ML17284A679
| ML17284A679 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 07/02/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17284A677 | List: |
| References | |
| 50-397-98-09, 50-397-98-9, NUDOCS 9807130346 | |
| Download: ML17284A679 (39) | |
See also: IR 05000397/1998009
Text
U.S. NUCLEAR REGULATORYCOMMISSION
REGION IV
Docket No.:
50-397
License No.: 'PF-21
Report No.:
Licensee:
Facility:
Location:
Dates:,
Inspector(s):
Approved By:
50-397/98-09
Washington Public Power Supply System
Washington Nuclear Project-2 --
Richland, Washington
April26 through June 6, 1998
S. A. Boynton, Senior Resident Inspector
J.
E. Spets, Resident Inspector
G. W. Johnston, Senior Project Engineer
G. M. Good, Senior Emergency Preparedness
Inspector
S. C. Burton, Resident Inspector, ANO
C. E. Skinner, Resident Inspector, CNS
H. J. Wong, Chief, Reactor Projects Branch E
AiTACHMENT:
Supplemental Information
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9807i30346 980702
ADOCK 05000397
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Washington Nuclear Project-2
NRC Inspection Report 50-397/98-09
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The routine shutdown for Refueling Outage R13 was properly executed with a detailed
preevolution brief and good command and control.
Operations performance in
monitoring and controlling the cooldown was improved over that observed during the
March 1998 forced outage (Section 01.1).
ai
Both the reactor disassembly and the fuel shuffle were generally well executed between
the control room and the refueling floor. However, two instances of weak procedure use
resulted in: 1) the failure to identify an incorrect precaution in the maintenance
procedure for the reactor building overhead crane, and 2) failure to verify that
appropriate minimum temperature requirements were being met prior to liftingthe
drywell upper shield blocks (Section M1.2).
The licensee's actions to address previously-identified weaknesses
in implementing
their foreign material controls (FMC) program for plant systems and containment have
been effective in raising the sensitivity and improving performance of plant personnel
(Section M1.3).
Licensee performance in implementing FMC for the spent fuel pool, reactor cavity and
reactor pressure vessel (RPV) was mixed. Weaknesses
were identified mainly in the
administrative controls of foreign materials.
These included the failure to perform
inventories of the spent fuel and equipment pools prior to removal of the RPV head.
The failure to perform the inventories eliminated an objective measure of the
effectiveness of FMC and was identified as a noncited violation of Plant Procedure 6.1.1
(Section M1.3).
Personnel performance in the conduct of testing excess flowcheck valves was
inadequate,
as evidenced by: 1) multiple examples of poor procedural adherence
and
procedure adequacy, 2) personnel knowledge deficiencies on testing requirements and
plant impact, 3) weak use of procedures in the field, and 4) weak command and control.
In one case, performance deficiencies resulted in the initiation of an engineered safety
features actuation signaI and plant transient.
Two violations of TS 5.4.1.a, each with
two examples, were identiTied regarding adequacy and use of surveillance procedures.
The violations included inadequate procedure guidance for establishing and restoring
from test conditions and failure to independently verify a valve location prior to valve
manipulation (Section M1.4).
The Division I emergency diesel generator (EDG) experienced multiple material
deficiencies during Refueling Outage R13 which resulted in several failures to run and/or
load. The material deficiencies included:
(1) the failure of the mechanical. governor'
-3-
motor operated potentiometer, (2) failure of the lube oil low pressure switch to reset, and
(3) failure of the diesel generator output breaker to close due to improper setting of the
breaker's trip latch check switch. The licensee's short-term corrective actions for the
failures were appropriate.
Long-term actions willbe reviewed in future inspection
activities (Section M1.5).
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~
During the fuel shuffle, the licensee accepted the condition of a partially elevated fuel
. assembly in the spent fuel pool without fullyevaluating its impact. