enclosure 4.1.
Step 2.20 of Enclosure 4.1 instructed the operator
to remove the backup air compressors from service when the primary
air compressor parameters were stable. These parameters were
listed in step 2.19 of this enclosure. This list of parameters
was not sufficient to determine if the primary air compressor was
properly loading. For example, the list of parameters in step
2.19 included sump pressure and gave the allowable range as 50 to
130 psig, whereas if the compressor was properly loaded the sump
pressure would be greater than instrument air header pressure
(approximately 100 psig).
The cause of the primary air compressor
failing to load was the differential regulators being slightly out
of adjustment. The licensee indicated that OP/0/A/1106/27 would
be modified to require a sump pressure of between 100 and 130 psig
prior to securing the backup compressors. The inspector concluded
that the control room operator response to the low header air
pressure was good, and that the procedure enhancement was
appropriate corrective action.
e.
Inadvertent Venting of the Unit 2 Quench Tank
An inadvertent venting of the Unit 2 quench tank occurred on
October 17, 1994, at approximately 3:00 a.m., as indicated on the
air ejector offgas radiation monitor RIA-40. This was
subsequently determined to have resulted from operator activities
that were in progress to fill the shell side of the 2A Steam
Generator (SG). This evolution required the SG shell side vents
be opened to the quench tank. At the same time, the feedwater and
steam side of the steam generators were at 29" of vacuum. RIA-40
stayed in the alarm condition with the counts decreasing for
approximately 50 minutes. The licensee was unaware that the alarm
condition was due to this evolution.
RIA-40 alarmed again at approximately 2:00 p.m., on October 17,
1994, during the filling of the 2B SG from the 2A SG (shell side
vents open to the quench tank). RIA-40 counts were decreasing at
4
3:00 p.m., when valve 2GWD-1 was opened to vent the pressurizer to
the quench tank as required by the procedure for reducing the RCS
inventory. At this time, RIA-40 alarmed again and it was noticed
that the pressure in the pressurizer had reduced, but the pressure
in the quench tank had not increased as expected. As a result,
the Senior Reactor Operator had the shell side vents on SG 2B
closed and the quench tank pressure began to increase. The RIA-40
alarm subsequently cleared. It was determined that when the shell
side SG vents were open to the quench tank, existing gas was being
drawn into the main condenser and to the atmosphere through the
steam jet air ejectors and the Unit 2 vent stack.
The inspectors will review the events that were in progress which
may have contributed to the failure to detect and correct this
condition in a timely manner. This item will be tracked as
Inspector Followup Item (IFI) 270/94-32-01:
Failure to Detect
Inadvertent Quench Tank Venting.
f.
Inoperable Containment Isolation Valve
On October 5, 1994, the licensee torqued the body to bonnet joint
on valve 1RC-7 to 125 percent of its normal torque value due to a
body to bonnet leak. Valve IRC-7 is the outboard pressurizer
sample containment isolation valve. The maintenance activity was
conducted per Work Order 94068251, Task 01.
The work activity was
commenced at approximately 8:30 a.m. and was completed at
approximately 10:37 a.m. Prior to performing the work activity
the operators in the control room asked the maintenance
technicians performing the work if post maintenance testing of the
valve was required. They were assured that testing would not be
required. At approximately 5:00 p.m., on October 5, 1994, a
performance planner requested that valve IRC-7 be stroke tested to
verify operability of the valve following the maintenance
activity. The control room operators declared the valve
inoperable and isolated the containment penetration and
deactivated the valves upstream of valve 1RC-7 until the required
post maintenance testing could be performed. The valve was stroke
tested satisfactorily; however, a question remained as to whether
a leak test was required to return the containment penetration to
an operable status. Subsequent review by the licensee determined
that a local leak rate test was not required based on the work
activity performed on the valve. The valve was declared operable
on October 7, 1994.
The licensee determined that the failure to declare valve 1RC-7
inoperable prior to performing the maintenance activity was a
result of the maintenance planners entering a not applicable (N/A)
statement on the Post Maintenance Testing (PMT) sheet. The work
order identified that a functional test, stroke test, and leak
rate test was required. The planners marked the signoffs on the
PMT sheet not applicable (N/A) because they stated that the
required tests would be documented on separate task sheets;
5
therefore, the N/A(s) were utilized to indicate that no signatures
were required on the PMT sheet. The maintenance technicians
assumed that the N/Aed steps meant that post maintenance testing
was not required.
A Licensee Event Report (LER) will be submitted to the NRC in
accordance with the requirements of 10 CFR 50.73. Also, as a
result of this problem, the licensee instituted the following
corrective actions:
(1) Work orders planned after October 12, 1994, contain a cross
reference statement on the PMT sheet that links the
controlling task to the supporting tasks that will perform
each retest.
(2) Work orders planned prior to October 12, 1994, but not
scheduled, were reviewed and the N/A(s) struck through and a
cross reference inserted.
(3) Maintenance personnel were informed that N/A(s) on the Post
Maintenance Test Sheet does not indicate that the test is
not required.
The failure to declare valve 1RC7 inoperable and perform the
required post maintenance testing is considered a licensee
identified violation.
However,
this violation will not be subject
to enforcement action because the licensee's efforts in
identifying and correcting the violation meet the criteria
specified in Section VII.B of the Enforcement Policy.
Accordingly, it will be identified as Non-cited Violation (NCV)
50-269/94-32-02:
Inoperable Containment Isolation Valve Due to
Maintenance Error.
Within the areas reviewed, one NCV was identified.
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, exposure was controlled, equipment was
properly returned to service, and limiting conditions for
operation were met.
The following maintenance activities were observed or reviewed in
whole or in part:
(1) Integrated Control System Feedwater Control, B Loop,
IP/0/B/0325/002
6
On October 13, 1994, the inspectors witnessed a calibration
that was in progress on the Unit 2 feedwater main and
startup valve control system. Problems were experienced in
that the control module did not duplicate the bench
calibration after it was reinstalled in the panel.
As a
result, the module was replaced with a new module.
Performance of the activity was in accordance with the
procedure and the effort was determined to be acceptable.
(2) Install and Reconnect 2LPSW-15, Work Order 94082562, Task 05
On October 29, 1994, the inspectors observed portions of the
work activities associated with the reinstallation of Low
Pressure Service Water valve 2LPSW-15. The inspectors
reviewed the work order for adequacy and observed the
completion of the work activity. No deficiencies were
noted.
(3) Engineered Safeguards System Analog Channel B Reactor
Coolant Pressure Channel Calibration, IP/O/A/0310B/004B
The licensee received a Unit 2 Engineered Safeguards (ES)
actuation on October 21, 1994 during the performance of
procedure IP/0/A/0310/004B.
While calibration of channel B
was in progress, channel A was inadvertently placed in the
"range" position as opposed to channel B as required by step
10.7.3.a of the procedure. (Note: The procedure referred to
the switches as A and B and the panel was labeled as
channels 1 and 2).
As a result of the event the licensee
generated Problem Investigation Report 2-094-1493, which
required an evaluation and corrective actions.
Having the two analog channels in a test status
simultaneously resulted in the ES Actuation. The major
events resulting from the actuation were:
-
Emergency start of .Keowee Units 1 and 2
-
The containment purge tripped due to purge valves PR-2
through PR-5 going shut
-
Low pressure service water pumps B and C started
Other ES devices actuated, but the equipment was out of
service as a result of the refueling outage and the
components did not start or realign.
The failure to place the proper switch to the required
position as specified by the procedure is identified as
Example 1 of Violation 270/94-32-03:
Failure To Follow
Procedures.
7
(4) AC Watt Transducer, Two Element, IP/O/A/3955/01
On October 26, 1994, switchgear 2TE experienced an
inadvertent undervoltage trip condition as a result of
testing errors during testing of transducer 2ET42. The
maintenance technicians failed to remove the test leads
attached to the terminal block prior to reclosing the link
and repowering the circuitry that had been taken out of
service for the test. As a result, the test leads made a
path to ground through the test equipment and resulted in
blowing a fuse in the 2TE switchgear when the circuit was
repowered. Step 10.7.17 of IP/O/A/3955/01 removes the test
equipment prior to restoring the plant equipment to service.
Although no signoff was required procedurally for performing
this step, the requirements for performing the activity were
explicit..."Remove test equipment."
Failure to comply with
the requirements of the procedure is identified as Example 2
of Violation 270/94-32-03: Failure To Follow Procedures.
(5) 2DIA Static Inverter Replacement, TN/2/A/288 1/0/AL1
On October 17, 1994, the inspectors observed the
installation of the power cables, ground cable, and alarm
circuitry wiring on the new 2DIA Static Inverter. The
inspectors verified that the work was conducted under an
approved procedure and that the as-left wiring was
consistent with design drawings.
All activities observed
were satisfactory.
