ML15118A327
| ML15118A327 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 03/05/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A253 | List: |
| References | |
| 50-269-97-18, 50-270-97-18, 50-287-97-18, NUDOCS 9803180070 | |
| Download: ML15118A327 (38) | |
See also: IR 05000269/1997018
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
-.Docket Nos:
50-269, 50-270, 50-287, 72-04
Report No:
50-269/97-18, 50-270/97-18, 50-287/97-18
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station, Units 1, 2, and 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
December 28, 1997 -.February 7. 1998
O
Inspectors:
M.
Scott, Senior Resident Inspector
S.-Freeman, Resident Inspector
E. Christnot, Resident Inspector
D. Billings, Resident Inspector
Paul Kellogg, Regional Inspector (Section E8.2)
Jerry Blake, Regional Inspector (Section M1.4)
Nick Economos, Regional Inspector (Section E1.1)
Approved by: C. Ogle, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9803180070 980305
PDR ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2, and 3
NRC Inspection Report 50-269/97-18.
50-270/97-18, 50-287/97-18
'This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant.support. -The-report covers a six-week
period of.resident inspection, and the results of announced inspections by
three regional based inspectors.
Operations
Operations personnel satisfactorily shut down Unit 1 following a steam
generator tube leak. The licensee identified a related procedure
problem that resulted in a Non-Cited Violation.
Operations
satisfactorily performed the shutdown and overall once through steam
generator configuration control work. The licensee drained the reactor
coolant system in a controlled fashion to reduced inventory levels five
times during the work. This problem is also discussed in Section M1.4.
(Section 01.3)
Operations personnel displayed a good questioning attitude that allowed
them to detect an unexpected power increase during letdown flow
instrument calibrations. This problem is also discussed in Section
M3.1. (Section 01.4)
The licensee exited a 24-hour limiting condition for operation on the
Unit 3 reactor building emergency hatch without fully understanding that
a Technical Specification interpretation did not relieve them of the
surveillance requirements for further testing. This issue was left
unresolved pending review of past.practices. (Section 01.5)
The licensee carefully tested and satisfactorily replaced a Unit 1
control rod, which had latching problems. Operations and engineering
provided good overall controls during the rod freedom of motion test.
(Section 01.6)
Operations satisfactorily manipulated Unit 1 to cold shutdown for
repairs and investigation of a 2 gallon per minute leak from a crack on
a one-inch drain line off the pressurizer surge line. Operations made
appropriate notifications and reports. (Section 01.7)
An apparent lack of agreement between the Safe Shutdown Facility diesel
technical manual and operations procedures will be tracked through an
unresolved item. (Section 03.1)
2
The licensee and its primary vendor removed and disassembled a
malfunctioning Unit 1 control rod mechanism, finding no definitive
problem. The overall inspection work was performed in a satisfactory
manner, with care to detect as-found conditions. (Section M1.2)
During the pressurizer surge line drain line work, pipe removal and
reinstallation practices and controls were generally acceptable. Health
physics personnel appropriately supported the maintenance activities.
ne rework item was observed that is discussed as a violation in
Inspection Report 50-269,270,287/98-01. (Section M1.3)
The December 28, 1997, Unit 1 shutdown for primary-to-secondary leakage
that was the result of past repairs where there had been an apparent
over-reliance on the results of visual inspections, and less than
adequate appreciation for primary water stress corrosion cracking.
(Section M1.4)
A violation was identified for failure to revise a high pressure
injection system letdown flow instrument calibration procedure following
modification of the Unit 3 integrated control system. (Section M3.1)
During inspection and testing of Safe Shutdown Facility 600 volt
breakers, several problems were identified by the licensee. The
licensee satisfactorily addressed the immediate equipment.problems.
Several issues regarding grease hardening and trip device past
operability were identified. (Section M3.2)
On January 30, 1998, the licensee was granted verbal enforcement
discretion on statements in their TS regarding TS surveillance
performance intervals. The licensee submitted a TS change to allow
eighteen-month periodicity of surveillance instead of a refueling outage
periodicity. The inspectors had reviewed the change for completeness.
Additional followup on the enforcement discretion will be tracked under
an unresolved item. (Section X2)
Engineering
Replacement of the cracked one-inch drain line on the pressurizer surge
line was consistent with applicable code requirements. A lack of
attention to detail in the planning phase of welding the replacement
line caused a significant job delay and the need to cut and re-weld a
new weld on the line. Engineering provided adequate support and took an
active role in determining the root cause of the crack. Welding,
nondestructive examination, and process control activities were
satisfactory. Stress analysis calculations determined that thermal
stratification and hanger loads on the drain line exceeded code
allowable usage factor requirements on the drain line nozzle.
(Section E1.1)
Three examples of a violation resulting from procedural inadequacies
were identified. An engineering supported troubleshooting procedure did
not minimize risk to equipment and was not completely validated prior to
performing work. Use of the procedure on Unit 2 integrated control
3
system wiring resulted in unexpected system responses. The other two
examples are discussed in Section E2.2. (Section E2.1)
Two additional examples of the violation resulting from procedural
inadequacies were identified on the Keowee Hydroelectric units. One
example involved the.motor operated automatic voltage adjusters on both
Keowee units not being adjusted in accordance with their applicable
drawings due to lack of procedural detail.
The other example involved
missed in-service tests on both Keowee Hydroelectric units due to
engineering not converting a temporary test into a periodic test of lube
oil valves. (Section E2.2)
A Non-Cited Violation was identified for failure to follow procedures
controlling modifications as discussed in Licensee Event Report 50
269/97-10, regarding reactor building sump issues. (Section E8.1)
The licensee was making good progress in the installation of the service
water modifications. Modifications on Unit 2 should be completed during
the March 1998 outage. (Section E8.2)
Plant Support
A Non-Cited Violation was identified for failure to perform a continuous
fire watch as required by the selected license commitments. The
licensee had performed hourly fire watches instead of continuous fire
watches when they removed the Unit 2 and 3 startup transformers fire
protection deluge system from service. (Section F1.1)
Report Details
Summary of Plant Status
Unit 1 began the report period at approximately 54 percent power, performing
integrated control system testing. On December 28, 1997, the unit began
equired shutdown activities following the identification of a primary-to
secondary leak. During the heat up following completion of inspection and
repairs to both steam generators, a leak was identified on the pressurizer
surge line drain. At the end of the report period, the unit was in cold
shutdown.
Unit 2 began and ended the report period at 100 percent power.
Unit 3 began and ended the report period at 100 percent power.
Review of Updated Final Safety Analysis Report (UFSAR) Commitments
While performing inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed
plant practices, procedures, and parameters.
I. Operations
01
Conduct of Operations
01.1 'General Comments (71707)
Using Inspection Procedure 71707., the inspectors conducted frequent
-reviews of ongoing plant operations. In
general, the conduct of
operations was professional and safety-conscious; specific events and
noteworthy observations are detailed in the sections below.
01.2 Operations Clearances (71707)
The inspectors reviewed the following clearances during the inspection
period:
.97-4445
Unit 3 Seal Supply Filter Swap
98-0207
Unit 1 Component Cooling Water Cooler
The inspectors observed that the clearances were properly prepared and
authorized and that the tagged components were in the required positions
with the appropriate tags in place.
01.3 Unit 1 Once Through Steam Generators (OTSG) 1A Tube End Weld Leaks
a. Inspection Scope (71707, 93702)
On December 28, 1997. the licensee detected radioisotopes in the
secondary system of Unit 1. The unit was at 54 percent power conducting
a power escalation following the refueling outage. The licensee
2
initiated a controlled shutdown and Problem Investigation Process (PIP)
report 1-97-4641 (with a failure investigation process team). The
inspectors observed the controlled shutdown of the unit, the once
through steam generator (OTSG) work, and subsequent return of the unit
to service. The inspectors also reviewed Licensee Event Report 97-11
written to document the event. A regional inspector was detailed to the
site in order to follow the repairs. Section M1.4 addresses
nondestructive inspections and engineering details of the problem and
related repairs.
b. Observations and Findings
Sequence of Events
On December 27, 1997, the licensee completed an integrated control
system (ICS) load rejection test from approximately 25 percent power.
About one hour after the end of the ICS test segment, radiation process
monitor RIA-40 for the condenser steam air ejectors went into alarm.
Following the guidance of PT/O/A/0230/01, Radiation Monitor Check,
Revision 109C, operations reset the RIA-40 alert alarm setpoint at twice
background level. However, the operations crew involved overlooked a
note on the next page of the procedure which indicated that if RIA-40
alarmed, samples should be taken to verify the leak rate. At shift
turnover the next morning, the shift discussed the reset of RIA-40. The
oncoming operators indicated that a sample was needed, and one was
subsequently taken~at 8:08 a.m., on December 28.1997. Confirmatory
samples in the afternoon of that same day confirmed a tube leak. The
licensee then entered the emergency operating procedure for an OTSG tube
leak. At 3:07 p.m. a unit shutdown was initiated. At 3:32 p.m. the
licensee completed a 10 CFR 50.72 notification to the NRC duty officer.
The unit was off line at 4:46 p.m.
Tube Leak Detection
The first indication of the primary-to-secondary leak was on the
condenser steam air ejector radiation monitor. At the time of the RIA
40 alarm and reset on December 27, 1997, historical trend data indicated
small but progressive increases in radiation levels. Additionally, the
RIA-16 (1A main steam line) monitor did trend up slightly, but did not
reach the alarm setpoint (2.5 millirem (mr) per hour setpoint with a
maximum attained value of slightly higher than 0.06 mr per hour).
The inspectors were informed that radiation instruments such as the
condenser steam air ejector monitor, will show increases in background
and may show small spikes due to power changes and material releases
from deposits in the secondary breaking loose. The inspectors were also
informed that historically during startups, RIA-40 required a reset of
its setpoint to compensate for normal background increases.
