ML17292B315
| ML17292B315 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 03/31/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17292B313 | List: |
| References | |
| 50-397-98-03, 50-397-98-3, NUDOCS 9804080246 | |
| Download: ML17292B315 (29) | |
See also: IR 05000397/1998003
Text
ENCLOSURE 2
U.S. NUCLEAR REGULATORYCOMMISSION
" REGION IV
Docket No.:
License No.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
50-397
50-397/98-03
Washington Public Power Supply System
Washington Nuclear Project-2
Richland, Washington
February
1 to March 14, 1998
S. A. Boynton, Senior Resident Inspector
G. W. Johnston, Senior Project Engineer
H. J. Wong, Chief, Reactor Projects Branch E
Attachment
Supplemental Information
9804080246
980331
ADOCK 05000397
6
EXECUTIV
S
RY
Washington Nuclear Project-2
NRC Inspection Report 50-397/98-03
~Oer'<~ion
Inadequate self-checking and peer checking resulted in an operator error that
deenergized
nonvital Bus SM-2 and started the Division III emergency diesel generator.
Operations personnel actions in response to the transient were appropriate and prompt.
The licensee's root cause analysis and corrective actions effectively addressed
the
human performance concerns (Section 01.1).
~
One instance was identified in which an operating crew did not demonstrate
a
conservative approach to equipment operation when a nonvital lighting panel, with an
unidentified ground, was reenergized without an understanding of the source of the
ground or a troubleshooting plan to identify the source (Section 01.2).
in
~
Poor material condition of the plant service water (TSW) system resulted in a leak that
challenged the integrity of the control room envelope as water was able to penetrate
through a concrete slab interface in the control room ceiling, a boundary credited by the
licensee's flooding analysis.
The licensee is currently implementing an improvement
plan that should adequately address the material condition deficiencies in theTSW
system (Section M2.1).
~Ei ~Igg
In reviewing the testing requirements for the standby gas treatment system, the
inspector identified the potential for the system floor drains to present a bypass pathway
'round
the filters. In response to the inspector's concerns, the licensee took appropriate
action to verify that the current leakage is acceptable,
and to develop a long-term
monitoring program for this potential unfiltered leakage path (Section E1.1).
Licensee personnel improperly applied surveillance requirement 3.0.2 to program
surveillances in the administrative section of Technical Specifications (TS). As a result,
a 25 percent surveillance interval extension was inappropriately utilized for several
technical programs (Section E8.2).
A number of deficiencies were identified in the implementation of the licensee's leakage
surveillance and prevention program.
Specifically, procedures for performing visual and
integrated leakage inspections on the standby gas treatment system, the containment
monitoring system (CMS), and the post accident sampling system (PASS), were
inadequate
in that they failed to identify all of the appropriate system components to be
monitored (Section E8.3).
-3-
~
Licensee corrective actions to address weaknesses
in implementing the transient
combustible control program have not been effective in addressing the root cause and
precluding repeat noncompliances with procedural requirements.
The root cause of
these noncompliances appeared to be a lack of understanding of fire protection
requirements and inattentiveness to fire protection labeling on the part of plant
personnel (Section F1.1).
e ort Details
fPI n
u
The plant began the inspection period at 100 percent power. On February 3, power was
reduced to 70 percent in response to a loss of electrical power to nonvital Bus SM-2. The loss
of electrical power resulted in the loss of one of the condensate/condensate
booster pump sets.
Following equipment restoration, the plant was returned to full power on February 4. On
March 1, power was reduced to 60 percent to facilitate investigation and repair of an apparent
tube leak in main condenser Waterbox C. Subsequent troubleshooting efforts were
unsuccessful
in identifying the leaking tube, and power was returned to 100 percent on
March 5.
On March 11, a failure of the instrument air line to main steam Line D inboard isolation valve
resulted in the inadvertent closure of the valve. The ensuing transient led to the closure of all of
the main steam isolation valves and a high flux reactor scram.
To facilitate troubleshooting and
repair of the broken air line, the licensee placed the plant in Mode 4 on March 12. The plant
remained in Mode 4 for the balance of the inspection period. The details of this event willbe
documented in NRC Inspection Report 50-397/98-05.
0 era ions
01
Conduct of Operations
01.1
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71
The inspector reviewed the licensee's Incident Review Board (IRB) report conclusions
and the recommended corrective actions of Problem Evaluation Request
(PER) 298-0102, following an inadvertent deenergization of Bus SM-2 on
February 3, 1998.
rva ion
n
The licensee conducted an IRB investigation of the February 3, 1998, deenergization of
Bus SM-2. The result of that IRB review showed that the event was principally due to
human performance induced error. The licensee's identified root cause was that the
reactor operator responsible for the event failed to "fullyinternalize the value of Peer
Checks and Self-Checking."
The event occurred during performance of PPM 2.7.1.A, "6900 Volt and 4160 VoltAC
Electrical Power Distribution System," to transfer Bus SM-1 from Transformer TR-N to
Transformer TR-S to support surveillance testing of Diesel Generator DG-1. The
actions before commencing the transfer included a prejob brief and a discussion of peer
checking.
Step 5.16.10 included action to "green flag" the TR-N/SM-1 Switch CB-N1/1.
The action to green flag a switch is to ensure the indicator flag on the switch agrees with
the lamp indication.
In the actions to transfer to TR-S, Breaker CB-S1 is allowed to
-2-
open automatically.
The switch flag, however,,does
not automatically reset.
Just before
the step,
the operator responded to an alarm on the adjacent panel.
When the operator
returned to the activity, he inadvertently opened the TR-N feeder breaker Switch CB-
N1/1 to Bus SM-2 rather than "green flagging" the CB-S1 switch. The action to green
flag a switch is the same action as manually opening the breaker.
This resulted in the
loss of Bus SM-2 and subsequent
tripping of major loads.
The inspector noted that the
, switches were side by side on the the control panel.
Following the inadvertent loss of Bus SM-2, several major loads in the secondary side of
the plant were lost. These included a condensate
pump and the associated condensate
booster pump. The loss of these two pumps required a prompt reduction of power, by
reducing recirculation flowfrom 100 percent of full power to approximately 65 percent.
A low voltage was also sensed
on Bus SMR, the Division III 4160V vital bus normally
supplied by SM-2, which resulted in a start of the Division III emergency diesel
generator.
From a review of the post event chart traces, the inspector determined that
the event did not compromise any operating limits. This was due to prompt action by
control room operators in reducing reactor power.
In the IRB report, the reviewers noted that the operator responsible for the event had
been under some personal stress and was tired at the time of the event. The inspector
discussed these aspects with the IRB chairman, observing that the IRB report described
these as "noncontributing" causes.
The IRB chairman stated that the individual involved
raised these points as possible contributors to his performance, and that the IRB
discounted them. The IRB interviews of other control room personnel and supervisors
found that the operator had not exhibited outward signs of stress or fatigue. The
operator had recently returned to shift duties from an extended assignment, which had
kept him from normal watch standing duties.
The IRB chairman further stated that
considerable change in control room conduct of operations had occurred over the period
before the operator's return to shift duties.
The chairman,
further, indicated his view
that the operator had not internalized the expectations involved in performing tasks
governed by procedure, especially with regard to self-checking and peer checking.
The licensee's immediate corrective actions included a station wide standdown on
February 3, 1998, to review this event and other recent personnel errors. An entry was
placed in the operations night orders referring to the stand down, reiterating
expectations regarding the contributing factors.
Shift managers were instructed to
evaluate crew members with regard to self-checking.
The operations manager stated
that the concept of peer checking had been emphasized
as a management expectation,
but had been left for each shift manager to implement.
This had led to variation in the
level of expectation and implementation.
Therefore, the operations manager directed
that management expectations with regard to peer checks be documented
in the
appropriate Operating Instructions.
'
Nuclear Safety Assurance Department (NSAD) quality department surveillance
report (298-014) indicated that an NSAD representative
observed the recovery from the
loss of SM-2.
The observer noted the operator logs did not mention that the chemistry
-3-
department was notified of the power reduction greater ttIan 15 percent.
Followup
inquiry by NSAD indicated that the plant laboratory chemistry supervisor believed that
operations notification was adequate.
No primary chemistry sample was taken, as the
noble gas release rate of 919.3 microcuries per second was below the sampling
requirement of greater than 15,000 microcuries per second.
The failure to properly perform PPM 2.7.1A, Revision 3, step 5.6.10, to "green flag" the
TR-N/SM-1 Switch CB-N1/1 was identified as a violation of Technical Specification (TS) 5.4.1.a, which requires, in part, procedures to be developed, implemented and
maintained for each of the surveillances directed by plant TS. This nonrepetitive,
self-revealing and corrected violation is being treated as a noncited violation consistent
with Section VII.B.1 of the NRC Enforcement Policy (NCV 50-397/98003-01).
Licensee
Event Report 50-397/98001-00, relating to the same event, is also closed.
~oui
Inadequate self-checking and peer checking resulted in an operator error that
deenergized
nonvital Bus SM-2 and started the Division III emergency diesel generator.