(6) Investigate Slow Stroke Time for 3BS-1, Work Order 94079209,
Task 01
On October 16, 1994, motor operated valve 3BS-1 failed to
satisfy performance stroke testing requirements. 3BS-1 is
the 3A reactor building spray pump's discharge isolation
valve, and is given an automatic open signal as part of an
Engineered Safeguard (ES) actuation. The performance test
measured an open stroke time of 14 seconds, as measured on a
stopwatch. The acceptance criteria per PT/3/A/0150/22A was
9 to 13 seconds. The acceptance criteria was based on a
baseline value of 11 seconds. The Final Safety Analysis
Report (FSAR) indicates that this valve is assumed to open
within 15 seconds. The licensee initially declared 3BS-1
inoperable and entered the seven day LCO for an inoperable.
train of building spray. The licensee performed electrical
and mechanical preventive maintenance on the valve operator,
including cleaning contacts and stem lubrication. Multiple
stroke tests were subsequently performed utilizing a Motor
Power Monitor (MPM) to precisely measure the stoke time. A
total of five MPM tests were performed and the stroke time
was consistently 13.5 plus or minus 0.1%. Based on this,
the licensee concluded that the valve was not currently
8
degrading and would meet the 15 second FSAR limit.
Consequently, the LCO was exited. The licensee believed
that maintenance performed during January 1994, which
included limit switch adjustment, may have altered the
baseline for this valve and that this would account for the
slower stroke time. The licensee indicated that they would
perform weekly stroke tests to confirm that the valve was
not degrading. The inspectors observed various portions of
the licensee's troubleshooting efforts including two of the
MPM stroke tests. The inspectors concluded that the
licensee's actions were acceptable.
b.
Surveillance activities were conducted with approved procedures
and in accordance with site directives. The inspectors reviewed
surveillance performance, as well as system alignments and
restorations. The inspector assessed the licensee's disposition
of discrepancies which were identified during the surveillance,
The following surveillance activities were observed or reviewed in
whole or in part:
(1) Control Rod Movement, PT/O/A/600/15
The inspectors witnessed performance of Unit 1 Control Rod
Drive (CRD) movement on October 6, 1994. The purpose of the
procedure was to test CRD operation under actual operating
conditions by moving each rod group a minimum of 2.5 percent
of full travel.
This test met the monthly surveillance
requirements as specified in Technical Specification 4.1.2.
The operators performed the rod movements per the procedure
and were cognizant of plant operating status during the
test. The activity was determined to be performed to
acceptable standards.
(2) Reactor Building Spray Pump Test, PT/1//A/0204/07
Portions of the reactor building spray pump test were
witnessed by the inspectors on September 27, 1994. The
quarterly test was necessary to satisfy TS 3.3.2, 3.3.6,
4.0.4. and 4.5.2, as well as Subsections IWP and IWV of
Section XI to the ASME Code. The performance test
demonstrates operability of the system. During testing of
the 1B Pump, high vibration was detected and determined to
be in the alert range. The pump was determined to be
operable, but the testing frequency was changed and the test
will be performed at 2 times the normal frequency.
As each pump was taken out of service, the appropriate
Limiting Condition for Operation was' entered as required per
step 6.1 of the test procedure. The conduct of testing was
viewed by the inspectors as a strength.
9
(3) Control Room Pressurization Test, PT/1&2/A/0170/03
The inspectors observed portions of this performance test
conducted on October 26, 1994. This test implements the
surveillance requirements .of Technical Specification 4.12.1.
The inspectors verified that the procedural acceptance
criteria was met.
(4) Unit 2 Main Feeder Bus 2 Lockout Test, TT/2/A/610/14
The inspectors observed portions of this temporary test
procedure conducted on October 26, 1994. This test
procedure verified that the Unit 2 Main Feeder Bus 2 lockout
relays operated properly. This test had not been performed
on Unit 2 prior to its performance on October 26, 1994.
During performance of the test, the startup breaker (E2)
failed to trip open when the 86B2 lockout relay was
actuated. Investigation by the licensee determined that
physical interference with the wiring connected to the
contact terminal prevented the actuation contact from
closing. The wiring interference was corrected and the test
was completed without further problems.
The licensee visually inspected the Unit 3 lockouts to
verify that adequate clearance existed between the terminal
lugs and the moving contacts. The Unit
1
main feeder bus
lockout relays had been tested during the previous Unit 1
refueling outage without incident. In spite of the
identified problem, the licensee determined that the Unit 2
Main Feeder Bus had been operable based on the fact that the
startup breaker's redundant trip coil had been operable and
would have operated to open the breaker if an actual fault
had occurred on the Main Feeder Bus.
(5) Unit 2 Control Rod Drive Drop Test, IP/0/A/330/03A
Drop time testing of the Unit 2 control rods was performed
on October 6, 1994.
The unit was shutdown for refueling
outage EOC14 with the reactor coolant system at 532 degrees
F and all 4 reactor coolant pumps running. Results of the
test showed that rod #3 in group #1 dropped at 1.803
seconds, which was slower than the TS limit of 1.66 seconds.
As a result, a second rod drop test was performed and the
same rod (rod #3) dropped at 1.758 seconds. Results of the
second test also showed a second rod, rod #4 in group #1, to
have increased in drop time to greater than the TS limit.
Rod #4 dropped at 1.662 seconds and was the only rod which
increased in drop time from the first to the second test.
A summary of the test results indicated that the drop times
for an additional 8 rods were slow enough (i.e., greater
than 1.40 seconds) to generate doubt that they may not meet
10
TS requirements after operating for another fuel cycle
(approximately 18 months).
One of these rods, rod #1 in
group #1, which dropped at 1.417 seconds during the first
test and at 1.328 seconds during the second test, was
evaluated by the licensee and determined not to be a problem
during the next fuel cycle. Past operating history of the
rod was reviewed and was considered as part of the
operability evaluation.
The slow rod drop times were determined to be a result of
erosion material build-up in the area of the ball checks in
the thermal barrier cooler. The ball checks are required to
raise off their seat to allow RCS coolant flow to enter and
replace the void created in the housing when the rods fall
into the core.
As a result, the thermal barrier coolers were replaced in 8
of the drive shaft housing assemblies with a modified cooler
(modified type A) that increased clearances in the area of
the ball check valves. The 9th assembly was replaced with a
spare rod drive shaft housing assembly that had been cleaned
and restored to the original clearances.
A statistical analysis was done on the Unit 1 control rods.
The analysis indicated that continued operation of Unit 1
would not result in rod drop times greater than Technical
Specification allowable values. However, the licensee
indicated that the operability of the Unit I rods would be
reassessed in April 1995.
The thermal barriers in the Unit 3 CRD shaft housing
assemblies are type C. There have been no reported
problems with CRD drop times associated with ball checks in
the type C thermal barrier coolers.
(6) Turbine Driven Emergency Feedwater Pump Test, PT/1/A/0600/12
On September 26, 1994, the inspectors witnessed performance
testing of the Unit 1 turbine driven emergency feedwater
pump. The test was required to be performed quarterly as
specified per TS to satisfy the American Society of
Mechanical Engineers (ASME),Section XI requirements. The
applicable sections of the TS which relate to pump
operability and stroke testing of valves were 3.4, 4.0.4,
and 4.9.
Personnel performing the test were knowledgeable of the
operation of the equipment and their performance was
determined to be very good.
11
(7) Operation of the SSF Diesel Generator, OP/0/A/1600/10
On October 3, 1994, the inspectors witnessed post
maintenance testing of the Safe Shutdown Facility (SSF)
Diesel Generator. The inspectors noted that step 2.15 of
the test procedure required that the Diesel Engine Log Book
be referenced to determine if the diesel had been operated
less than 700 KW for greater than 2 accumulated hours, in
order to determine if the engine needed to be "desouped" (a
procedure that involves burning out deposits in the exhaust
manifold). The inspectors reviewed the Diesel Engine Log
Book and noted that the information included was inadequate
to determine the exact amount of time the engine had been
operated at less than 700 KW. The licensee agreed that the
Diesel Engine Log Book did not contain sufficient detail to
comply with step 2.15, but stated that they had been
informed by the diesel manufacturer some time ago that the
desouping procedure was not necessary. However, they had
neglected to remove this step from the procedure. The
inspector concluded that this represented a weakness in the
licensee's procedure. The licensee indicated that step 2.15
would be deleted. All other aspects of the procedure were
satisfactory and the diesel and its support equipment met
all acceptance criteria.
(8) -Low Pressure Injection Pump Test, PT/3/A/0203/06A
On October 4, 1994, the inspectors witnessed the performance
of the quarterly operability test of the 3A Low Pressure
Injection (LPI) Pump. The indicated developed head for the
pump was 186 psid, according to instrument 3PG-21. This
exceeded the acceptance criteria of 158.5-181.5 and would
have placed the pump in the alert range. However, the
difference between the indicated pressure on the suction and
discharge gages was 174 psid. Therefore, the licensee
concluded that instrument 3PG-21 was out of calibration and
the developed head of the pump was within the acceptance
criteria. The inspectors agreed with the licensee's
conclusion and determined that all activities observed.were
satisfactory. The licensee plans to recalibrate 3PG-21
prior to the next performance of the procedure.
(9) Turbine Stop Valve Movement Test, PT/O/A/290/04
The inspectors witnessed the monthly test of the Unit 3 main
steam stop valves as required by TS 4.1.
This test closed
each valve approximately 10% in order to verify valve
movement locally and via the control room meter. All
activities observed were satisfactory.
Within the areas reviewed, one violation with two examples was
identified.
12
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.
Turbine Bypass Isolation Test, TT/2/B/0251/46
The inspectors witnessed testing activities to evaluate leakage
through the Unit 2 turbine bypass valves. The test was performed
in accordance with test procedure TT/2/B/0251/46, Turbine Bypass
Isolation Test. The test consisted of evaluating plant MWe output
and condenser vacuum during closure and reopening of the block
valves to each of the bypass valves. The test data was taken via
the operator aid computer and was utilized to determine the need
for bypass valve maintenance or replacement during the Unit 2
refueling outage.
Performance of the testing activities was considered to be
acceptable.
b.
10CFR Part 21 Review
The inspectors reviewed a 10CFR Part 21 .issue, identified by
Dresser-Rand dated August 5, 1994, that related to a deficiency
with the Gimple trip throttle valve on the turbine driven
auxiliary feedwater pump at Davis-Besse Unit 1. The reported
deficiency was that the coupling set screw on the trip throttle
valve had not engaged the valve stem and therefore, the stem
travel was impaired.
The Duke Power General Office reviewed the subject report and
determined that Gimple valves were utilized at their Catawba and
McGuire Nuclear Stations. As a result, problem identification
report (0-G94-0365) was issued to initiate preventative measures
at those sites. However, the licensee determined that Gimple
valves did not exist at the Oconee Nuclear Station and no
corrective actions were necessary.
The inspector verified that General Electric turbines were
installed at the Oconee Nuclear Station and that Gimple valves
were not utilized.
No violations or deviations were identified.
5.
Plant Support (71750)
The inspectors assessed selected activities of licensee programs to
ensure conformance with facility policies and regulatory requirements.
During the inspection period, the following areas were reviewed:
13
radiological controls; radiological effluent, waste treatment, and
environmental monitoring; physical security, and fire protection.
a.
Radiation Protection
During a tour of the turbine building on October 11, 1994, the
inspectors noticed maintenance personnel crossing the
yellow/magenta ropes set up to identify a radiation controlled
zone (RCZ) at main steam reheater 2B2. When the maintenance
personnel were questioned, they informed the inspectors that
health physics (HP) personnel had informed them that it was not
necessary to comply with the rules established for an RCZ since no
radiation hazard existed until the manways were removed from the
heater.
The area HP was summoned to the area and it was verified that the
maintenance personnel had been told that the yellow/magenta ropes
were to be ignored until the manways were removed. The HP
informed the inspectors that the RCZ was set up in advance to get
a "head start" on the outage effort.
The licensee's directive, Radiation Protection, Directive No. III
3, Posting of Radiation Control Zones, requires that an RCZ be
identified with a yellow/magenta rope with placards attached
indicating the requirements for entering the zone. Although the
placards had not been installed, the inspectors determined that
allowing personnel to cross back and forth across the
yellow/magenta ropes was a poor practice and a weakness in the
Health Physics Program. The inspectors had identified this poor
practice during a previous refueling outage. At that time, the
licensee agreed to caution workers to treat all RCZ ropes as
boundaries at all times.
After bringing this latest observation to the attention of
licensee management, the inspectors were assured that the practice
would be corrected. The inspectors observed various RCZs
throughout the remainder of the reporting period and did not
identify any instances where the yellow/magenta ropes were being
ignored.
No violations or deviations were identified.
6.
Exit Interview
The inspection scope and findings were summarized on November 2, 1994,
with those persons indicated in paragraph 1 above. The inspectors
described the areas inspected and discussed in detail the inspection
findings addressed in the summary and listed below. The licensee did
not identify as proprietary any of the material provided to or reviewed
by the inspectors during this inspection.
14
Item Number
Description/Reference Paragraph
50-270/94-32-01
IFI:
Failure to Detect Inadvertent Quench
Tank Venting (paragraph 2.e).
50-269/94-32-02
NCV:
Inoperable Containment Isolation
Valve Due to Maintenance Error (paragraph
2.f).
50-270/94-32-03
VIO:
Failure to Follow Procedures - Two
Examples (paragraph 3.a).
(III