ML17292B251
| ML17292B251 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 02/19/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17292B249 | List: |
| References | |
| 50-397-97-20, NUDOCS 9802250114 | |
| Download: ML17292B251 (30) | |
See also: IR 05000397/1997020
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
50-397
License No.:
Report No.:
50-397/97-20
Licensee:
Facility:
Location:
Washington Public Power Supply System
Washington Nuclear Project-2
Richland, Washington
Dates:
December 21, 1997, through January 31, 1998
Inspectors
S. A. Boynton, Senior Resident Inspector
T. R. Meadows, Reactor Engineer
G. W. Johnston, Senior Project Engineer
M. P. Shannon, Senior Radiation Protection Specialist
Approved By: H. J. Wong, Chief, Reactor Projects Branch E
ATTACHMENT: Supplemental Information
9802250ii4 9802i9
ADQCK 050003'P7
8
EXECUTIVE SUMMARY
Washington Nuclear Project-2
NRC Inspection Report 50-397/97-20
Qg~r~ins
~
The professionalism of the control room operators and shift management ownership of
crew activities supported good operational performance over the inspection period.
Operators were generally knowledgeable of plant and equipment status, with several
minor exceptions (Section 01.1).
The licensee's program to assure that corrective lenses for self-contained breathing
apparatus (SCBA) for operators requiring them was implemented successfully. However,
procedural guidance for maintenance of the SCBA corrective lens program was
considered weak in that periodic inventories were not required and written expectations
were not provided to operators on the need to have SCBA qualified lenses, regardless of
the type of corrective lenses normally used (Section 01.2).
A personnel error on the part of an equipment operator during the performance of
clearance order activities resulted in the momentary deenergization'of the Division II
4160V vital bus and the loss of residual heat removal assist cooling of the spent fuel
pool. A noncited violation was identified associated
with this 1996 licensee event report
(Section 08.1).
M in
anc
Observed maintenance and surveillance activities were generally well coordinated and
executed with appropriate craft supervision and system engineering participation
(Section M1.1).
The failure of maintenance
personnel to read and adhere to the instructions on a caution
tag prior to manipulating a breaker resulted in the loss of the Division I 125VDC critical
instrument power inverter, the initiation of several essential safety features, and isolation
of several containment isolation valves.
The event occurred while the plant was defueled
in Mode 5. A noncited violation was identified associated with this 1996 licensee event
report (Section M8.1).
~En ineeiin
Licensee procedures for controlling the configuration of the 4160V vital switchgear
breakers did not ensure that configurations would be consistent with the seismic
qualification of the switchgear.
A noncited violation was identified associated with this
1996 licensee event report (Section E8.1).
Calibration and surveillance procedures for the rod block monitor system were found to.
be inadequate to ensure the rod block monitors were operable prior to exceeding
30 percent rated thermal power as required by Technical Specifications.
As a result, the
-3-
system did not enforce rod blocks until power was approximately 33 percent.
A noncited
violation was identified for this 1997 licensee event report (Section E8.2).
In establishing the flow switch high flow isolation setpoint for the reactor water'cleanup
system blowdown line, engineering personnel did not adequately review the instrument
loop design.
This resulted in the application of an improper conversion factor for the flow
switch and a nonconservative high flow isolation setpoint that exceeded the maximum
allowable Technical Specification value. A noncited violation was identified associated
with this 1997 licensee event report (Section E8.3).
~
Three examples were identified in which the licensee had evaluated and implemented a
change to the facility, as described in the Fina1'Safety Analysis Report, but failed to
update the report in accordance with 10 CFR 50.71(e).
The licensee is implementing a
broad review of the Final Safety Analysis Report to identify and correct any additional
errors. A noncited violation was identified (Section E8 4).
~
Corrective actions to address inadequate labeling of radioactive material containers have
not been effective in'preventing recurrence, as evidenced by several recent
noncompliances identified by the inspectors and the licensee, and resulted in a violation
Additionally, a lack of defined ownership of areas in the radwaste
building contributed to poor radiological housekeeping
practices on the 507 foot elevation
(Section R1.1).
Engineering controls placed upon the traversing in-core probe Drive C were
insufficient'n
preventing movement of the probe during troubleshooting activities. The unexpected
movement of the probe required personnel actioh to.prevent the probe from withdrawing
from its shielded location and going into the area where the troubleshooting was being
performed.
Based upon other barriers to personnel overexposure that were in place and
the immediate actions taken in response to the event, the likelihood of a significant
overexposure was low (Section R1.2).
The licensee's analysis and root cause evaluation of the unexpected movement of the
traversing in-core probe accurately characterized the event and identified a number of
areas for improvement, including personnel level of knowledge of TIP system operation
and level of involvement of radiation protection supervision in the ALARAplanning
process for high radiological risk jobs (Section R1.2).
Summa
. f Plan
S a
The plant began the inspection period at 100 percent power. On January 12, power was
reduced to approximately 99 percent when the licensee identified a minor but nonconservative
input error to the plant process computer's heat balance calculation.
The licensee corrected the
error and returned the plant to full power on January 22. The plant remained at 100 percent
power for the balance of the inspection period.
01
Conduct of Operations
01.1
en
r
I
e
s
707
During the inspection period, the inspectors performed extended observations of the
conduct of activities in the control room. Allsix crews were observed during
approximately 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> (including 26 shift turnoyers) of observation in the control room.
bs rv in
The operators were generally alert, responsive to alarms, professional, and safety
conscious.
The inspectors observed that operators used good operator self-checking
when manipulating controls and three-way communication when appropriate.
The
inspectors observed appropriate shift management involvement in daily activities. Shift
turnovers were thorough, efficient, and covered all plant activities planned for the shift.
The shift supervisor also reviewed any problem evaluation requests (PERs) and new
night orders.
When questioned on various aspects of plant'status and systems,
operators were generally found to be knowledgeable, except as noted below:
During a morning shift crew briefing, the inspectors noted that the night shift crew
had turned over to the oncoming crew that the off-gas condenser level controller
had to be vented due to a buildup of gas.
When questioned, the oncoming crew
did not know the reason for the gas buildup and had accepted the venting as
routine. Subsequent
investigation by the licensee identified a faulty level
controller and the problem was corrected.
A review of control board process parameters
noted that the indicated flowfor
Main Steam Line A was approximately 8 to 9 percent lower than the other three
steam lines.
From questioning operators from several different crews, the
inspectors determined that none of the operators could adequately explain the
difference in the flow indications.
In subsequent
discussions with the cognizant
-2-
system engineers, the inspectors found that the flow difference is a physical
phenomenon that resulted from the licensee's main turbine governor valve
optimization modification.
Operating Instruction (Ol) 9, "Expectations for Supervisory and Peer Oversight," provides
guidelines for reinforcing performance expectations and coaching of the operations staff
through direct observation of routine activities. Ol-9 also delineates the number of
observations that each of the members of the shift crews are expected to perform on a
shift or weekly basis.
A review of the observations performed by each of the six crews
during the months of December and January found that the expectations of Ol-9 were
generally being met. The number of observations performed within each crew also
showed a renewed emphasis on implementing the Ol-9 program at the crew level. The
inspectors concluded that this level of coaching likely contributed to the good
performance during December and January.
It was also recognized that performance
was improved from similar periods during the past several years.
Qgni~us'i~
The professionalism of the control room operators and shift management ownership of
crew activities supported good operational performance over the inspection period.
Operators were generally knowledgeable of plant and equipment status with several
minor exceptions.
0.1.2
r
8
u
ifi
e
s
0
The inspectors verified operator license conditions regarding operator licenses which
specified the need for corrective lenses.
The inspection included a review of the
licensee's processes
for ensuring that SCBA qualified corrective lenses were readily
available in the control room.
b
rvations a
Fi din s
Licensed operators who, as a condition of their license, are required to wear corrective
lenses during the performance of licensed activities, 'are also required to have SCBA
'qualified corrective lenses readily available in the control room. The inspectors
interviewed two operators with conditions for corrective lenses and were informed that
SCBA qualified lenses were in individual lockers in the control room. The inspectors also
verified that the licensee has administrative and training procedures
in place that require
biennial SCBA fit tests and reminders for operators to check that they have SCBA
qualified lenses, ifnecessary.
However, the inspectors found that the licensee did not have in place instructions or
procedures that require an independent periodic inventory of SCBA qualified lenses for
-3-
licensed operators in the control room. The licensee also did not have a system that
could readily list which operators are required to have SCBA qualified lenses.
The
inspectors found from interviews with licensee management that it was their expectation
that all licensed operators that have licenses with conditions for corrective lenses have
SCBA qualified lenses readily available, whether or not they normally wear contacts or
glasses.
However, this expectation was not communicated to operators in writing.
Operations management committed to revise their conduct of operations procedures to
require licensed operators to periodically verify inventory for their SCBA qualified
corrective lenses, as necessary.
The licensee also committed to provide written
expectations of their policy regarding SCBA qualified corrective lenses.
The lack of
procedural guidelines and written expectations to require and monitor the continued
availability of SCBA qualified corrective lenses in the control room was considered a
weakness
in the implementation of the SCBA program.
c.
~Cncl sion
The licensee's program to assure that corrective lenses for SCBA for operators requiring
them was implemented successfully.
However, procedural guidance for maintenance of
the SCBA corrective lens program was considered weak in that periodic inventories were
not required and written expectations were not provided to operators on the need to have
SCBA qualiTied lenses, regardless of the type of corrective lenses normally used.
Operational Status of Facilities and Equipment
02.1
n ine r
Saf
F a
re
s
m Walkdowns
71707
The inspectors walked down accessible portions of the following engineered safety
feature systems:
Control Room Ventilation
(Div. I, II, III)
4160V Vital Switchg ear
Standby Service Water System (Train A)
Each of the systems was found to be properly aligned for the current plant conditions.
Material condition of system components was found to be generally good, with
deficiencies properly identified. However, during tours of the emergency diesel
generator (EDG) rooms, the inspector found the "Ready for AUTO Start" light on the
Division II EDG local control panel and the "ON" light for Division III Fan DEA-FN-31 not
lit.
Subsequent
investigation by the licensee showed that the indicating lights had
burned out. Failed indicating lights on the diesel generator motor control centers were
noted as a concern in NRC Inspection Report 50-397/97-14.
4
08
Miscellaneous Operations Issues (92901)
08.1
Closed
LE
0-397/96002-00:
inadvertent loss of power to vital bus and automatic
start of associated
EDG. On May 4, 1996, with the reactor defueled, critical safety
Bus SM-8 lost power when supply Breaker 3-8 tripped open due to personnel error. As a
result, the Division II EDG started, the backup transformer automatically provided power
to Bus SM-8, and residual heat removal Pump 2B lost power. This pump had been
supplying fuel pool cooling in the assist mode.
The plant was immediately restored to
normal lineup. The licensee determined the cause of the event was momentarily
opening of the Bus SM-3 potential transformer (PT) fuse compartment by an equipment
operator (EO). The EO had erroneously opened and then reclosed the PT compartment,
leaving it in an abnormal condition. The EO was installing clearance orders in and
around Bus SM-8.
The licensee took the following immediate actions:
~
Operations management suspended
ongoing clearance order restoration
activities and initiated a PER
.
~
Residual Heat Removal Pump 2B was returned to service within 45 minutes.
I
The licensee took the following additional corrective actions:-
Revised procedures/instructions
regarding clearance order preparation to ensure
the need for simultaneous verification is noted.
Took appropriate personnel action against the EO.
Counseled the production reactor operator and senior reactor operator that were
involved concerning the necessity of performing adequate
prejob briefs prior to
performance of critical clearance activities.
Because the licensee event report (LER) did not address labeling of the fuse
compartments as a potential contributor, the inspectors independently observed the
associated
Bus SM-3 fuse panels and found them to be well labeled.
The inappropriate
opening of the Bus SM-3 PT fuse compartment was determined to be a violation of the
licensee's clearance order procedure and Technical Specification (TS) 6.8.1.a.
This
nonrepetitive, licensee-identified and corrected violation is being treated as a noncited
violation consistent with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-
397/97020-01).
08.2
Closed
VIO 50-397/96003-02:
failure to draw a reactor coolant chemistry sample within
2-6 hours following a power change of greater than 15 percent, in accordance with
TS 3.4.5. The licensee determined that the root cause of the violation was an
inadequate procedure.
Specifically, the licensee found that neither Plant Procedure
0
-5-
Manual (PPM) 3.2.1, "Shutdown to Cold Shutdown," nor PPM 3.2.2, "Shutdown to Hot
Shutdown," contained steps in the body of the procedure to notify chemistry of the need
to perform a sample following the recirculation pump shift, an evolution that resulted in a
.power change of greater than 15 percent.
A prejob brief that failed to identify a
responsible individual to track reactor power changes and notify the chemistry
department and insufficient information in the control room log identifying specific power
changes were considered to be contributing factors.
In addressing the root cause and contributing factors, the licensee revised PPMs 3.2.1
and 3.2.2 to include the assignment of an individual to track reactor power changes and
to notify chemistry, as appropriate.
A performance improvement plan was implemented
to address critical behaviors for effective crew prejob briefs while the licensee's
performance oversight process was also revised to include a prejob brief observation as
a performance feedback tool.
The inspectors noted that the licensee's Improved Technical Specifications, implemented
in March 1997, no longer require a reactor coolant system sample to be drawn when
reactor power is changed by greater than 15 percent in a 1-hour period.
M1
Conduct of Nlaintenance
M" .
a.
n
c ion
e
2707
The inspectors observed and/or reviewed the following maintenance and surveillance
activities:
Work Order Task HJJ301, Off-gas Hydrogen Analyzer B Channel Check
Work Order Task JRJ701, Service Water Process
Radiation Monitor Adjustment
Work Order Task HVB001, Reactor Building Fan ROA-FN-1B Lubricate Bearings
Work Order Task HTZ901, Reactor Core Injection Cooling Water Leg Pump,
RCIC-P-3 Oil Change and Lubrication
Work Request 98000012, Reactor Water Feed GE FANUC CPU Scanner Module
Failure
Work Order Task JSZ6T2, Replace Reactor Heat Removal Pump, RHR-P-3,
Packing
-6-
Work Order Task HYR300, Replacement of Instrument Test Valves on Main
Steam Instrument Rack E-IR-H22/PO15
Work Request 98000009, WCH-DPT-50 AirSeparator Controller Reset
Work Order Task HML704, Standby Liquid Control Pump, SLC-P-2B,
Replacement of Lube Oil
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Fin in
The inspectors observed that, with the one exception noted below, the work was
'performed professionally and was consistent with the licensee's work control procedures
and expectations.
The inspectors also observed frequent maintenance management
and operations personnel supervision and observation during this inspection period.
On January 15, 1998, the inspectors periodically observed craft personnel replace
lubricating oil on standby liquid control (SLC) Pump SLC-P-2B. On one occasion the
inspectors arrived at the work location and noticed tools and other loose items lying
about, with no licensee personnel and no work-in-progress sign present.
The inspectors
found that it is the licensee management
expectation to have an appropriately filled out
work-in-progress sign in place when it is necessary to abandon the work site. The
inspectors also observed that the personal protection shield over the motor-to-pump
coupling had been removed and the coupling left exposed.
The inspectors determined
that this was in accordance with the licensee's foreign material exclusion procedures
in
that the procedures only required foreign material exclusion for internal pump or motor
components.
However, the inspectors concluded that the missing sign, disarrayed tools,
and uncovered shaft coupling with the absence of personnel present to be poor work
practices which did not meet the licensee management expectations.
c.
Conctusiorcs
The observed maintenance
and surveillance activities were generally well coordinated
and executed with appropriate craft supervision and system engineering participation.
MS
Miscellaneous Maintenance Issues (92902)
M8.1
Closed
LE
50-397/96001-00:
inadvertent engineered safety feature (ESF) actuation
due to tripping temporary power supply. On April 25, 1996, two temporary electricians
inadvertently opened the fused disconnect supplying the uninterruptible power supply
Inverter IN-3 loads.
This caused
a loss of power to the loads and subsequent
actuations and containment isolations.
Since the plant was in an outage and defueled,
there was little impact and the operators quickly restored the affected systems.
Inverter IN-3 loads were being temporarily supplied through a disconnect switch that was
labeled as a spare breaker.
A caution tag on the disconnect handle identified it as the
-7-
temporary power supply to Inverter IN-3 with instructions to contact the control room
before operating the disconnect.
The two electricians said that they did not read the
caution tag. The licensee determined the'root cause of the event to be human error.
The licensee took the following immediate'actions:
~
Operations restored power to Inverter IN-3 loads and reset the ESF actuations
without further incident.
~
Restricted the two electricians from the power block for the remainder of the
outage.
~
Reiterated management expectations concerning equipment clearance
'requirements and the appropriate approvals needed prior to entering panels,
components,
or systems, during briefings with plant and contractor maintenance
personnel.
The licensee took the following additional corrective actions:
~
Revised PPM 10.25.1, "Maintenance Programs and Procedures," Revision 9, to
include the requirement to provide field identification of spare disconnects that
are providing temporary power.
~
Revised applicable maintenance lesson plans to include lessons learned from
this event regarding clearance orders and the opening of panels.
The failure of the electricians to read and adhere to the instructions on the supply
breaker's caution tag was identified as a violation of the licensee's clearance order
procedure and TS 6.8.1.a.
This nonrepetitive, licensee-identified and corrected violation
is being treated as noncited violation consistent with Section VII.B.1 of the NRC
Enforcement Policy (NCV 50-397/97020-02).
M8.2
Closed
Viola ion 50-397/
2-01: Plant Procedure Manual Procedure 2.10.4, "Diesel
Generator (DG) and Cable Cooling Heating Ventilation, and'Air Conditioning (HVAC),"
Revision 12, date January 11, 1996, did not provide adequate instruction for
troubleshooting for low DG room temperature conditions.
The procedure did not include
provisions for other possible causes,
such as the standby DG heating and ventilation unit
damper positions.
The licensee identified that, in past revisions, inclusion of checks of possible inleakage
past the emergency ventilation unit dampers was considered unnecessary.
This was
because the dampers were not thought to be likely sources of outside air inleakage.
The
licensee has included steps to check the dampers and to consider other possible
sources as contributors to cold room temperature
in Revision 13 to PPM
Procedure 2.10.4.
-8-
NRC Inspection Report 50-397/96-06 identified further examples of this violation.
Corrective actions for those specific violations included changes to PPM
Procedure 1.3.78 to further define management expectation of the use of emergency
maintenance.
PPM Procedure 1.3.78 was superseded
by Site Wide Procedure SWP-MAI-01, "Work
Management - Planning, Scheduling and Work Activities," Revision 0. The inspector
examined Procedure SWP-MAI-01 and determined that the procedure in Section 3.1
provides guidance that defines the circumstances under which emergency maintenance
can proceed.
The inspector concluded that the guidance was sufficient to ensure proper
control of emergency maintenance activities.
Procedure SWP-MAI-01 also provides guidance on management
expectations for
postmaintenance
testing and determination of operability. The inspector concluded that
guidance was sufficient to assure that adequate postmaintenance
testing is identified
and that testing is sufficient to determine operability.
The licensee's corrective actions were considered appropriate.
INiscellaneous Engineering Issues (92903)
E8.1
'
lo
d
E
0-
7/
07- 0:
electrical breakers not seismically qualified in
test/disconnect
position.
On November 22, 1996, the licensee identified that the plant
was in an unanalyzed condition due to a spare electrical circuit breaker in a safety-
related 4160 V switchgear being in a racked out condition not assessed
by seismic
analysis.
Specifically, seismic testing of the vital 4160V switchgear was not conducted
with breakers in a racked out condition. The licensee immediately reported this condition
to the NRC and removed the spare breaker from the switchgear and placed it in a
qualified position.
The licensee concluded that the root cause of the event was the failure of the
manufacturer to test the vital switchgear with breakers in the racked out condition.
However, the LER further states that the switchgear was tested in accordance with
Electrical Standard IEEE-344, 1971, which only specifies testing in the service mounted
or racked in condition. The inspector considered the licensee's identified root cause of
the event to be inappropriate based on the IEEE testing requirements and the corrective
actions taken to address the issue.
The licensee's corrective actions included revising
procedures for racking out breakers to ensure that they are not placed in a nonseismic
qualified position. Also, seismic qualification files for existing safety-related switchgear
were revised to specify the lack of seismic qualification for breakers in the racked out
condition. The corrective actions taken were considered appropriate.
-9-
The failure of plant procedures and instructions to control the configuration of the vital
4160V switchgear to ensure that its seismic qualification was maintained was identified
as a violation of 10 CFR Part 50, Appendix B, Criterion III (Design Control). This
nonrepetitive, licensee-identified and corrected violation is being treated as a noncited
violation consistent with Section VII.B.1 of the NRC Enforcement Policy
(NCV 50-397/97020-03).
E8.2
Clo
d
ER
0- 97/97002-00:
rod block monitor calibration values not in accordance
with Technical Specifications.
On February 18, 1997, the licensee determined that they
were not in compliance with TS Table 3.3.6-1 and TS 3.1.4.3 regarding the operability of
the rod block monitoring (RBM) system.
A vendor surveillance procedure to calibrate
RBM channels caused an error that did not allow RBM to become operable until
33 percent power. The TS limitwas 30 percent power. This condition had existed since
the original plant startup.
The licensee also found similar errors in the TS RBM
surveillance procedures.
The licensee immediately corrected the vendor procedures,
recalibrated the RBM
channels, and reperformed the channel surveillance to verify that the RBM systems
became operable at 30 percent power. The licensee then revised the TS RBM
surveillance procedures to correct the errors.
The licensee also implemented the
Improved Technical Specifications which also checked or corrected other TS related
instrument surveilances.
The failure of the RBMs to be operable prior to exceeding
thermal power levels of 30 percent was considered to be a violation of TS 3.0.4.
The inspectors reviewed the corrective actions and found them to be acceptable.
However, the inspectors noted that the licensee's root cause analysis had not addressed
why operators did not identify the concern with the RBMs during the many plant startups
since the initial startup.
Current procedures do include a step to verify that the RBM
downscale alarm is clear prior to going above 30 percent power. This nonrepetitive,
licensee-identiTied and corrected violation is being treated as a noncited violation
consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV 50-397/97020-04).
E8.3
Clo ed
LER 50-397/97001-00:
reactor water cleanup (RWCU) blowdown flow isolation
setpoint above TS allowable limit. On February 11, 1997, the licensee determined that
they did not comply With TS 3.3.2 for the maximum allowable RWCU blowdown flow of
equal to or less than 271.1 gpm. The licensee determined that an improper dc voltage
setpoint for the associated
leak detection system flow switches had been used in the
original RWCU high blowdown flow isolation trip signal calculation.
The calculation error
was in the nonconservative direction. The licensee took the following corrective actions:
Immediately isolated RWCU blowdown flow.
Modified applicable channel calibration, channel functional checks, and response
time testing procedures to incorporate the corrected setpoints from the corrected
calibration.
0
-10-
Recalibrated applicable flow switches, realigned the RWCU system, and restored
blowdown capability.
Initiated a plan to conduct a review of plant instrument setpoint calculations and
associated
master data sheets.
The failure to set the flow switches to isolate RWCU prior to exceeding a blowdown flow
of 271.1 gpm was determined to be a violation of TS 3.3.2.
The inspectors reviewed the corrective actions and found them to be acceptable.
This nonrepetitive, licensee-identified and corrected violation is being treated as a
noncited violation consistent with Section VII.B.1 of the NRC Enforcement Policy
(NCV 50-397/97020-05).
E8.4
Clo
d
In
ec ion Followu
Item 50-397/9
0
- 4: failure to update the Final Safety
Analysis Report (FSAR). The inspectors identified three examples in which the licensee
made changes to the facility, as described in the FSAR, but failed to update the FSAR to
reflect those changes.
The three examples included:
Removal of the diesel-driven air compressor for the Division II EDG starting air
system (FSAR Section 9.5.6.2).
Removal from service of the 522 foot reactor building elevation electronics air
conditioning unit (FSAR Section 9.4.2.2.4.d).
Elimination of the electrohydraulic operator for Valve WOA-V-52D, control room
HVAC purge isolation valve (FSAR Section 6.4.4.1).
For each of these changes, the licensee had performed a written safety evaluation in
accordance with 10 CFR 50.59. As a corrective action to these and other examples
identified by the NRC and the licensee, the licensee has undertaken a broad program
review to identify any additional discrepancies
and update the FSAR. A description of
the licensee's program was provided in NRC Inspection Report 50-397/97-14.
From a
review of the scope and depth of the licensee's review program, the inspector concluded
that the licensee would likely have identified and corrected the above discrepancies.
The
, failure to update the FSAR was determined to be a violation of10 CFR50.71(e).
This
noncompliance is'eing treated as a noncited violation, consistent with Section VII.B.3of
the NRC Enforcement Policy (NCV 50-397/97020-06).
An inspection followup item will
be opened to evaluate the licensee's corrective actions for FSAR discrepancies
(Inspection Followup Item (IFI) 50-397/97020-07).
E8.5
Closed
Unresolved
I em
0-397/96026-04:
failure of standby service water Pump 1A.
Standby service water Pump 1A tripped unexpectedly on December 20, 1996, when
control room operators attempted to start the pump. This issue was closed in NRC
Inspection Report 50-397/97-04 in the review of LER 96009-00.
-11-
E8.6
I
d Ins
i n F Ilowu
I em
0-397/97018-0:
review of transient hydraulic loads
on standby service water loop piping. The licensee's analysis of service water Loop B
piping was documented
in Calculation Modific'ation Record ME-02-96-25. The
calculation was to evaluate the service water Loop B piping hydraulic transients in
response to PER 295-1 275. This IFI was initiated on closure of IFI 50-397/95033-01.
The results of the calculation'did not indicate there were any substantive stresses
imparted to the piping or supports.
At the time of NRC Inspection Report 50-397/97-18,
the inspector had not completed a review of the calculational methodology.
After the inspections, the licensee conducted an analysis of the effects of the water
hammer to quantify the stresses
incurred during the event.
The inspector reviewed the
calculation and determined that the methodology appeared
to be appropriate.
The
results of the calculation indicate low stress levels and no apparent potential for damage
to the piping. Maximum indicated stress to the piping itself was 842 psi, with an
allowable stress of 15,000 psi. For the pipe support lugs on the return line hanger at
SW-1063-12, where the highest stress was identified, the stress was 7,600 psi with an
allowable stress of 18,000 psi.
The inspector concluded that the calculations were appropriate, addressing the most
significant portions of the piping and confirming the observations of no damage to the
piping or supports.
IV. Plant Support
R1
Radiological Protection and Chemistry Controls
R1.1
In d
ua e
arkin
f Radioac ive M
erial
ntai
and R
i
i n
i n
a.
Inse in
e 7750
The inspectors conducted frequent plant tours to evaluate,
in part, radiation protection
controls and practices.
b.
bs rva ion
andFin
'n s
adi
iv
Ma erial Labelin
On December 31, 1997, while conducting a general tour of the 507 foot level of the
radwaste building, the inspectors found three sealed bags containing HEPA filters just
outside of a radiological work isolation room. The sealed bags were not labeled as to
any potential radiological hazard.
The inspectors also found a large internally
contaminated piece of machinery that was wrapped and sealed in a radiological control
bag which was also not labeled.
In addition, the inspectors noted an apparent
contamination control area that was posted with unmarked radiation signs.
On
-12-
January 22, 1998, the inspectors noted another radiological control bag that was
, apparently not labeled.
This was also found on the 507 foot level of the radwaste
building. Subsequent
investigation by the licensee found that'a label was attached to the
material inside the bag which was not readily visible to the inspector.
From discussions
with the radiation protection manager, this labeling practice did not meet management
expectations.
The unmarked radiation signs for the apparent contamination control area were a
concern because they lacked information on the general hazards within the area and
also have the potential to desensitize licensee personnel to radiation signs.
For each of
the sealed bags of contaminated equipment noted above, a clearly visible label could not
be identified that provided information on the quantity of radioactivity, radiation levels,
and kinds of material present.
The inadequate labeling of the radioactive material was
determined to be a violation of 10 CFR 20.1904(a) which requires containers of licensed
material be labeled with sufficient information to permit personnel to take precautions to
avoid or minimize exposures (VIO 50-397/97020-08).
The failure to properly label containers of radioactive material has been the subject of
several recent PERs.
PER 296-0346 was initiated due to an adverse trend in
compliance with the licensee's radioactive material labeling procedure.
Subsequent to
the initiation of PER 296-0346, 15 additional noncompliances with the labeling procedure
were identified, 3 of which occurred after closure of the PER. As a result, the licensee
initiated another adverse trend PER for those concerns (PER 296-0839).
The licensee's
root cause analysis showed that the earlier events were generally caused by errors
made by health physics technicians.
As a result, enhancements
were made to the
licensee's labeling procedure and specific training was provided to the health physics
technicians.
The licensee's review of the more recent concerns with labeling found that the errors
were generally caused by inadequate radiation worker performance.
Additional
improvements to plant procedures were implemented as a result. To improve radiation
worker performance,
it was also recommended,
through the disposition of PER 296-
0839, that a request be submitted to the cognizant training advisory groups (TAGs) to
address radioactive material labeling requirements. in their training programs.
However,
the request that was actually sent to the TAGs did not require any modifications to their
programs and only asked that the TAGs consider addressing this issue.
The inspectors
considered this to be an important corrective action that had weak implementation, due
to the open-ended
nature of the request to the TAGs.
PERs 297-0485, dated May 26, 1997, and 297-0721, dated August 15, 1997, were also
initiated due to inadequate labeling of radioactive material.