Due to the low radiation levels, the leak was not readily detectable.
Although secondary off-gas process monitoring is generally the first
indication of an OTSG tube leak, the small size of the 1A OTSG leak and
the minimal isotopic migration to the secondary made this leak
3
particularly difficult to detect.. The leakage was relatively free of
isotopes due to the recently refueled core, overall cleanliness of the
primary, and limited size of the leak.
Likewise, the chemistry department could not positively identify a leak
with the 8:00 a.m. samples, but similarly could not disprove its
presence. The xenon isotope was in low concentration in the primary.
he licensee used the minimum detectable limit, an artificial number,
for the isotopic concentration in the leakage rate calculation. This
calculation produced an initial leak rate of 260 gallons per day (gpd)
following the first sample.
RIA-16 for the 1A steam line indicated an increasing trend. The RIA-17
monitor for the lB steam line was flat-lined. Given this and the
inability to disprove a leak, the licensee drew a second series of
samples and analyzed them in the early afternoon (there was a 90 minute
sample preparation time). As the power was increased by the time of the
second sample, the xenon isotope in the primary was elevated and
slightly above the minimum detectable level.
The licensee introduced
this value into the leak rate calculation which resulted in a higher
leak rate of 404 gpd. With the low isotopic levels in the primary and
the change in power, the licensee believed that there was no true
increase in the leakage rate between the 8:00 and 11:00 a.m. samples.
At that point, with no radiation process monitors in an alarm state, the
licensee decided to shut down the unit. The secondary and turbine
building sumps received very small increases in radiation levels.
The inspectors determined that had rimary and secondary chemistry
samples been drawn at the time of te initial RIA-40 alarm, it was
inconclusive that the licensee would have detected the leak since there
was very little radiation specie concentration in the secondary.
Adequacy of Radiation Monitor Procedure
The inspectors reviewed the RIA-40 instructions contained in Procedure
PT/0/A/0230/01 and observed that they were not adequate from two
perspectives. First, the requirement for sampling was contained in the
"notes" of the procedure outside the procedural text. Second, the
direction to take samples contained a "should" statement.
The subject procedure was not adequate in that policy intent or prudent
requirements were not positively and clearly stated as required in
Nuclear Site Directive 703, Administrative Instructions for Site
Procedures, revision date December 30, 1997, Section 703.5, Preparation
of Procedures. Subsection 4 of the directive indicated, in part, "That
all instructions should be clear and precise. Ambiguous and vague
wording or implied action should be eliminated from the procedure."
Additionally, Regulatory Guide 1.33,.Revision 2, which is invoked under
the licensee's topical report, states that "shall" statements are to be
used instead of "should" statements where the procedural step is of
sufficient importance. Operations management stated.policy was to take
the samples with an alarm of RIA-40.
0II
4
An operations management review of the tube leak events on or before
January 8, 1998 (prior to LER issuance), initiated correction actions to
be available for the next startup and normal plant operation.
Operations, in conjunction with Chemistry, performed the following
corrective actions: (1).discussed the sampling expectations with the
operations crew of December 27, 1997: (2)
provided the sampling
expectations to the other operational shifts; (3)
incorporated what had
been notes in the previous revision of PT/0/A/0230/01 as requirements
and added enhancements in the reset of RIA-40: (4)
changed annunciator
response Procedure 1SA-8/D-10, Radiation Monitoring, to clearly state
samples were to be taken by chemistry when RIA-40 went into alarm
(instead of referring to another complex document): (5)
rewrote
Procedure OP/0/A/1106/31, Control of Secondary Contamination, to enhance
rocedure usefulness and integration with the above PT. Inadequate
rocedure PT/O/A/0230/01 was identified as a violation. This non
repetitive, licensee identified and corrected violation is identified as
a Non-Cited Violation (NCV) consistent with Section VII.B.1 of the NRC
Enforcement Policy, NCV 50-269/97-18-01: Inadequate RIA Procedure.
Performance of Operating Crews
The rapid shutdown of the unit following confirmation of the tube
leakage on December 28, 1998, was well controlled by operations
personnel.
Between January 1 and January 15. 1998, the unit was drained five.. times
to reduced inventory levels. This was done to permit nozzle dam.
installation or removal in
the Unit 1 OTSGs. An inspector was present
for each of these draindowns, observing good control of the evolutions.
With the number of draindowns performed, the licensee had reduced the
activity to near routine, but retained the correct operational
perspective. Control room operators provided oversight for tube sheet
pressure tests that were similarly properly controlled.
c. Conclusions
Operations personnel satisfactorily shut down Unit 1 following a steam
generator tube leak. The licensee identified a related procedure
problem that resulted in a Non-Cited Violation. Operations
-satisfactorily performed the shutdown and overall once through steam
generator configuration control work. The licensee drained the reactor
coolant system in a controlled fashion to reduced inventory levels five
times during the work.
01.4 Unit 3 Power Change Due to Letdown Flow Calibration
a. Inspection Scope (71707)
The inspectors reviewed the operational aspects of an unexpected power
increase on Unit 3. The maintenance controlled procedural aspects are
discussed in Section M3.1.
5
b. Observations and Findings
.
On January 15, 1998, while Unit 3 was at 100 percent power and
instrumentation technicians were calibrating letdown flow
instrumentation, operations personnel observed a slight decrease in the
core thermal power best one hour average and a slight increase in
megawatt output.
Operations personnel notified reactor engineering, who identified that
the letdown flow signal was an input to the thermal power calculation
and that the thermal power calculation provided feedback to ICS.
Following consultation with reactor engineering and completion of the
evaluation, operations stopped the letdown flow calibration and reduced
core thermal power demand by 0.2 percent.
When the letdown flow signal was set to zero during the calibration,
core thermal power feedback to ICS decreased by 0.15 percent. In
response. ICS adjusted feedwater flow enough to bring core thermal power
back to 100 percent. However, since only the letdown signal was zero
and not actual letdown flow, core thermal power never decreased and the
adjustment by ICS caused actual core thermal power to exceed 100
percent. Licensee calculations determined that shift average power
increased from 99.95 to 99.98 percent of rated power over an hour and a
-
half period and that'core thermal power reached a maximum of 100.10
percent of rated power. After reviewing TS and the reactor engineering
power calculations, the inspectors-determined that no power limits were
exceeded.
c. Conclusions
Operations personnel displayed a good questioning attitude that allowed
them to detect an unexpected power increase during letdown flow
instrument calibrations.
01.5 Unit 3 Reactor Building (RB) Emergency Hatch
a. Inspection Scope (71707)
The inspectors reviewed the circumstances surrounding testing and
operability-of the Unit 3 RB Emergency Hatch.
b. Observations and Findinqs
On January 19, 1998, the licensee was performing Procedure
PT/0/A/0150/08B. RB Emergency Hatch Leak Rate Test, Revision 25, and
entered the hatch to remove strongbacks from-the inner door as required
by procedure. U
pon exiting the hatch, the licensee found that the outer
door would not close properly. The licensee declared the outer door
inoperable and entered a 24-hour Limiting Condition for Operation in
accordance with TS 3.6.3.a.
The licensee investigated the outer door and found that a small air
pocket had been trapped behind the outer 0-ring. Maintenance personnel
6
removed the air and closed the outer door properly. The licensee
determined that no maintenance had been done; therefore, no further
testing was required. Based on this, the licensee declared the outer
door operable and exited TS 3.6.3.a.
Further investigation by the operations staff continued into January 20,
1998. On the next shift, the licensee determined that the hatch was
inoperable due. to an inoperable door gasket, and that a leak test of the
outer door double seal was required. The licensee again declared the
outer door inoperable and entered a seven-day LCO in accordance with TS 3.6.3.a.2. The licensee subsequently made the starting time for the LCO
retroactive to the previous day when the hatch was originally declared
inoperable. The licensee completed a test of the outer door 0-rings
using Procedure PT/0/A/0150/09A, RB Emergency Hatch Outer Door 0-Ring
Leak Rate Test. Revision 13. The outer door was subsequently declared
operable and TS 3.6.3.a. was exited. The licensee documented the
occurrence in PIP report 3-98-272.
The inspectors reviewed TS 3.6.3 and TS 4.4.1.5.2, reviewed control room
and shift work manager logs, and interviewed personnel involved both in
the maintenance of the door and in the initial decision to exit TS 3.6.3.a without performing any further testing. The inspectors
determined that whether or not maintenance was performed did not affect
the need for further testing. TS 4.4.1.5.2 stated that either a full
hatch test or a leak test of the outer door double seal was required
within three days of initial opening. The licensee had interpreted this
TS to allow opening the outer door without further testing if the door
was opened to remove strongbacks following a full hatch test. However.
the inspectors determined the TS interpretation did not relieve the
licensee of the-surveillance requirement and therefore further testing
was required.
The licensee did not violate any TS in this case because the door was
reseated and tested within twenty-four hours. However, the existence of
a TS interpretation indicated the outer door may have been opened in the
past without proper surveillance testing. The circumstances surrounding
this issue will be tracked as URI 50-287/97-18-02: Containment Air Lock
Testing, pending review of past surveillance practices concerning
containment air lock testing.
c. Conclusions
The licensee exited a 24-hour limiting condition for operation on the
Unit 3 reactor building emergency hatch without fully understanding that
a Technical Specification interpretation did not relieve them of the
surveillance requirements for further testing. This issue was left
unresolved pending review of past practices.
7
01.6 Unit 1 Control Rod 7 of Group 5 Failure to Latch
a. Inspection Scope (71707. 93702, 37551, 92703)
.,On January 19, 1998. while performing a test, control rod 7 in group 5
would not withdraw in group control.
The inspectors were immediately
- notified of the problem and.-followed the licensee's activities. This
rod had a similar problem with operation on December 22, 1997,
(Inspection Report 50-269,270.287/97-16, Section 01.5).
b. Observations and Findings
On January 19, 1998. at approximately midnight, while performing
Procedure PT/0/A/305/01, Reactor Manual Trip Test, Revision 8, control
rod 7 of group 5 would not respond to an out command. During the drop
test done the previous day, the rod had operated normally. The licensee
attempted to move the control rod by repeating activities done in
December 1997, when the rod had exhibited out motion problems.
The
licensee's efforts, which included replacement of the control rod power
cable, failed to restore function. Several days.later, the plant was
drained to a point above reduced inventory conditions (approximately 100
inches in the pressurizer) for re lacement of the control rod drive
(CRD). The inspectors observed the satisfactory drain, manual rod
motion and freedom testing, removal of the CRD. and inspection of the
CRD by the vendor (see Section M1.2). Operations and engineering
provided good overall controls during the rod freedom of motion test.
nable to identify a cause for the rod motion problem, the licensee sent
the mechanism to a .vendor for further testing.
Retest of the new mechanism was satisfactory. The inspectors reviewed
the test times, which were within the expected and TS values. The
licensee subsequently continued preparations for unit startup.
c. Conclusions
The licensee carefully tested and satisfactorily replaced a Unit 1
control rod, which had latching problems. Operations and engineering
provided good overall controls during the rod freedom of motion test.
01.7 Oconee Unit 1 Cold Shutdown for Primary Leak
a. Inspection Scope .(71707,93702,62707)
Following the completion of repairs to the CRD, the licensee discovered
a small leak on the pressurizer surge line drain line. The licensee
immediately notified the residents and NRC headquarters of the problem.
The inspectors followed the recovery activities and repair efforts.
b. Observations and findings
Operations personnel had been warming Unit 1 to hot shutdown conditions.
The plant was at 2100 psig and 500 degrees at midnight on January 26.
1998. Operations had observed an increase in the rate of normal sump
8
pumping. Reactor building leakage was estimated to be approximately 2.0
9pm. At midnight, a non-licensed operator (NLO) was sent into the RB to
investigate the increased leakage. The operator found a weld area crack
on a 90-degree elbow on the one-inch diameter pressurizer surge line
drain that was spraying water vapor. The operator reported this
information to the control room at 12:47 a.m. At 1:00 a.m., the
licensee began a cooldown of the plant. For the observed conditions,
the licensee entered the excessive leakage abnormal procedure and TS 3.1.6.3. At 1:10 a.m., operations notified the senior resident, who
came to the site to review licensee actions. At 1:38 a.m., the licensee
initiated a one-hour non-emergency phone call to the NRC's headquarters
operations officer. The unit completed .a
normal cooldown over the
remainder of the night with all observed parameters remaining within
acceptable limits. The licensee initiated an investigation and an
engineering manager was on site interviewing personnel by 3:00 a.m. At
5:00 a.m., the plant was at 550 psig and 337 degrees F with the licensee
preparing to go on low temperature over pressure protection. The RB
leakage trended down with RCS pressure. Based on personnel safety
risks, the licensee made no further RB entries.
The plant was drained to above reduced inventory level to repair and
investigate the weld problem over the next several days. The crack in
the drain line was about 1/4 of the way around an elbow. This activity
was well planned and supported by the investigative team direction. See
Sections M1.3 and E1.1 for drain piping inspection details and repairs.
c. Conclusions
Operations satisfactorily manipulated Unit 1 to cold shutdown for
repairs and investigation of a 2 gpm leak from a crack on a one-inch
drain line off the pressurizer surge line. Operations made appropriate
notifications and reports.
03
Operations Procedures and Documentation
03.1 Standby Shutdown Facility (SSF) Diesel Generator Operation
a. Inspection Scope (71707, 62707)
The inspectors observed the operation of the SSF diesel generator on
February 6, 1998, during post-maintenance operation to return the SSF
diesel generator back to service following scheduled maintenance.
b. Observations and Findins
During low idle maintenance operation, the licensee identified that
turbo lube oil pressure was low on the A engine. Operations reviewed
Procedure OP/O/A/600/10, Enclosure 4.5 SSF Diesel Generator Auto Idle
Start, Revision 22. and contacted maintenance and engineering personnel
nearby. While troubleshooting the low turbo oil pressure, maintenance
identified that the installed engine revolutions per minute (rpm)
tachometer was reading approximately 30 rpm low on hand-held calibrated
0II
9
tachometers. The engine speed was less than the value stipulated in
applicable operations procedure.
The system engineer identified that the operations procedure specified a
different engine rpm value than the diesel technical manual. The
technical manual stipulated an idle speed of 490 RPM. The operations
procedure stipulated an idle speed of 400 - 450 RPM.. Operations and
system engineering continued to review the differences in the two
procedures.
At the close of the inspection period, NRC review of the technical
manual versus the operations procedure issue was not complete.
Followup of this issue will be under Unresolved Item (URI) 50
269,270,287/97-18-03: SSF Diesel Generator Operation. This issue is
unresolved pending additional NRC review of the maintenance and
operations activities associated with the operation of the SSF diesel
for return to service following maintenance.
c. Conclusions
An apparent lack of agreement between the SSF diesel technical manual
and operations procedures resulted in an URI.
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62707, 61726)
The inspectors observed all or portions of the following maintenance
activities:
Change Out of Reactor Coolant Pump Seal
Injection Filters
OP/3/A/1104/02
Enclosure 3.8. Swapping Seal Supply Filters,
Revision 85C
PT/0/A/0620/09
Keowee Hydro Operation-Control Room Start,
Revision 16
OP/1/A/1102/01
Controlling Procedure for Unit Start Up,
Revision 2 8, Enclosure 4.18, Reactor Building
Tour at Hot Shutdown
PT/1/A/0711/01
Zero Power Physics Testing, Revision 30,
Enclosure 13.7, Approach to Criticality (Group
5, Rod 7 problem on January 22, 5:48 a.m.)
MP/1&2/A/1140/
CRDM Shim Driver Removal and Replacement,
16
Revision 3
10
5001137-00
Babcock and Wilcox Procedure, dated January 20,
1998, Type A Shim CRDM Refurbishment
WO 97094576-1
Inspect Unit 1 Component Cooling Cooler Tubes
Inspect 2A Low Pressure Injection (LPI) Pump
Boric Acid-Covered Casing Bolts
IP/O/A/0305/01B Reactor Protection Systems (RPS) Channel B Pump
Power Monitor Instrument Calibration, Revision
31
IP/O/A/0305/015 RPS Removal From and Return to Service for
Channel ABC.D, Revision 16
PT/O/A/0610/22
Degraded Grid Switch Isolation and Keowee
Overfrequency Functional Test. Revision 9
OP/0/A/1600/10
Enclosure 4.5, SSF Diesel Generator Auto Idle
Start, Revision 22
P/0/A/1810/014
Valves and Piping-Welded-Removal and
Replacement - Class A through F. Revision 26
Troubleshoot and Repair Unit 2 Integrated
Control System
.
PT/0/A/0610/22
Degraded Grid. Switchyard Isolation, and Keowee .
Overfrequency Protection, Revision 8
TT/0/A/2200/16
Keowee Hydro Unit 2 Turbine Guide Bearing Oil
System Test, Revision 1
TT/0/A/0620/34
Keowee Emergency Blackout Start Test, Revision 0
PT/3/A/0600/12
Turbine Driven Emergency Feedwater Pump,
Revision 48
b. Observations and Findings
All work observed was performed with the work package present and in
use. Technicians were experienced and knowledgeable of their assigned
tasks. The inspectors frequently observed supervisors and system
engineers monitoring job progress. Quality control personnel were
present when required by procedure. When applicable, appropriate
radiation control measures were in place.
The inspectors were in the switchyard during the degraded grid test
(PT/0/A/0610/22) observing proper operational configuration controls of
the yard breakers and proper breaker operation. Operations personnel in
the switchyard maintained good communications with the control room
personnel and used good command and control techniques when talking with
the test director.
11
During observations of the boric-acid inspection (WO 98009938) in the 2A
Low Pressure injection (LPI) pump room (63), the inspectors observed
that Teflon tape was being used in several locations on the Unit 2 low
pressure injection (LPI) system. Notably, the tape was used on pump
casi.ng plugs and system instrumentation connection points.
Inspectors
had also observed its use on the Unit 3 LPI system. Following inspector
questions on this observation, the licensee commenced a detailed
inspection observing the use of the Teflon tape in numerous locations on
the systems and documented it in PIP report 2-98-455. The report
indicated that piping specifications did not allow the use of the tape,
but did not render the system inoperable. The tape was to be evaluated
on a case by case basis with followup corrective actions. This finding
was identified as URI 50-269,270,287/97-18-04: Teflon Tape Use on the
LPI System.
c. Conclusions
The inspectors concluded that the maintenance activities listed above
were generally completed thoroughly and professionally. One URI was
initiated for the use of Teflon tape on the LPI system.
M1.2 Control Rod Drive Testing and Inspection
a. Inspection Scope (62707)
As indicated in Section 01.6, Group 5 Rod 7 had failed to latch on
January 19, 1998. The inspectors observed manual testing of the rod in
the core and subsequent disassembly of the removed control rod drive
mechanism.
b. Observations and Findings
The licensee developed a special test procedure to manually test the
freedom of motion of the subject rod. Before test performance, an
evaluation of the procedure was satisfactorily completed and the on-site
review committee reviewed the details of the entire evolution. For test
conditions, the reactor was in cold condition and depressurized with an
adequate shutdown margin available. The licensee performed the freedom
of motion test through the intact CRD housing with conditions very
similar to a normal rod unlatch conditions. The inspectors verified
that the conditions were appropriate for the work. With the inspectors
present on January 22, 1998, the licensee used a chainfall to lift the
rod from the core approximately 12 inches and then return it to its rest
condition. The movement met the acceptance criteria with no rod motion
or reactivity problems identified. The licensee readied and removed the
CRD for examination.
On January 25, 1998, the inspectors observed the disassembly of the
removed mechanism. Vendor representatives were in air fed hoods,
communication headsets, and full body plastic suits for the work. The
inspectors could view the work through windows in the special sealed
plastic tent constructed for the work.
12
The disassembly and inspection process did not identify a definitive
cause for the failure to latch. Corrosion product buildup was found
inside the mechanism, but the vendor described this as normal when
compared with other disassembled mechanisms. A thrust bearing locking
nut was three turns loosened. The locking cup for the nut had not been
sufficiently deformed to lock the nut completely. The licensee
indicated that this by itself was not the problem. The roller bearings
that drive the rod could still be pulled into the lead screw. The rotor
assembly parts that electrically pulled out to allow engagement of the
rollers showed grooves on their outside diameter. Grooves were in the
corrosion product coating. The vendor indicated that this indicated that
the parts were probably reaching their maximum outward movement.
The licensee and vendor removed the subject mechanism to the vendor's
contaminated test facility for further dynamic testing. The overall
inspection work was performed in a satisfactory manner and with care to
detect as-found conditions.
c. Conclusions
The licensee and its primary vendor removed and disassembled a
malfunctioning Unit 1 control rod mechanism, finding no definitive
problem. The overall inspection work was performed in a satisfactory
manner, with care to detect as-found conditions.
M1.3
Pressurizer.Drain-Line Removal and Installation
- a. Inspection Scope (71707. 62707, 37551)
As-indicated in Section 01.7, the drain line from the pressurizer surge
line developed a leak on January 26. 1998. After plant depressurization
and drain to approximately 60 inches on LT-5. the line was removed and
replaced. The inspectors observed the line removal, replacement, and
re-welding.
b. Observations and Findings
After meeting appropriate plant conditions for the work, operations
released WO 98009597-05, to remove the one-inch diameter line. The line
consisted of the pressurizer surge line to drain line nozzle joint, a
short vertical run, four elbows and three short pieces of pipe arranged
in "C"
configuration, and then a straight, vertical twenty-foot run of
pipe to the equipment drain header near the basement level.
The piping
was per plan with five "U" bolt hangers on the twenty-foot run.
The
inspectors verified the plant was in stable condition for work
performance and appropriate clearances had been set.
At the first pipe
cut at the surge line drain line nozzle, no water was observed (only
dripping). The pipe end moved 1.75 inches down and 1.25 inches toward
the reactor vessel when cut. The motion was in a plane created by the
four elbows in the expansion segment of the drain line. This freed
motion indicated that the piping was under some residual stress that had
placed a preload on the piping. Analysis of the piping arrangement is
discussed in Section El.1. The supporting health physics and
13
maintenance personnel worked well together, taking adequate precautions
to make the work progress smoothly, maintaining adequate radiological
controls, and practicing good foreign material control.
The inspectors observed portions of the prefabrication of the
replacement piping in the machine shop and the class one welds made in
the RB. The work went well with good foreign material practices being
observed. Upon radiographic inspection of the prefabrication work, two
of seven butt weld joints were found to have inadequate fusion; and
therefore requiring rework. This use of prefabrication was an
acceptable methodology and practice.
The RB work was well controlled
with proper use of purge gases. Weld interpass temperatures were
appropriately monitored. The licensee stated that the radiographs were
acceptable on all completed and Duke Quality Assurance accepted welds.
While welding one of the joints, purge paper was used to plug the surge
line connection and keep condensate from the weld area. An excessive
amount of this dissolvable paper was used and it did not dissolve after
the welds were completed requiring further repairs. This is-further
discussed in Inspection Report 50-269,270,287/98-01.
c. Conclusions
During the pressurizer surge line drain line work, pipe removal and
reinstallation practices and controls were generally acceptable. Health
physics personnel appropriately supported the maintenance activities.
One rework item was observed that is discussed as a violation in
Inspection Report 50-269.270.287/98-01.
M1.4 Unit 1A Once Through Steam Generator (OTSG) Primary-to-Secondary Leakage
a. Inspection Scope (50002)
The inspectors reviewed the circumstances of, and the corrective action
for, the primary-to-secondary OTSG leakage that led to the December 28,
1997, shutdown of Unit 1.
b. Observations and Findings
On December 28, 1997, during start-up from a refueling outage, Oconee
Unit 1 was required to shut down due to primary-to-secondary leakage.
Plant chemistry personnel measured the leakage to be greater than 400
gpd from the 1A OTSG. When the 1A OTSG was opened for inspection, leak
testing showed that the primary source of leakage was at the interface
between the upper (hot leg) tubesheet and the OTSG tubes. Minor leakage
was also found at a remote welded plug location on the lower (cold leg)
tubesheet.
The configuration of the connections between the OTSG tubes and the
upper tubesheet is unique in the Oconee 1A OTSG. This uniqueness is the
result of field repairs to the upper tubesheet after foreign material
during hot functional testing damaged it in 1972. In the standard
connection between OTSG tubes and the upper tubesheet of a Babcock and
14
Wilcox (B&W) OTSG, the tubes protruded approximately 3/s to 112 inches
beyond the top of the tubesheet: the tubes were partially rolled in
the
tubesheet to provide the mechanical connection; and fillet welds
connected the outside of the tubes with the tubesheet to provide the
seals. The untubed lane of tubesheet holes was plugged with button
plugs that were fillet welded into place. In the Oconee 1A OTSG, the
tubesheet and tube connections were repaired by machining the damaged
tube ends flush with the top of the tubesheet; re-rolling the top of the
tube in the tubesheet: and seal welding over the seam between the tube
and the tubesheet to repair the hot functional damage. Encapsulating
the plugs with a weld overlay repaired the row of button plugs in the
untubed lane.
After the December 28, 1997, shutdown, initial test results in the 1A
OTSG indicated that there were eleven leak locations and three different
types of leaks. After the first repair attempts, subsequent test
results identified eight leaking locations; seven of these locations had
not been previously identified, and one of these provided a fourth type
of leak.
Leakage from Button Plug Locations Adjacent to Tube Location 77-7
A section of the weld overlay encapsulating the button plug row,
adjacent to tube location 77-7, had been machined away: this machined
area appeared to be the major source of leakage. Tube location 77-7 had
been plugged during the Spring 1994 refueling outage, and itwas during
this evolution that the section of weld overlay was machined away. B&W
nonconformance reports 94-00271 and 94-00271-01 reported a sequence of
-events in which attempts to install a remote welded plug at location 77
7 were unsuccessful, due to interference from the adjacent weld overlay.
At the time that a portion of the weld overlay was removed, the new
configuration was left as-modified, with the understanding that the
machining should not have encroached on the original button plug weld.
The leaking area of the weld overlay was manually repair welded and
successfully leak-tested. A full examination of the weld overlay area
showed that the area adjacent to location 77-7 was the only location
where metal had been removed to install an adjacent plug.
Remote Welded Plug (RWP) leaks
The RWP at location 87-61 in the lower tubesheet of OTSG 1A and the RWP
at location 97-92 in the upper tubesheet of OTSG 1B had been installed
during the past refueling outage (RFO 1EOC-17) as a result of tubes
being pulled for inspection. (RWPs in OTSG B were examined after a
review of records showed that 7 of 28 RWPs installed in OTSG B during
the past outage had experienced rejects during welding.)
Both of these
RWPs had experienced two rejects prior to final weld acceptance.
The two leaking RWPs were manually weld-repaired and successfully leak
tested. The licensee's review of RWP records from the last outage
showed that 2 of 23 RWPs in OTSG A, and 7 of 28 RWPs in OTSG B had
experienced weld rejects during installation. This reject rate of 25
15
percent in OTSG B, and 17 percent overall appears to be rather high for
a remote welding process.
The licensee's corrective actions for this problem included leak testing
of future RWPs and requiring the contractor to review the welding
process to determine if enhancements could be made to reduce the reject
rate.
Tube Seal Weld Leaks
Nine locations on the OTSG 1A upper tubesheet were found to be leaking
during bubble testing after shutdown; these locations were 40-1, 145-1,
144-1, 140-1, 139-1, 137-2, 136-6,75-126, and 12-71. After re-rolling
these tubes in the tubesheet, (using a recently qualified re-rolling
technique) one of the original locations, 136-6, and eight additional
locations, (116-2, 148-41, 147-46, 144-2, 146-51,81-124, 116-1, and
144-56) were found to be leaking. All of the seal-weld, leak locations
were at, or near, the periphery of the tubesheet.
The apparent root cause of the s'eal weld leakage was postulated to be a
stress corrosion cracking (SCC) phenomena brought on by the machining of
the tubesheet surface during the repairs in 1972. A licensee requested
review of the accident analyses for the Oconee OTSGs showed that during
a main steam line break (MSLB), flexure of the tubesheet is postulated
to cause dilation of the peripheral holes near the surface of the
tubesheet, thereby transferring the axial MSLB loads from the rolled
joint to the seal welds, which have been shown to be susceptible to SCC.
(The MSLB analyses for the Oconee units predicted.much higher axial .
loads on the upper tubesheet than did the MSLB analyses for other B&W
once through steam generators. The absence of main steam isolation
valves in the Oconee design apparently contributed to these higher
loads.)
The licensee had recently qualified a re-rolling process (due to
indications in the upper tubesheet roll transition area) which places a
new rolled joint about three inches below the top of the tubesheet. The
MSLB accident analysis showed that the new location would not be
significantly affected by the postulated MSLB hole dilation.
To correct this potential problem, the licensee re-rolled greater than
1700 peripheral tubes in the upper tubesheet of OTSG 1A. The final
acceptance of the re-rolled tubes included eddy current testing and leak
testing. After the completion of testing, forty tubes were removed from
service by plugging: two tubes, (75-126, and 144-1) were due to seal
weld.leakage after re-roll: six tubes, (3-32, 3-34, 44-1,84-131, 136-6,
and 150-6) were due to unacceptable eddy current indications at or below
the re-rolled area; and thirty-two tubes, (1-12, 5-3, 5-44, 8-56, 20-84,
22-1, 23-7, 25-1,36-113, 37-1. 42-1,53-126, 60-129,65-130, 67-130,74-125, 83-132,85-130, 87-130,88-129, 102-123, 130-93, 137-1, 138-75,
139-73, 143-60, 147-44, 147-46, 148-38, 148-41, 149-32, and 151-10) were
because the.configuration of the re-rolled area did not meet acceptance
standards.-
16
Manual Welded Plug Leak
After conletion of the repairs.to the weld overlay area adjacent to
location 77-7, subsequent leak testing showed a pinhole leak in the
manual weld of location 75-8. This tube location was extremely close to
the leaks in the weld overlay, and therefore this leakage was masked
during the initial leak testing of the OTSG.
The weld pinhole, at location 75-8, was manually weld-repaired and
successfully leak tested. The licensee is considering the addition of
leak testing to the acceptance criteria for future manual welds.
The inspectors reviewed the licensee's root cause process and report,
and observed OTSG inspection and recovery activities. Activities
observed included visual inspections, leak-testing, re-rolling, and eddy
current inspections. Based on the reviews of video tapes of the tube
sheet inspections, reviews of 1974 and 1977 documentation, and
observation of recovery activities, the inspectors agreed with the root
cause(s) and corrective action conclusions reached by the licensee's
investigation team. In particular, the inspectors agreed with the
conclusions that pointed to an apparent over-reliance on visual
inspections for acceptance of welds, and the 'need for leak testing of
future OTSG work. The inspectors concluded th*at past corrective actions
had not adequately considered the role of primary water stress corrosion
cracking. (It
was not a viable consideration during the tubesheet
repairs in 1972, and the weld overlay modification in 1994.)
The long term corrective..actions recommended by-the licensee's
investigation team charged the licensee's OTSG Maintenance Group with
ensuring that the contractor's welding and inspection procedures and
acceptance criteria were modified to preclude recurrence. The
inspectors agreed that the licensee's responsible organization, the OTSG
Maintenance Group, should adopt a more questioning attitude toward the
contractor's procedures and criteria.
c. Conclusions
The December 28, 1997, Unit 1 shutdown for primary-to-secondary leakage
was the result of past repairs, where there had been an apparent over
reliance on the results of visual inspections, and less than adequate
appreciation for primary water stress corrosion cracking.
M3
Maintenance Procedures and Documentation
M3.1 Unexpected Effect of Letdown Flow Calibration on Unit 3 Thermal Power
Best
a. Inspection Scope (62707)
The inspectors reviewed the maintenance aspects of an unexpected power
increase on Unit 3. The details of what happened and the operational
aspects of the power increase have been included in Section 01.4.
17
b. Observations and Findings
On January 15, 1998, maintenance personnel were calibrating letdown flow
instrumentation in accordance with Procedure IP/0/B/0202/01h, High
Pressure Injection System Letdown Flow Instrument Calibration, Revision
16, when core thermal power began to increase. The licensee
- investigated and determined the cause of the power increase was the
effect that chan ing letdown flow signal had on the ICS. The licensee
determined that letdown flow was an input into the secondary thermal
power calculation performed by the operator aid computer (OAC). This
thermal power calculation was used by the ICS as a feedback signal for.
core thermal power.
The licensee suspended the calibration, placed Procedure IP/0/B/0202/01h
on administrative hold, and initiated PIP report 3-098-0232. The
licensee began a review of procedures affected by the OAC core thermal
power calculation and subsequently determined that Procedure
P/0/B/0202/01h had not been identified as affecting the core thermal
power calculation or the ICS when ICS was returned to service after
modification on March 27, 1998.
The inspectors reviewed applicable site documents to understand the
modification interaction process. Documents reviewed were as follows:
Procedure IP/0/B/0202/01h; Problem Report 3-098-0232; Modification ON
32989, 3EOC16-ICS Replacement, Revision 0; and Nuclear Station Directive
(NSD) 301, Nuclear Station Modifications (NSM), Revision 13.
Additionally, the inspectors interviewed-licensee personnel on how
procedures affected by plant modifications are identified and changed.
NSD 301, Section 301.3.1.11, stated that the superintendent of
maintenance was responsible for -identifying and developing any
instrumentation procedure revisions required as a result of modification
work. NSD 301, Sections 301.5.4.4 and 301.6.3.7, stated that prior to
acceptance of a modification by operations, all procedure revisions
would be completed. With the modification of the ICS, neither procedure
IP/0/B/0202/01h nor modification ON-32989 addressed or made any mention
of an impact on ICS by letdown.flow calibration. The inspectors also
identified that the maintenance department lacked a section level
procedure governing the process for identification and revision of
procedures affected by modifications.
TS.6.4.1.e requires the station to be maintained in accordance with
approved procedures for maintenance of equipment which could affect
nuclear safety. The failure to revise Procedure IP/0/B/0202/01h to
include effects of modifications to the ICS is a violation (VIO) of this
TS and is identified as VIO 50-269,270,287/97-18-05: Failure to Revise
Procedure Following ICS Modification.
c. Conclusions
The inspectors identified a violation for failure to revise a high
pressure injection system letdown flow instrument calibration procedure
following modification of the Unit 3 ICS.
18
M3.2 Oconee 600 Volt K-line Breakers
a. Inspection Scope (62707)
On February 2. 1998, the SSF was removed from service for maintenance.
Included in the maintenance was testing and inspection of six Asea Brown
Boveri (ABB) K-line 600 Volt load center OXSF breakers. During the
testing, problems were discovered. The inspectors observed portions of
the repair and retesting.
b. Observations and Findings
During the SSF maintenance, the licensee discovered some breaker
lubrication and breaker trip time delay problems. These problems were
promptly brought forward for management attention and problem reports 4
98-515 and 516 were initiated. One breaker had sufficient hardening of
its grease such that it may not have reclosed completely if it had
tripped. These breakers have no automatic re-latching capability. The
remaining five breakers had operated satisfactorily during as-found
testing, but upon inspection, they did exhibit signs of grease hardening
that required work. All six breakers were satisfactorily disassembled,
greased, and retested. In addition, the over-current trip devices
(identified as SS4G) for three of the breakers were found out-of
tolerance (under.time by 2 to 8 seconds) for the long time delay minimum
acceptance criteria. These devices were replaced with new ones. The
licensee was evaluating the impact of the out-of-tolerance condition on
past operability and determining root cause of the problem. Inspector
review of breaker coordination revealed that there appeared to be no
safety-problem.
There are approximately thirty-seven other safety-related K-line
breakers on-site. There are eleven per unit with four common to all
units. These .breakers are normally closed and contain no under voltage
trip circuits. They are supplied from three redundant power trains,
each of which are supplied independently from one of the three 4160 volt
switchgear, as described in the UFSAR. The breakers only function would
be to trip if a safety device were to fail.
If one of the 600 volt
breakers failed to trip, its 4160 volt supply breaker would open. The
failure of one train of 600 volt safety power is an evaluated condition
during a design basis event.
The licensee was to evaluate the following:
- -
grease hardening impact on a preventive maintenance schedule
trip device impact on SSF K-line breaker preventive maintenance
and
past operability evaluation on SSF trip device supplied breakers
Pending resolution of this issue, this is identified as Inspector
Followup Item (IFI) 50-269,270.287/97-18-06: K-line Breaker Issues.
19
c. Conclusion
During the inspection and testing of the SSF 600 volt breakers, several
problems were identified by the licensee. The licensee satisfactorily
addressed the immediate equipment problems. There were several issues
regarding grease hardening and trip device past operability. An IFI was
initiated on those issues.
III. Engineering
El
Conduct of Engineering
E1.1 Steam Leak in Unit 1 Pressurizer Surge Line (PSL) Drain Line
a. Inspection Scope (55050)
The inspectors determined by observation of completed welds and document
review, the adequacy of replacing the drain line on the PSL. The
governing code was the American Society of Mechanical Engineers (ASME),
Section XI, 1989 Edition with no Addenda, and the American National
Standards Institute (ANSI) B31.7. 1968 Edition. The drain line was
identified as Duke Class A piping. The leak occurred near the PSL and
could not be isolated. The replacement was performed under Work Order
98009597-5.
b. Observation and Findinqs
On February 2, 1998, the inspector visited.Oconee Unit 1 to inspect
repairs to the PSL drain line steam leak attributed to a crack near a 90
degree elbow weld on the expansion loop of the drain line. The leak was
discovered on January 27. 1998. Through discussion w.ith technical
personnel and document review, the inspectors learned that on the
morning of January 27. 1998, Oconee Unit 1 was heating up and
pressurizing the RCS to the hot shutdown condition. During this time,
operation personnel identified a leak in the RCS, which they
subsequently verified as a steam leak in the PSL drain line. The leak
was found at an elbow weld on the expansion loop of the drain line. The
drain line was bounded by the PSL and valve 1RC-18 near the equipment
drain line header, at the basement floor level. It was determined that
the leak rate was 1.7 gallons per minute.
Following plant cooldown and
cold shutdown, the licensee removed the failed section of the line with
a cut at the outlet of the PSL drain line nozzle and another just below
the expansion loop. The welds on the drain line section were liquid
penetrant inspected. There were no additional cracks found. Selected
samples of straight piping and elbows were sent to the Lynchburg
Technology Center for a metallurgical investigation. A review of the
metallurgical investigation report disclosed that the failure resulted
from stress corrosion cracking, which originated on the intrados of the
third 90-degree elbow from the PSL drain line nozzle. The aggressive
material associated with this type of failure mechanism was chlorides.
The licensee believes that these chlorides came from combustion of
material containing polyvinyl chlorides during a 1973 fire in the
reactor building 1A cavity. PIP report 1-098-0357 was issued to
0II
20
document this event and the metallurgical investigation that was
performed to determine the apparent root cause of the failure.
Replacement Piping, Installation and Testing
At the time of this inspection on February 2, 1998, the replacement
drain line had been installed. The -inspector inspected the new welds,
reviewed the weld packages and the associated radiographs, all of which
were found to be satisfactory.
During plant heat up, the licensee determined that there was no flow in
the drain line. An investigation determined that a plug, which was made
from purge paper and used to prevent water from dripping on the drain
line welds during fabrication, was lodged in the pipe and would not
dissolve as expected. For more details on this matter see Inspection
Report 50-269,270,287/98-01. Following an evaluation of the potential
impact that the paper material could have on the RCS, the licensee
decided to cut the line, remove the plug by mechanical means, re-weld
the line and fill up the system for testing. By review of the above
mentioned PIP report, the inspector ascertained that the failure
investigation process team had identified an engineering or design error
in the stress analysis calculation (OSC 4349) of the drain line system.
A description of the error was documented in PIP report 1-098-465.
Error in Stress Analysis Calculations
A review of PIP .report 1-098-465 disclosed that from the time Unit 1
commenced operation, until approximately September 19. 1981, support
S/R59-0-478A-H9 was on the drain line near the PSL drain line nozzle.
The support was removed per NRC Bulletin 79-14 reanalysis request.
Monitoring of the PSL movement in response to IEB 88-11, disclosed that
the PSL was susceptible to thermal stratification that resulted in
greater movement than originally addressed. In 1991, the licensee
reanalyzed the PSL. However, the present review revealed that the re
analysis addressed only stresses from the configuration without support
S/R 59-0-478A-H9. The licensee's subsequent analysis of stress
conditions prior to the removal of S/R59-0-478A-H9 indicated that
certain locations on the drain line and the drain line nozzle were
significantly over stressed. This over stressed condition was
identified as an indicator of cycling the stress range beyond twice the
yield point, which appears to have been mostly responsible for the
initiation of the crack. However, in reference to the drain line, the
licensee determined that the stress overload condition had been
rectified by the removal of S/R 59-0-478A-H9 and the removal of the
original drain line. The drain line was replaced from the drain nozzle
down to a location on the vertical run below the expansion loop.
Oualification of Drain Line Nozzle for Continued Operation
In addition to this analysis, the licensee performed a calculation to
evaluate the flaw tolerance of the PSL drain line nozzle. A review of
the results disclosed that the subject nozzle was capable of performing
its required function for all design loading for one fuel cycle. During
- .
21
this time frame the licensee will re-evaluate the problem and determine
the appropriate corrective action to be taken to bring the drain nozzle
into compliance with the applicable code requirements. On February 2,
1998, the licensee discussed this matter with the staff at Nuclear
Reactor Regulation (NRR),.who agreed with the licensee's methodology.
No operability issues on this matter were identified during this call.
The licensee plans to continue power operation for one fuel cycle, which
provides sufficient time to decide the appropriate actions that will be
taken to return the PSL drain line nozzle into compliance with
applicable code and UFSAR requirements. This matter was identified as
an inspector followup item to allow for a review and verification that
the subject nozzle had been returned to compliance with code
requirements and FSAR commitments, IFI 50-269/97-18-07:
Pressurizer
Surge Line Drain Line Nozzle Loads Exceed Stress Analysis Limits.
c. Conclusion:
Replacement of the cracked one-inch drain line on the pressurizer surge
line was consistent with applicable code requirements. A lack of
attention to details in the planning phase of welding the replacement
line caused a significant job delay and the need to cut and re-weld a
new weld on the line. Engineering provided adequate support and took an
active role in determining the root cause of the crack. Welding.
nondestructive examination, and process control activities were
satisfactory. Stress analysis calculations determined that thermal
stratification and hanger loads on the drain line, exceeded code.
allowable usage factor requirements, on the drain line nozzle.
E2
Engineering Support of Facilities and'Equipment
E2.1 Unit 2 Integrated Control System Neutron Error Spikes
a. Inspection Scope (62707, 92903)
The inspectors observed, between January 6 and 7, 1998, troubleshooting
activities, engineering support, operator actions, and prejob briefings
relating to the Unit 2 ICS neutron error spikes.
b. Observations and Findings
The ICS neutron error spikes were occurring randomly and were causing
unwarranted control rod movements. The problem was captured in PIP
2-97-4615. Engineering had begun power monitoring of the ICS and had
narrowed down the problem to several components. Prior to the
troubleshooting activities the average temperature module started a
decreasing trend. This resulted in minor rod movements.
Among the specific items observed by the inspector were: the replacement
of two relays associated with the average temperature; tracing of the
power lead which was to be lifted inside ICS cabinet number 6 for
various modules associated with the neutron error signal; the
replacement of a potentially degraded connector plug for a module in the
ICS; and the prejob briefings for the replacement of the relays and the
22
connector plug. The inspector had not observed the hand-over-hand
tracing of the neutral line that was to be lifted for the repair work.
Engineering and instrumentation personnel had written a trou leshooting
procedure for the work.
On January 7, 1998, the inspectors observed that during the prejob
briefing for the replacement of the connector plug, the engineer
informed the operators that the activity would have minimal impact on
the unit. The lifting of the black power lead on the connector plug per
the troubleshooting procedure, would result in the loss of startup feed
water flow indications that were not needed at full power. When
maintenance personnel lifted the white neutral wire, several events,
both expected and unexpected occurred. Expected changes such as the 2A
and 2B startup feedwater flow indication being lost occurred. The
following items that were unexpected also occurred: the 2A and 2B main
feedwater flow indication was lost: the smart analog signal select
(SASS) system detected a loss of main feedwater indications on the A and
B loops and selected a good indication; and the 2A and 2B main feedwater
pump controllers shifted from the automatic mode to the manual mode of
operation. In this condition, the unit controls would not have
responded to a feedwater pump automatic runback. Correct SASS system
operation prevented a plant trip. The encountered problems were
documented in PIP report 2-98-44.
The shift operations manager directed the engineer and the technicians
to stop work, to review the activity, and to determine the extent of the
loss of ICS modules and relays. The review:indicated that the white
neutral wire was attached.to modules and relays in ICS cabinets other
than those originally identified. The procedure manipulation affected
these other components. Subsequently the licensee personnel involved
found all other neutral wire connected components. The other components
not previously identified were visually difficult to see. After
satisfying operations of the completeness of their more recent tracing
and completion of procedure changes, the repair work was completed
successfully.
During the initial work on January 7, 1998, maintenance had not
adequately traced the white neutral lead. This error had been
introduced into the licensee's troubleshooting procedure. 10 CFR 50,
Appendix B, Criteria V. Instructions, Procedures, and Drawings, '
conformed to by the licensee's quality assurance program, requires that
activities affecting quality shall be prescribed by documented
instructions, procedures, and drawings of a type appropriate to the
circumstances and shall be accomplished in accordance with these
instructions, procedures, and drawings. NSD 703, Administrative
Instructions for Station Procedures, Revision 17, Section 703.5,
Preparation of Procedures, states, in part, that procedures shall be
written to minimize risk to equipment and should, when appropriate,
instruct persons performing the procedure what responses to expect from
their actions. Further, as required by the NSD, the licensee had not
validated the procedure to ensure usability and operational correctness.
The troubleshooting procedure written for the repair (WO 98000451)
failed to meet these requirements.. This failure is identified as an.
(II
23
example of VIO 50-269,270,287/97-18-08: Failure to Establish and
Implement Procedures - Three Examples.
c. Conclusions
The inspectors identified the first of three examples of a violation
involving procedural inadequacies. (The other two examples are
discussed in Section E2.2.)
An engineering supported troubleshooting
procedure did not minimize risk to equipment and was not completely
validated prior to performing work. Use of the procedure on Unit 2 ICS
wiring resulted in unexpected system.responses.
E2.2 Keowee Testing. Failure to Start, and In-Service Testing
a. Inspection Scope (37551, 92903)
The inspectors observed and reviewed engineering support for testing
involving the Keowee Hydroelectric Plant (KHP). The inspectors
responded to the KHP for observations and reviews of engineering support
when: on January 9. 1998. the Unit 2 generator failed to start in the
normal mode; on January 14, 1998, voltage adjust did not run to preset
as expected during testing: and, on January 20, 1998, both of the KHP
units were out of service due to a missed in-service test.
b. Observations and Findinqs
On January 9: 1998, the KHP operations personnel started the KHP Unit 1
generator, which successfully paralleled automatically to the grid as
expected. When the Unit 2 KHP generator was started, it came up to
rated speed, received a UNIT 2 INCOMPLETE.START alarm, and tripped. The
KHP units were being started to.control Keowee Lake level.
The inspectors observed and reviewed activities involved with
engineering support, troubleshooting- information gathering for root
cause, prejob briefings for the various work activities, and the
adjustment of the motor operated automatic voltage regulator. The
troubleshooting identified an open coil in a time delay relay (Agastat
90X1A/TD).that prevented the regulator from shifting to automatic
control. With the regulator not shifting to automatic, the unit
received the incomplete start alarm and tripped.- The licensee replaced
the relay, tested the unit, and returned it to operable status.
The inspectors observed, during the troubleshooting, that the regulator
was not adjusted in accordance with drawing KEE-212-5, Elementary
Diagram Excitation System Motor Operated Auto Voltage Adjuster, Revision
8, a Quality Assurance (QA) Condition 1 drawing. The inspectors found
that Procedure IP/0/A/2005/003, Keowee Hydro Station Westinghouse WTA
Voltage Regulator Test, Revision 23, did not contain adequate detail to
properly set up the voltage adjuster. The procedure did not address the
unused timing cams in the adjuster that, if unaccounted for, could cause
operational problems.
(The unaccounted for cams had not caused
operational problems at discovery.)
Following the Unit 2 adjustment,.
the Unit 1 regulator was checked and was also not in accordance with the
24
applicable drawing. Subsequently, the licensee properly adjusted both
cams. During the work, the operational status of the Keowee units was
properly addressed. These voltage adjusters had been previously worked
by the above procedure.
10 CFR 50 Appendix B, Criteria V. Instructions, Procedures, and
Drawings, conformed to by the licensee's QA program, requires that
activities affecting quality shall be prescribed by documented
instructions, procedures, and drawings of type appropriate to the
circumstances and shall be accomplished in accordance with these
instructions, procedures, and drawings. The failure to have a detailed,
adequate procedure for adjusting the motor operated regulator in
accordance with drawing KEE-212-5, Revision 8, is a violation of these
requirements. NSD 703, Administrative Instructions for Station
Procedures, Revision 17, Section 703.5, Preparation of Procedures,
Subsection 4, subsection requirements stated, in part, that procedures
shall be written in adequate detail to ensure accurate results. This
item is identified as an example of VIO 50-269,270,287/97-18-08: Failure
to Establish and Implement Procedures - Three Examples. The licensee
initiated a failure investigation team and problem report K-98-106.
On January 14, 1998, during the performance of test PT/O/A/0610/22,
Degraded Grid, Switchyard Isolation, and Keowee Over Frequency
Protection, Revision 8, the KHP Unit 2 did not return to the preset
automatic generator voltage level as required. With support from
engineering, a defective Cutler-Hammer Type D87 timer relay was
discovered. The.timer fai.led to allow enough-time for the motor
operated automatic voltage adjuster to run the voltage back to the
preset level. The licensee replaced the timer relay and the test was
successfully completed. The inspectors found that type D87 timer relays
had failed on a previous occasion. The licensee initiated a second
failure investigation and PIP report K-98-211. The licensee has sent
both of the failed relays to vendors for evaluation. Pending additional
inspector review of the licensee's efforts in this area, this is
identified as IFI 50-269,270,287/97-18-09: Review of the Root Cause
Analysis for Agastat Time Delay and Type D87 Timer Relays.
On January 20, 1998, during a quarterly surveillance and maintenance
outage for KHP Unit 2, it was discovered that an in-service test (IST)
had not been performed when required on both KHP units. Both units were
declared inoperable and the appropriate TS and selected licensee
commitment was entered. The inspectors found that a temporary IST
Procedure TT/0/A/0620/16, KHU-1 Turbine Guide Bearing Oil System Test,
Revision 1, was not converted to a performance test (PT).
This resulted
in an IST of check valves in the oil system for Keowee Unit 1 not being
performed within the required time frame. The required ISTs were
performed using the temporary procedure and both KHP units were declared
NSD 300. ASME Section XI Program, Revision 2. states, in part, that the
nuclear site engineering organization is responsible for interfacing
with the station organization to prepare written test procedures. Not
0II
25
converting the temporary procedure to a PT is a violation of this.
requirement. This item is identified as an example of VIO 50
269,270,287/97-18-08:
Failure to Establish and Implement Procedures
Three Examples.
At the end of the report period, licensee personnel had completed a
review of temporary procedures for conversion to permanent procedures
with no discrepancies identified. The licensee was also conducting root
cause determinations for the open coil on the time delay relay and the
failed timer.
c. Conclusions
Two additional examples of a three-example violation involving procedure
inadequacies were identified. Section E2.1 discusses the first example
of the violation. The two additional examples occurred on the Keowee
Hydroelectric units. One example involved the motor operated automatic
voltage adjusters on both Keowee units not being adjusted in accordance
with their applicable drawings due to a lack of procedural detail.
The
other example involved missed ISTs on both Keowee Hydroelectric units
due to a failure by engineering to convert a temporary test into a
periodic test on lube oil valves.
E8
Miscellaneous Engineering Issues (92903.92700)
E8.1 <(Discussed) LER 50-269/97-10: Inadequate.Analysis of.Emergency Core
Cooling System (ECCS) Sump.Inventory Due to Inadequate.Design Analysis.
This event was discussed in Inspection Report 50-269,2701287/97-16. The
inspectors reviewed the completed evaluation in the LER. During the
flow velocity evaluation, the licensee identified that the refueling
canal drains contained basket type strainers which could become clogged
and trap approximately forty thousand gallons of ECCS and reactor
coolant system line break fluid.
The reactor cavity drain had a flange installed with an open 3/4-inch
pipe nipple that could also become blocked and trap approximately sixty
thousand gallons of fluid. UFSAR section 3.8.3.1. "Description of the
Internal Structures," states that the reactor cavity was designed
structurally to contain core flooding water up to the level of the
reactor nozzles. Framatome Technology Incorporated was contacted by
engineering and confirmed that this was an original design issue that
was later determined to be unnecessary. The flange on Unit 3 was
removed at some unknown time.
The strainers in the fuel transfer canal drains were installed
approximately ten years ago during a refueling outage to maintain dose
rates during decontamination As Low As Reasonably Achievable (ALARA).
Individuals interviewed remembered this to be with verbal concurrence
from engineering to remove them prior to operation and reinstall the
approved perforated strainer plate. The original strainer plates were
never reinstalled.
26
The system engineering evaluation concluded on January 8, 1998, that the
increase in transport velocity did not affect the operability of the
reactor building emergency sump. Therefore the sump was determined to
be both past and present operable.
Neither the removal of the flange nor the installation of the strainers
was evaluated as a modification to the plant through the station
modification process. NSD 301, NSM, Revision 12, Section 301.1.1,
indicates that it applies to all structures, systems, and components
located within the nuclear facility. Section 301.2 further indicates
that changes to these structures, systems, and components are considered
modifications and require implementation packages. The licensee has
subsequently evaluated the removed Unit 3 flange, removed the flanges on
the other two units, and, as indicated above, removed the strainers.
This non-repetitive, licensee identified and corrected violation is
being treated as a NCV consistent with Section VII.B.1 of the NRC
Enforcement Policy. This is identified as NCV 50-269.270.287/97-18-10:
Failure to Follow Modification Procedures. This LER will remain open
ending review of additional issues concerning the Borated Water Storage
ank level and the RB emergency sump level identified at the end of the
report period.
E8.2 (Open) Inspector FollowUp Item 50-269.270.287/96-13-03: Service Water
System Modifications and Testing.
The service water system operational performance inspection (SWSOPI) had
identified several issues with respect to the design and operation of
the low pressure service watersystem. (LPSW)
and the emergency condenser
circulating water (ECCW) systems. These issues included the cooling and
-sealing supply to the condenser circulating water (CCW) pumps and
motors, maintaining the CCW conduits full of water during siphon
operation, the net positive suction head (NPSH) requirements for the
LPSW pumps, and the quality condition of certain structures, systems and
components (SSC) required to maintain the siphon. The licensee had
committed, in a letter dated December 28, 1995, to perform certain
modifications to upgrade the ECCW system. These modifications included
providing an LPSW supply to the CCW pumps and motors, changes to the
PSW system to ensure adequate NPSH. installing an emergency siphon
vacuum system, and upgrading and reclassifying portions of the CCW
system to QA-1. The five major modifications have been broken down into
approximately eighty implementation parts and minor modifications.
The inspectors reviewed the licensee's progress in implementing these
modifications. The following implementation parts have been completed:
LPSW minimum flow recirculation piping has been installed on all three
units; trenches have been installed from the radioactive waste trench to
the intake dike and essential siphon vacuum (ESV) building: the
emergency safeguards signal for LPSW 4 and 5 has been removed from Units
1 and 2: new LPSW pump impellers have been installed in Units l and 2;
Unit 1 CCW pump discharge valve control circuitry has.been upgraded and
the new isolation valves for the non-essential turbine building LPSW
loads have been installed and related control switches moved to the
control rooms.
27
The inspectors reviewed work in progress, which included completion of
the ESV building and installation of the ESV pumrs, tanks, valves,
power, and instrumentation; installation of the PSW headers from Unit
1, 2 and 3 in the turbine building; and installation of the LPSW and ESV
piping in the trench to the intake dike.
The inspectors discussed the licensee's LPSW implementation plans for
the Unit 2 outage, currently planned for March 1998. The implementation
parts to be completed during the March outage as currently planned will
complete the LPSW modifications on Unit 2. Testing of the ECCW siphon
will be conducted on Unit 2 following completion of the modifications.
The licensee's current plans are to complete Unit 3 modifications during
the fall 1998 outage and the remaining Unit 1 modifications during the
spring 1999 outage.
The inspectors concluded that the licensee had made good progress in the
installation of the modifications considering the intervening events
(feedwater heater line rupture and rework on the balance of plant
systems) and the size of the LPSW modifications.
This item will remain open pending the completion of the modifications
on all three units and completion of post modification testing.
IV.
Plant Support Areas
P8
Miscel aneous. EP Issues (92904)
. P8.1 Severe Accident Management Guideline (SAMG) Training
Severe accident mitigation guidelines were written to identify options
available when plant conditions place the operators outside the current
emergency operating procedures. The inspectors reviewed training
materials and observed actual SAMG training provided to plant personnel.
There were 442 employees that received introductory training on the
existence and basis for the SAMGs: 171 of which continued training for
the assessment and mitigation strategies. These employees were from
shift operations, nuclear engineering, and technical support center
personnel. One hundred and seventeen then completed self-paced
computer-based training on the science of severe accidents. The licensee
also conducted table top drills for 131 of the original 442 employees.
The training was completed on December 19, 1997, and the licensee posted
a letter to the NRC describing the training. The inspectors attended
parts of the training, finding the training and guidelines to be .of
sufficient detail for the intended purpose.
P8.2 Meeting With Local Emergency Preparedness Officials
The resident inspectors met with local officials following the
completion' of the Systematic Assessment of Licensee Performance (SALP)
meeting on January 8, 1998. The purpose of the meeting was to introduce
the new inspectors to the officials and to allow discussion of any
concerns the officials may have. No concerns were identified by local
officials.
28
F1
Control of Fire Protection Activities
F1.1 Transformer Fire Watches
a. Inspection Scope (71750)
On January 17, 1998,.the licensee determined that they had not
established appropriate fire watches during the out-of-service periods
for two transformers. The inspectors followed the licensee's activities
and corrective actions.
b. Observations and Findings
On January 17, 1998, at approximately 2:00 p.m., the operations staff
determined that they had not implemented fire watches in accordance with
a site instruction. Operations generated problem report 98-0255 and
notified the inspectors. Operations personnel had taken the deluge fire
protection and detection systems out-of-service for the startup
transformers on Units 2 and 3. They had accomplished the preventive
maintenance on CT2 and CT3 on January 15, 1998. Operations was
preparing to take the systems out on Unit 1 when it was discovered that
elected Licensee Commitment 16.9 and NSD 316, Fire Protection (dated
December 30, 1997), had been misapplied. Specifically, hourly fire
watches had been.established instead of the continuous fire watches as
required by both instructions. Operations personnel had mistakenly
thought that they had not taken the .detection system out-of-service when
the fire water header was isolated on each of the two transformers. The
decision point regarding hourly or continuous fire watches was in the
procedure, but it did not specify what took the detection system out-of
service. Making the correct decision required an understanding of the
transformer fire suppression system. The licensee placed appropriate
watches on Unit 1. NSD 316 was scheduled to be enhanced to point out
that the detection system was disabled with the isolation of the
transformers' fire header. This non-repetitive, licensee identified and
corrected violation is being treated as an NCV consistent with Section
VII.B.1 of the NRC Enforcement Policy. This is identified as NCV 50
270,287/97-18-11: Failure to Implement Continuous Fire Watches During
Transformer Deluge System Maintenance..
c. Conclusions
An NCV was identified for failure to perform a continuous fire watch as
required by the fire protection program and selected licensee
commitments. The licensee had performed hourly fire watches instead of
continuous fire watches when the fire protection deluge system was taken
out of service for the startup transformers on Units 2 and 3.
29
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on February 11, 1998. The
licensee acknowledged the findings presented. No proprietary
information was identified to the inspectors.
X2
Notice of Enforcement Discretion for Units 2 and 3
a. Inspection Scope (92903)
The licensee has had many regular outage schedule disruptions, due to
many forced outages on all three plants in the last several years.
The
realization of associated surveillance schedule problems led the
licensee to have discussions with the NRC and produce several TS
submittals. The inspectors followed the activities and read the TS
submittals for correctness.
b. Observations and Findings
On January 15. 1998, the licensee submitted a TS change request in
accordance with 10 CFR 50.90. The requested amendment titled, Request
for Technical Specification Amendment for Test and Calibration,
consisted of a proposed one-time extension to the instrument channel
test frequency for several instruments and engineering safeguards
channel surveillances. The NRC.was processing that change in accordance
with the normal thirty-day comment period. Several days later, the
licensee discovered more TS driven surveillances that had not been
included in the January 15 submittal. The licensee engaged the NRC in
discussion about including these additional items in the January 15
submittal.
Due to NRC process requirements, NRR could not include those
additional surveillances in a timely manner to support Unit 2
surveillance due dates. The end of initial TS surveillance grace limit
for the potentially overdue low pressure injection cooler performance
test surveillance was February 14, 1998. while the unit refueling was
scheduled for March 13. 1998. The licensee then questioned the NRC
whether they could perform the surveillances scheduled to be completed
at refueling outages, at other times. The response from NRR in NRC
headquarters was that surveillances specified for refuelings per TS must
be completed during refueling outages. On January 30, 1998, the
licensee submitted a request for a Notice of Enforcement Discretion
(NOED) for Refueling Outage Frequency Surveillances. NRR had verbally
granted the discretionary enforcement to the licensee on January 30,
1998. After the granting of discretionary enforcement, the licensee
submitted a February 2, 1998, TS change altering the surveillance
frequency dates. The change which affected 93 surveillances, aligned
the Oconee TS with the NRC approved standard TS. That left several
surveillances to be performed later in February 1998 while Unit 2 was at
power operation, which was after the end of this inspection period.
30
The inspectors reviewed the proposed new TS for content. The licensee
appeared to have identified all the locations in the TS were refueling.
refueling outage, or "RF" (abbreviation for refueling frequency) had
been used. The licensee was submitting a page change to the last
submittal correcting a paragraph 4.2.2 change back to refueling-outage
frequency from eighteen months. These involved inspections of the core
barrel to core support shield caps that-should be inspected each outage.
This change was due to be issued on or about February 19, 1998.
Several items are planned or have occurred in response to the above
administrative events. The NRC performed a review of the surveillance
rocess, which is discussed in Inspection Report 50-269,270,287/98-01.
RR has issued or planned to issue the required documentation on the
licensee's submittals. The licensee was to issue an LER on the required
surveillance issue. Pending further review, this will be identified as
URI 50-269.270,287/97-18-12:
Refueling Outage Surveillance NOED.
c. Conclusions
On January 30, 1998, the licensee was granted verbal enforcement
discretion on statements of their TS regarding surveillance performance
intervals. The .licensee submitted a TS change to allow eighteen-month
periodicity of surveillance instead of a refueling outage periodicity.
inspectors had reviewed the change for completeness. Additional
followup on the enforcement discretion will be tracked under an
unresolved item.
X3
NRC Management Meetings
On December 16, 1997, Mr. Hugh Thompson, Jr., Deputy Executive Director
for Regulatory Programs and Mr. Luis Reyes, Regional Administrator.
Region II,
were at the site to tour the facility and meet with licensee
personnel.
0II
31
Partial List of Persons Contacted
Licensee
,E. Burchfield. Regulatory Compliance Manager
T. Coutu, Scheduling Manager
D. Coyle, Mechanical Systems Engineering Manager
T. Curtis, Operations Superintendent
B. Dobson, Mechanical/Civil Engineering Manager
W. Foster, Safety Assurance Manager
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Engineering Manager
W. McCollum, Vice President, Oconee Site
M. Nazar, Manager of Engineering
B. Peele, Station Manager
J. Smith, Regulatory Compliance
J. Twiggs, Manager, Radiation Protection
Other licensee employees contacted during the inspection included technicians,
maintenance personnel, and administrative personnel.
NRC
D. LaBarge, Project Manager
Inspection Procedures Used
Onsite Engineering
ASME Welding
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support Activities
Onsite Followup of Written Event Reports
Followup-Engineering
Followup-Piant Support
Prompt Onsite Response to Events
Sta0enrtr
32
Items Opened, Closed, and Discussed
50-269/97-18-01
Inadequate RIA Procedure (Section 01.3)
50-269,270,287/97-18-02
Containment Air Lock Testing (Section
01.5)
50-269,270.,287/97-18-03
SSF Diesel Generator Operation (Section
03.1)
50-269,270,287/97-18-04
Teflon Tape Use on the LPI System (Section
M1.1)
50-269,270,287/97-18-05
Failure to Revise Procedure Following ICS
Modification (Section M3.1)
50-269.270,287/97-18-06
IFI
K-line Breaker Issues (Section M3.2)
50-269/97-18-07
IFI
Pressurizer Surge Line Drain Line Nozzle
Loads Exceed Stress Analysis Limits
(Section E1.1)
50-269,270,287/97-18-08
Failure to Establish and.Implement
Procedures - Three Examples (Sections E2.1
and E2.2)
50-269,270.287/97-18-09
IFI
Review of the Root Cause Analysis for
Agastat Time Delay and Type D87 Timer
Relays (Section E2.2)
50-269,270,287/97-18-10
Failure to Follow Modification Procedures
(Section E8.1)
50-270.287/97-18-11
Failure to Implement Continuous Fire
Watches During Transformer Deluge System
Maintenance (Section F1.1)
50-269,270,287/97-18-12
Refueling Outage Surveillance NOED
(Section X2)
Closed
None
Discussed
50-269/97-10
LER
Inadequate Analysis of ECCS Sump Inventory
Due to Inadequate Design Analysis (Section
E8.1)
33
50-269,270,287/96-13-03
IFI
Service Water System Modifications and
Testing (Section E8.2)
List of Acronyms
Asea Brown Boveri
As Low As Reasonably Achievable
ANSI
American National Standard
American Society of'Mechanical Engineers
Babcox and Wilcox
CFR
Code of Federal Regulations
Condenser Circulating Water
Control Rod Drive
ECCW
Emergency Condenser Circulating Water
ESV
Essential Siphon Vacuum
F
Fahrenheit
GPD
Gallows per Day
GPM
Gallons Per Minute
Integrated Control System
IFI
Inspector Followup Item
In Service Testing
KHP
Keowee Hydro (electric) Plant
LER
Licensee Event Report
LCO
Limiting Condition for Operation
Low Pressure Injection
Low Pressure Service Water
Main Steam Line Break
mR
Millirem
Non-Cited Violation
Non-Licensed Operator
Notice of Enforcement Discretion
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
Nuclear Research and Regulation
NSD
Nuclear System Directive
NSM
Nuclear Station Modification
Operator Aid Computer
Oconee Nuclear Station
Once Through Steam Generator
Public Document Room
Problem Investigation Process
Pounds Per Square Inch Gauge
PSL
Pressurizer Srge Line
Performance Test
Quality Assurance
Reactor Building
REV
Revision
RIA
Radiation Indication and Alarm
Revolutions Per Minute
Remote Weld Plug
34
Severe Accident Management Guideline
SASS
Smart Analog Signal Select [system]
Once Through Steam Generator
Structure, Systems & Components
SSF
Safe Shutdown Facility
SWSOPI
Service Water System Operational Performance Inspection
TS
Technical Specification
Updated Final Safety Analysis Report
Unresolved Item
Violation
Work Order