Operations personnel actions in response to the transient were appropriate and prompt.
The licensee's root cause analysis and corrective actions effectively addressed
the
human performance concerns.
o
L
s
0
The inspector reviewed the control room log and problem evaluation requests (PERs) on
a daily basis to evaluate the accuracy of the logs, and the actions taken by the licensee
in response to conditions identified.
t
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d
in in
Over the past several months the inspector identified several discrepancies
in the
control room logs that were generally administrative in nature (for example, wrong
individual identified as shift manager, wrong shift manager verifying log entries for a
shift). Although the errors were administrative, the errors made it difficultto determine
whether of one of the shift managers had maintained appropriate watch standing
qualifications. The inspector noted that the shift manager had not been routinely
assigned to the control room during the fourth quarter of 1997. The licensee reviewed
payroll records and interviewed personnel to verify the requirements of 10 CFR Part 55
had been satisfied.
The technical accuracy of the logs was noted to be very good.
On March 1, a control log entry was made for reenergizing a lighting panel in the turbine
building to support work in the condenser bay. This entry was noteworthy in that the
panel in question had an existing work request against it due to an unidentified electrical
ground.
Upon reenergizing the panel a 4-5 amp ground was noted on the supply
bus (MC-2D-A)to the lighting panel.
Subsequent
field walkdowns found the neutral
ground resistor for Transformer 2-21 to be very hot.
This inspector discussed this entry with the responsible shift manager and found that no
troubleshooting activities had been planned or performed to identify the ground prior to
reenergizing the panel.
The shift manager, in clearing the danger tag associated with
the supply breaker, made the assumption that the ground was due to one of the
mercury vapor lamps powered from the panel, based upon experience.
That experience
had shown historically that ifthe ground was in a lamp, the ground would be eliminated
when the lamp cooled down. The inspector disagreed with this approach in that the
decision to reenergize the lighting panel was based upon an assumption and not on
actual data for the existing condition. The result was a potential fire hazard and the
potential for damage to electrical equipment.
The impacted equipment was not safety-
related.
On March 8, control room operators identified what appeared to be an unexpected
oscillation transient on reactor feedwater Turbine B. The shift technical advisor (STA)
had also been touring reactor feedwater pump Room B at the time of the event.
According to the PER initiated for the event, the STA repeated his actions in the pump
room in an attempt to repeat the transient to see ifhe may have caused or contributed
to the event.
Further review by the licensee determined that the actions taken by the
STA were actually benign and that the PER did not accurately reflect those actions. The
inspector also noted that although the operating crew determined the event warranted
the initiation of a PER, no control room log entry was made to note it.
~ou~
The technical accuracy of the control room logs was found to be generally very good,
with the exception of the omission of a log entry for a feedwater turbine transient and a
few minor administrative errors.
One instance was identified in which an operating crew did not demonstrate
a
conservative approach to equipment operation when a nonvital lighting panel, with an
unidentified. ground, was reenergized without an understanding of the source of the
ground or a troubleshooting plan to identify the source.
Operational Status of Facilities and Equipment
rd
f
Fau
Walk
w
717 7
The inspectors walked down accessible portions of the following engineered safety
feature systems:
Reactor Core Isolation Cooling
Standby Gas Treatment, Trains A and B
0
1
t
I
~
II
-5-
Residual Heat Removal, Trains A, B, and C
Each of the systems was found to be properly aligned for the current operating mode.
No deficiencies were identified by the inspectors that had not already been identified by,
the licensee.
A review of plant logs and operating data indicated that system reliability
and availability remain well above maintenance
rule performance guidelines.
II
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a ce
M1
Conduct of Maintenance
a.
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7 6
The inspectors observed the followingwork activities:
~
OSP-HPCS/IST-Q701
High Pressure Core Spray (HPCS) System
Operability Test
~
WO¹ KRWO
Troubleshoot and Repair Instrument AirLine to
MS-V-22D
~
PPM 6.2.4
New Fuel Inspection
Each of the work activities was adequately implemented.
Radiological protection
practices during new fuel receipt inspections and the drywell maintenance
on
Valve MS-V-22D were appropriate.
The ALARAplanning and execution for the work in
the drywell was effective in minimizing the dose to workers.
Foreign material controls
were also properly implemented for these activities.
Operations performance during the high pressure core spray (HPCS) pump operability
test was adequate.
Proper peer checking was observed for control board
manipulations.
Three-way communications were not consistently utilized, contrary to
management
expectations.
The control room supervisor (CRS) authorized the stroking
of manual Valve HPCS-V-6 (HPCS keep-fill pump discharge check valve) out of
sequence
from the procedure.
This change to the order of the procedure was contrary
to the guidance in SWP-PRO-01, "Description and Use of Procedures
and Instructions,"
which states that procedure steps within TS surveillances should be performed in the
sequence
specified unless otherwise designated by the procedure.
Procedure OSP-PCS/IST-Q701
did not specifically authorize this practice.
The system
engineer that was monitoring the surveillance, noted the discrepancy and informed the
-6-
operators that the manual valve had to be stroked with the keep-fill pump operating.
The procedure steps were then repeated satisfactorily in the order specified.
Nlaintenance and Nlaterial Condition of Facilities and Equipment
M
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De icie cies in
In
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7
1
The inspector assessed
the licensee's actions to resolve a leak that occurred in the
service water system on the 525-foot elevation of the Radwaste Building. The inspector
also reviewed the licensee's assessment
of the leakage in PER 298-0157.
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On February 20, 1998, electricians were installing electrical conduits in an
Instrumentation and Controls shop, Room C510, on the 525-foot elevation of the
Radwaste Building. During the work, an electrician leaned on a 3/4-inch drain line from
a strainer on a TSW line to a room air conditioning Unit WRA-AC-52. The force applied
broke the pipe nipple, initiating a leak onto the floor. Water was unable to drain into a
local scupper because of an elevated lip. Subsequently, the water flowed out under the
door into adjacent spaces and then flowed into two floor drains. The electricians
initiated action to isolate the leak and informed the control room operators immediately.
Later, the control room operators noted the sound of dripping water in the ceiling
overhead.
An inspection by the system engineer noted that a small amount of water
had gone into the ceiling overhead space and had dripped onto the upper surface of the
ceiling tiles. The engineer noted that the leakage was coming from seams in the floor
slab from the construction joints in the concrete.
The inspector toured the affected area with the system engineer.
From the tour of the
spaces,
the, inspector noted that the floor slab appeared to have been poured during
construction in six separate
pours.
The boundaries between each slab were not cleanly
dressed or troweled. The inspector observed a fine crack between the slabs that
appeared sufficient for water to'penetrate and migrate. This was the apparent cause of
the leakage into the ceiling space above the control room.
A barrier impairment was issued for the floor surface for flooding protection because the
floor is a credited flooding boundary in the fire protection program. A work request
(WR 98000899) was initiated to apply a surface coat to the floor to provide an
impervious flooding boundary.
Immediate action included the staging of plastic sheeting
to provide protection to control panels in the control room.
It is unlikely, due to the
narrow nature of the cracks in the 525-foot floor slab, that substantial amounts of water
could flow into the control room ceiling overhead.
A similar configuration was also
identified for the 484-foot elevation of the Radwaste Building (cable spreading room),
resulting in the issuance of a barrier impairment for that elevation.
These actions
appeared appropriate in addressing the immediate concerns from possible flooding of
-7-
the 525-foot elevation.
The licensee initiated action to review other possible locations in
other buildings that may be similar to the concerns identified in the Radwaste Building.
The design requirement for flooding protection is in Tech Memo 2103, which was
generated for fire barrier analysis, and addresses
penetration seals.
The design
requirement is not identified in the Facility Safety Analysis Report.
Currently the floor is
required to maintain a 4-inch maximum standing water depth. The leakage through
joint cracks in the floor slab does not meet the requirement in the Tech Memo because
of the observed leakage.
The control room envelope integrity has been demonstrated
by surveillance testing and therefore meets the operability requirement in the TS.
However, because of the leakage into the control room, the envelope was considered
degraded due to the barrier impairment issued for the TSW leakage.
The system engineer for the TSW system indicated that a piping replacement program
is in place and a schedule has been developed identifying the portions of piping that are
to be replaced during each refueling outage.
Prioritization of the replacement was from
nondestructive examination and system importance.
The engineer stated the licensee's
goal is eventually to replace all affected piping. The piping replacement scheduled for
Refueling Outage R-13 is small bore supply and return lines to the main steam tunnel
coolers (RRA-CC-8 and 9). The reason for this replacement is that a leak in the main
steam tunnel could result in a plant shutdown.
Other actions to address the material
condition of the TSW piping include a silt/rust inhibitor system that ha's been added to
the system and plans to install an anti-biofouling injection system.
The silt/rust inhibitor
system is currently undergoing testing and troubleshooting.
C.
Poor material condition of theTSW system resulted in a leak that challenged the integrity
of the control room envelope as water was able to penetrate through a concrete slab
interface in the control room ceiling, a boundary credited by the licensee's flooding
analysis.
The, licensee is currently implementing an improvement plan that should
adequately address the material condition deficiencies in the TWS system.
II
En
E1
Conduct of Engineering
E11
si
of
S
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asTr
e
GT S
e
a.
I
i
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7
In reviewing the licensee's implementation of its leakage surveillance and prevention
program for the SGT system (see Section E8.3), the inspector reviewed the testing
performed on the system to ensure it meets its design requirements.
-8-
a ons
nd Findin
Licensee TS 3.6.4.3 requires the SGT system to be tested in accordance with the
Ventilation Filter Testing Program as described in TS 5.5.7. TS 5.5.7 requires the high
efficiency particulate air (HEPA) and charcoal filters of the SGT system to be tested in
accordance with ASME-N510-1989, "Testing of Nuclear AirTreatment Systems," to
demonstrate that penetration and system bypass is less than 0.05 percent.
The inspector reviewed the 1975, 1980, and 1989 versions of ASME-N510 and found
that each of the standards describes the methodology for testing the penetration and
bypass of the HEPA and charcoal filters. In the 1975 and 1980 versions of the standard
an appendix was included regarding the importance of in-place leak tests.
In these
versions it was stated that "an installed system can be assumed to have an efficiency
equivalent to that of the [factory tested charcoal] sample only if:...there are no leaks or
bypasses
in either the individual [charcoalj cells (factory tests) or the installed system
(field tests)." The 1989 version went further and included a specific testing method and
frequency for system bypass leakage.
The purpose of the test was described as
'ollows:
Systems using HEPA filters and adsorber banks may contain
bypass dampers, ducts, conduits, floor drains, pipe penetrations,
etc., which could potentially defeat the purpose of high efficiency
nuclear air treatment components.
Therefore, it is necessary to
perform tests which challenge all these potential bypass leakage
paths...
ASME N510-1989 recommends
a frequency of once per operating cycle for performing
the system bypass leakage test.
The inspector noted that the SGT filtertrain contains a number of fioor drains for
directing the flow of fire protection deluge water to the reactor building floor drain
system.
These drains are normally closed by means of a passive check valve in each
drain line. Several of the drains are located in the exhaust section of the filtertrain, and
as such, present a potential bypass leakage path ifthe check valve failed or was not
properly seated.
In questioning the licensee on testing of these valves, it was
determined that the licensee did not have a program for visually inspecting the valves or
a procedure to measure system bypass leakage from the floor drain system.
In response to the inspector's concerns, the licensee attempted to measure the air flow
into the common header of the SGT floor drain system to evaluate ifany of the check
valves may be leaking by their seat.
Measurements
made with a pitot tube velocimeter
at the outlet of the common drain header found that the air velocity into the header on
both trains was less than that detectable with the instrument (25 ft/min). The licensee
then estimated that leakage flow into the system, via the check valves, was less than
0.5 scfm. The leakage was well within the analysis assumption of 14 scfm.
-9-
Although the leakage rate past the check valves was found to be acceptable, the
inspector questioned the licensee on the need to test this leakage path on a periodic
basis as recommended
by ASME N510-1989.
The licensee reviewed the testing
requirements of the SGT system and did not identify any licensing basis for testing the
bypass flow path.
Specifically, in implementing the testing requirements of
ASME N510-1989, through TS 5.5.7, only testing of the in-place HEPA filters and
charcoal adsorbers
is required.
However, due to the potential consequences
of bypass
leakage, the licensee agreed that testing would be prudent. As a result, the licensee will
be implementing a periodic testing program for the SGT floor drains.
g~cu~si n.
In reviewing the testing requirements for the SGT system, the inspector identified the
potential for the system floor drains to present a bypass pathway around the filters. In
response to the inspector's concerns, the licensee took appropriate action to verify that
the current leakage is acceptable,
and to develop a long-term monitoring program for
this potential unfiltered leakage path.
Miscellaneous Engineering Issues (92903)
E8.1
I
v d
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9
1 -: lack of written safety evaluation for
removal of information from the fire hazards analysis (FHA) in the Final Safety Analysis
Report (FSAR). A more detailed review'of the changes made to the FSAR found that
the information removed from the FSAR was duplicated in the licensee's combustible
loading calculation.
In removing that information, the licensee also incorporated the
combustible loading calculation into the FSAR by specific reference.
Thus, changes to
the calculation would then be required to be evaluated under the requirements of
.10 CFR 50.59. The inspector found that no changes were made to the calculation in
conjunction with the removal of the information from the FSAR. Therefore, the removal
of the information, in and of itself, did not constitute a change to the facility and did not
require a written safety evaluation.
In response to a number of outstanding calculation modification reports, and several
concerns raised by the inspector, as documented
in NRC Inspection
Report 50-397/97-18, the licensee recently revised the combustible loading calculation.
The inspector verified that a written safety evaluation was performed to evaluate those
changes and the associated
changes to the FHA section of the FSAR.
E8.2
los
resolv d I em 5 -3 7/ 7
8- 4: inappropriate application ofTS4.0.2 to
.allow for a 25 percent extension to certain surveillance intervals. This item was opened
based upon the licensee's use of TS 4.0.2 when scheduling the integrated leakage
surveillances required by TS 6.8.4.a.2 for evaluating primary coolant leakage outside of
containment.
In resolving this issue, the licensee reviewed each of the 72 integrated
leakage surveillances performed, in accordance with TS 6.8.4.a.2, since initial operation.
The licensee found that the use of TS 4.0.2 resulted in 27 instances where the 18-month
surveillance interval was exceeded.
The licensee also found that TS 4.0.2 was applied
-10-
to TS 6.8.4.d.5.
TS 6.8.4.d.5 (Improved Technical Specification (ITS) 5.5.4.e) requires
every 31 days a determination of cumulative and projected dose contributions from
radioactive effluents for the current calendar quarter and calendar year. Although the
application of Surveillance Requirement (SR) 3.0.2 (old TS 4.0.2) is not explicitly
referenced,
a 25 percent extension has been routinely applied to this SR.
As noted in NRC Inspection Report 50-397/97-18, the licensee's implementation of ITS
now allows for the use of a 25 percent surveillance interval extension (SR 3.0.2) for
those surveillances required by TS 5.5.2 (equivalent to old TS 6.8.4.a).
The licensee determined that the root cause of the misapplication of TS 4.0.2
(SR 3.0.2) was personnel error in that there was a general misunderstanding of how
TS 4.0.2 (SR 3.0.2) applied to SRs in the Administrative Controls section.
Specifically, it
was not understood that application of TS 4.0.2 (SR 3.0.2) to surveillances under
administrative TS was not provided unless explicitly referenced.
In response, the
licensee developed a set of rules for determining the applicability of SR 3.0.2 to SRs
that are outside of Sections 3.1 through 3.10 of ITS. The inspector reviewed the
licensee's methodology and found that, ifproperly implemented, the rules would result in
the proper application of SR 3.0.2. The licensee has established
a corrective action to
train licensing personnel and program managers on this methodology.
To meet the 31-day interval requirement of TS 5.5.4.e, the licensee is determining the
cumulative and projected doses from radioactive eNuents twice each month until a TS
amendment
is approved to allow the application of SR 3.0.2.
The failure to perform the integrated leakage surveillances on an 18-month interval was
identified as a violation of TS 6.8.4.a.2 (VIO 50-397/98003-02).
The failure to determine
cumulative and projected dose contributions from radioactive effluents for the current
calendar quarter and calendar year every 31 days was identified as a violation of
TS 5.5.4.e (VIO 50-397/98003-03).
sed
U
esolve
e
50-397/97 18-0: undefined process for evaluating and
correcting leakage from the SGT system in accordance with TS 5.5.2.
requires that biennial leakage inspections and periodic visual inspections be performed
on those systems outside of containment that would contain highly radioactive fluids
following a postulated toss-of-coolant accident (LOCA). SGT is included as one of the
systems to monitor under TS 5.5.2.
However, PPM 1.5.6, "Leakage Surveillance and
Prevention Program," Revision 8, the licensee's procedure that implements the TS 5.5.2
program, did not define those components of SGT that need to be monitored for leakage
and did not provide for periodic visual inspections.
Subsequent
to the findings noted in NRC Inspection Report 50-397/97-18, the licensee
initiated a broad review of its implementation of the requirements of TS 5.5.2. This
review included the basis for which SGT is included as a system under TS 5.5.2, and
detailed reviews of the procedures that implement the inspection requirements, as
referenced by PPM 1.5.6.
-11-
SGT System:
Subsequent
evaluations by the licensee have been unsuccessful
in
determining the technical basis for the inclusion of the SGT system in TS 5.5.2.
In fact,
the licensee's original commitment to implementing the leakage surveillance and
prevention program, as described in the FSAR, did not list the SGT system as one of
the systems to be monitored.
In reviewing the operating characteristics of the system, the inspector found that the
system isolates from containment upon the initiation of a LOCA. The leakage from the
containment isolation valves is monitored through the licensee's inservice testing
program.
The only p'ortion of the system downstream of the containment isolation
valves in which leakage would be of concern appeared to be that section of the system
between the outlet of the charcoal filters and the inlet of the fans. Airin-leakage in this
portion of the system would be drawn in to the fans and would bypass the filter unit.
The licensee's analysis for evaluating offsite doses following a postulated LOCA
assumes that 14 scfm of unfiltered air is discharged by SGT. This takes into account
leakage from joints, valve packing, and the fans'haft seals.
The testing, performed
following initial installation of the system verified that the 14 scfm was a conservative
assumption.
The licensee plans to address visual inspections of the SGT system through a revision
to the routine operability surveillance procedures.
CMS: Concerns were also identified with the licensee's leakage monitoring of the CMS.
Prior to the licensee's implementation of ITS, PPM 7.4.6.3.4.2, "Excess Flow Check
Valve Test of Containment Atmosphere and Suppression
Pool Level," was being
credited for the biennial integrated leakage surveillance required by old TS 6.8.4.a.2
'(ITS 5.5.2). However, PPM 7.4.6.3.4,2 only verified operability of the CMS excess flow
check valves and checked for leakage at the containment penetration isolation and test
valves.
No leakage inspections were required for components downstream of the
excess flow check valve. Additionally, the inspector noted that PPM 7.4.6.3.4.2 was
canceled upon implementation of ITS and that a new procedure has not yet been
approved.
A new procedure to test the CMS excess flow check valves was in the review process at
the conclusion of the inspection.
The system engineer was also working with the
TS 5.5.2 program manager to determine what additional components would need to be
inspected as part of the biennial leakage surveillance.
PASS: Similar to the SGT system, a procedure had not been identified for performing
periodic visual inspections of the PASS system.
The licensee is in the process of
determining an appropriate mechanism and frequency for performing these inspections.
The licensee's biennial integrated leakage inspection is proceduralized in PPM
Revision 0, "Post Accident Sampling Leakage Surveillance." The
system engineer's review of this procedure identified a number of components within the
PASS system that are not evaluated during the biennial surveillance.
The components
included, but were not limited to, the isolation valves from the residual heat removal
-12-
system and sampling valves within the PASS sample rack. A revision to PPM
TSP-PASS-B801
has been initiated to incorporate the findings of the system engineer.
Conclusions:
The existing monitoring requirements for the other systems covered
under TS 5.5.2 were found to be generally adequate.
However, the failure of PPM 1.5.6
to adequately address the SRs of TS 5.5.2 for the SGT, CMS, and PASS systems was
identified as a violation of TS 5.4.1.e. (VIO 50-397/98003-04).
V
a
Su
o
F1
Conduct of Fire Protection Activities
F1.1
eciveA
i n
A
a'I
es
o
on
ITr
o
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ci
The inspector reviewed the licensee's actions to address several examples of
inadequate control of transient combustibles in the reactor building, as described in NRC
Inspection Report 50-397/97-18.
Several walkdowns of vital fire protection areas were
also performed to evaluate the adequacy of those actions.
s
F'i
NRC Inspection Report 50-397/97-18 identified several examples where the
requirements of PPM 1.3.10C, "Control of Transient Combustibles," were not followed
for transient combustible materials left in high radiation areas of the reactor building. In
response to the identified concerns, the licensee performed a root cause analysis and
has implemented a corrective action plan through the associated
PER': The plan
included the issuance of an e-mail message from the plant general manager to
department managers and a discussion between the operations manager and the
operations shift crews of the fire protection concerns.
Additional discussions between
the other department managers and their staffs are planned, but have not yet been
completed.
The licensee's root cause analysis identified weaknesses
in plant staff
knowledge of the requirements of PPM 1.3.10C.
Specifically, it was concluded that
plant staff may not have a clear understanding of what constitutes combustible material
that would require controls under PPM 1.3.10C.
However, the corrective action plan
only called for a review of the root cause and corrective actions for the associated
PER
in update training sessions.
No short-term actions were taken to focus the plant staffs
attention on the transient combustible permit process and the treatment of
combustible-free zones.
On February 18, the inspector identified unattended transient combustibles in a
safety-related instrument rack room on the 501-foot elevation of the reactor building.
The combustible materials were introduced into the room as a part of planned
maintenance activities that also established
a contamination zone and step-off pad in
-13-
the room. The instrument rack room is designated as a combustible-free zone in
accordance with PPM 1.3.10C. As such; unattended transient combustibles are not
allowed in this room. The licensee subsequently initiated PER 298-0144 to document
the procedure noncompliance.
The combustibles were removed from the room and a
transient combustible permit was issued by the plant fire marshal to allow for small
amounts of transient combustibles in the room with the requirement that they be
constantly attended.
On March 6, the inspector again identified unattended combustibles in the same
'nstrument
rack room. The transient combustibles (small plastic containers, tygon
tubing, and electrical multimeter) were apparently staged for an instrumentation and
controls surveillance.
The inspector attended the material until the shift support
supervisor (SSS) arrived. The SSS subsequently left the area without removing the
material or leaving another individual in attendance.
Although the inspector noted to
the CRS that the material found did not comply with the requirements of PPM 1.3.10C,
a PER was not initiated until the inspector discussed this concern with the fire protection
engineer on March 10.
The inspector noted that a sign was posted in the interior of the instrument rack room
indicating that the room is a combustible-free zone. The inspector also noted that the
transient combustible permit, issued following the concerns identified on February 18,
was posted in the stairwell adjacent to the room, but not readily visible to individuals
accessing the room. Both of the two occurrences identified by the inspector indicate
that plant personnel were not being attentive to fire protection program labeling and did
not understand the requirements of PPM 1.3.10C for what constitutes transient
combustible material. The failure of the SSS to constantly attend or remove the material
from the instrument rack room on March 6, and the failure of the CRS to initiate a.PER
for the procedure noncompliance, both underscore the concern.
They also indicate that
the licensee's actions to address personnel knowledge deficiencies in implementing the
transient combustible control program, in response to the concerns identified in NRC
Inspection Report 97-18, were inadequate to preclude repeat procedure
noncompliances.
The failure to take prompt and adequate corrective actions for
improper control of transient combustibles in the reactor building, a condition adverse to
quality, was identified as a violation of 10 CFR Part 50, Appendix B, Criterion XVI
(VIO 50-397/98003-05).
~Cnclusi
n
Licensee corrective actions to address weaknesses
in implementing the transient
combustible control program have not been effective in addressing the root cause and
precluding repeat noncompliances with procedural requirements.
The root cause of
these noncompliances appeared to be a lack of understanding of fire protection
requirements and inattentiveness to fire protection labeling on the part of plant
personnel.
-14-
V. Ma
a emen
eeti
s
X1
Exit Nleeting Summary
The inspectors presented the inspection results to members of licensee management after the
conclusion of the inspection on March 25, 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.
~LI en'
Supplemental Information
PARTIALLIST OF PERSONS CONTACTED
D. Coleman, Regulatory Affairs Manager
D. Giroux, System Engineering
D. Hillyer, Radiation Protection Manager
T. Hoyle, Engineering Programs
D. Kobus, Fire Protection
A. Langdon, Assistant Operations Manager
P. Inserra, Licensing Manager
S. Oxenford, Operations Manager
G. Smith, Plant General Manager
J. Kane, Acting Engineering Manager
R. Webring, Vice President Operations Support
INSPECTION PROCEDURES USED
IP 37551:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 92901:
IP 92902:
IP 92903:
Onsite Engineering
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support
Followup - Operations
Followup - Maintenance
Followup - Engineering
Qgg~ed
ITEMS OPENED, CLOSED, AND DISCUSSED
50-397/98003-01
50-397/98003-02
50-397/98003-03
50-397/98003-04
failure to properly perform PPM 2.7.1A
failure to perform the integrated leakage surveillances on
an 18-month interval
failure to determine cumulative and projected dose
contributions from radioactive eNuents for the current
calendar quarter and calendar year every 31 days
failure of PPM 1.5.6 to adequately address the SRs of
TS 5.5.2 for the SGT, CMS, and PASS systems
~
~
-2-
50<97/98004-05
failure to take adequate corrective actions for improper
control of transient combustibles in the reactor building
Qgged
50-397/98001-00
LER
voluntary report of automatic start of HPCS DG due to
operator error
50-397/98003-01
NCV.
'0-397/97018-03
failure to properly perform PPM 2.7.1A
undefined process for evaluating and correcting leakage
from the SGT system in accordance with TS 5.5.2.
50-397/97018-04
inappropriate application of TS 4.0.2 to allow for a 25
percent extension to certain surveillance intervals
50-397/97018-08
lack of written safety evaluation for removal of information
LIST OF ACRONYMS USED
IRB
LER
ITS.
NRC
PER
SR
TS
TSW
WNP-2
containment monitoring system
control room supervisor
Final Safety Analysis Report
high efficiency particulate air
incident review board
licensee event report
Improved Technical Specifications
loss-of-coolant accident
noncited violation
U.S. Nuclear Regulatory Commission
Nuclear Safety Assurance Department
post accident sampling system
problem evaluation request
Plant Procedures Manual
surveillance requirement
standby gas treatment
shift support supervisor
Technical Specifications
plant service water
unresolved item
violation
Washington Nuclear Project-2