PERs 297-0485, 297-0721,
and the more recent examples identified by the inspectors indicate that the corrective
actions to improve radiation worker performance have not been fullyeffective.
0
-13-
Housekee
in
in Radiolo icall
C nrolle
Are s
On December 31, 1997, the inspectors noted anticontamination clothing loosely lying
about on the floor, just outside the step-off pad of a contaminated area of the 507 foot
. elevation of the radwaste building. On January 22, 1998, the inspectors again noted
poor housekeeping
practices on the 507 foot level of the radwaste building. Loose tools,
bolts, rope, and plastic straps were lying about both in and outside of controlled
contaminated areas near the step-off pad receptacles.
From discussions with the plant
manager,
it was determined that organizational ownership of the area was not clearly
defined for purposes of housekeeping
and cleanliness.
The radiation protection
manager walked down the areas noted by the inspectors and agreed that the
housekeeping
conditions found did not meet management
expectations.
Conclusions
Corrective actions to address inadequate labeling of radioactive material containers have
not been effective in preventing recurrence as evidenced by several recent
noncompliances identified by the inspectors and the licensee and resulted in a violation
Additionally, a lack of defined ownership of areas in the radwaste
building contributed to poor radiological housekeeping
practices on the 507 foot
elevation.
R1.2
E
ma
E
o ure Con
s
In
ec ion Sco e
8 75
On January 7, 1998, while troubleshooting was being performed on tiaversing in-core
probe (TIP) Machine C, withdrawal of the probe towards the TIP machine occurred
unexpectedly.
Selected radiation workers and radiation protection personnel involved in
the troubleshooting were interviewed. Additionally, the problem evaluation request which
documented the event was reviewed.
0 serva ions and Findin s
The inspectors reviewed Problem Evaluation Request (PER) 298-0019, which
documented the events associated
with the unexpected movement on January 7, 1998,
and found the PER and its associated
root cause evaluation to be an accurate reflection
of the event.
The inspectors determined that the root cause evaluation, including the
addendum, identified and captured a number of areas for improvement to help prevent a
similar occurrence
in the future.
During the review of this event, the inspectors interviewed the radiation protection
supervisor who had approved the radiation work permit (9700390-01) for the TIP drive
work and the radiation protection technician who performed the ALARAplan and
provided job coverage for the task.
Both of these individuals were under the mistaken
-14-
impression that the TIP could not fullywithdraw into the TIP drive room where the
troubleshooting was being performed on TIP Machine C.
From discussions with the
system engineer, he was aware that the TIP could fullywithdraw into the TIP drive room;
however, he was under the mistaken impression that the logic circuit was working
properly and would prevent this from happening.
As a result, the implemented
engineering controls were not comprehensive to ensure movement of the TIP probe was
precluded.
The inspector also concluded it was for this reason that the system engineer did not
discuss the possibility of the TIP completely withdrawing into the TIP drive room during
the ALARAprejob briefing with the personnel involved with this task.
From interviews with the radiation protection technician who performed the ALARA
planning aspects of the task, the inspectors determined that the radiation protection
technician researched
the plant's radiological job history files to identify past radiation
work permits and historical radiological survey information which was used for similar
work. However, the inspector found that the files did not contain industry events or NRC
information notices for similar work. The inspectors commented that maintaining industry
events and NRC information notices in job history files could help identify problems that
might be encountered.
The licensee acknowledged the inspectors'omment.
The licensee provided the inspectors an estimate of the worst case radiological
conditions in the event that the TIP was to completely withdraw into an unshielded
portion of the TIP system.
The licensee estimated, and the inspectors concurred, that
the radiation exposure levels could have been as high as 110 rems per hour at
30 centimeters (about
1 foot) from the TIP. The licensee's investigation determined that,
although the radiation protection personnel involved in the task knew that the exposure
rates could be substantial, they did not have a complete understanding of the radiological
conditions in the event the TIPs were fullywithdrawn.
The inspectors noted that the radiation protection supervisor who had approved the
radiation work permit was not involved in any of the job planning meetings and was only
briefed by the radiation protection technician who performed the ALARAjob planning.
The inspectors commented that not involving the radiation protection supervisor who was
responsible for approving a potential high radiological risk radiation work permit could
lead to the permit being approved without a complete understanding of the task. The
radiation protection and station managers acknowledged the inspectors'omment
and
stated that they would review the process of approving radiation work permits.
From interviews with the personnel involved and a review of the radiation work permit
and ALARAprejob briefing, the inspectors determined that the personnel involved knew
the radiological conditions in the area and their response to unexpected radiological
conditions.
It was also noted that each person carried an alarming, electronic dosimeter
~
~
-15-
for monitoring their accumulative dose and area dose rate.
These measures,
coupled
with the immediate actions taken to leave the room when the TIP drive began to move,
significant!y reduced the likelihood of an overexposure.
The inspectors'eview of the station's procedures,
GEN-RPP-01 "ALARAPROGRAM
DESCRIPTION," Revision 1, 11.2.2.5, "ALARAJOB PLANNINGAND REVIEWS,"
Revision 7, and 11.2.2.11, "EXPOSURE EVALUATIONSFOR MAINTAININGTEDE
ALARA,"Revision 2, identified that these procedures did not discuss management's
expectations and requirements for involving second and/or third line radiation protection
supervision in the review of high radiological risk jobs. The radiation protection and plant
managers also noted that they had identified this issue as an area of improvement and
would review their program to clearly involve second and/or third!ine radiation protection
supervision in the ALARAreview process for certain high risk radiological tasks.
C.
g~o~l<jiin
Engineering controls placed upon the traversing in-core probe Drive C were insufficient
in preventing movement of the probe during troubleshooting activities. The unexpected
movement of the probe required personnel action to prevent the probe from withdrawing
from its shielded location and into the area where the troubleshooting was being
performed.
Based upon other barriers to personnel overexposure that were in place, and
the immediate actions taken in response to the event, the likelihood of a significant
overexposure was low.
The licensee's analysis and root cause evaluation of the unexpected movement of the
traversing in-core probe accurately characterized the event and identified a number of
areas for improvement, including personnel level of knowledge of TIP system operation
and level of involvement of radiation protection supervision in the ALARAplanning
process for high radiological risk jobs.
V. I@an'a
ement Nleetin s
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management
after the
conclusion of the inspection on February 9, 1998. The licensee acknowledged the findings
presented.
The inspectors asked the licensee whether any materials examined during the inspection. should
be considered proprietary.
No proprietary information was identified.
Supplemental Information
PARTIALLIST OF PERSONS CONTACTED
~L'se .
P. Bemis, Vice President for Nuclear Operations
F. Diya, Engineering Programs Manager
D. Hillyer, Radiation Protection Manager
P. Inserra, Licensing Manager
A. Langdon, Assistant Operations Manager
E. Neasham,
Reactor Engineering
G. Smith, Plant General Manager
R. Webring, Vice President Operations'upport
J. Weers, System Engineer
INSPECTION PROCEDURES USED
IP 37551:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92901:
IP 92902:
'P
92903:
Onsite Engineering
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support
Followup - Operations
Followup - Maintenance
Followup - Engineering
Qgy~n
ITEMS OPENED, CLOSED, AND DISCUSSED
50-397/97020-01
inappropriate opening of the SM-3 PT fuse compartment
50-397/97020-02
failure of the electricians to read and adhere to the instructions on
the supply breaker's caution tag
50-397/97020-03
failure of plant procedures and instructions to control the
.configuration of the vital 4160V switchgear to ensure that its
seismic qualification was maintained
50-397/97020-04
failure of the RBMs to be operable prior to exceeding thermal
power levels of 30 percent
-2-
50-397/97020-05
failure to set the flow switches to isolate RWCU prior to exceeding
a blowdown flow of 271.1 gpm
50-397/97020-06
failure to update the FSAR
50-397/97020-07
IFI
effectiveness of the licensee's FSAR upgrade program
50-397/97020-08
inadequate labeling ofradioactive material
Qllgyd
50-397/96002-01
50-397/96003-02
inadequate troubleshooting procedures for EDG HVAC
failure to draw a reactor coolant chemistry sample within 2-6 hours
following a power change of greater than 15 percent
50-397/96003-04
IFI
failure to update the Final Safety Analysis Report
50-397/96006-05
IF I
lack of work instructions for maintenance/cleaning
50-397/96026-04
failure of standby service water Pump 1A
50-397/96001-00
LER
inadvertent engineered safety feature actuation due to tripping
temporary power supply
50-397/96002-00
LER
inadvertent loss of power to vital bus and automatic start of
associated
50-397/96007-00
LER
electrical breakers not seismically qualified in test/disconnect
position
50-397/97001-00
LER
RWCU blowdown flow isolation setpoint above TS allowable
50-397/97002-00
50-397/97018-05
LER
rod block monitor calibration values not in accordance with
Technical Specifications
IFI
review of transient hydraulic loads on standby service water loop
piping
50-397/97020-01
inappropriate opening of the SM-3 PT fuse compartment
50-397/97020-02
failure of the electricians to read and adhere to the instructions on
the supply breaker's caution tag
-3-
50-397/97020-03
50-397/97020-04
failure of plant procedures and instructions to control the
configuration of the vital 4160V switchgear to ensure that its
seismic qualification was maintained
failure of the RBMs to be operable prior to exceeding thermal
power levels of 30 percent
50-397/97020-05
failure to set the flow switches to isolate RWCU prior to exceeding
a blowdown flowof 271.1 gpm
50-397/97020-06
failure to update the FSAR
LIST OF ACRONYMS USED
IEEE
IFI
LER'RC
Ol
PER
SCBA"
TAG
TS
WNP-2
as low as reasonably achievable
diesel generator
equipment operator
engineered safety feature
Final Safety Analysis Report
heating, ventilation, and air conditioning
electrical standard
inspection followup item
licensee event report
U.S. Nuclear Regulatory Commission
. operating instruction
problem evaluation request
Plant Procedures
Manual
potential transformer
rod block monitoring
self contained breathing apparatus
training advisory group
traversing in-core probe
Technical Specifications
unresolved item
Washington Nuclear Project-2
Ir.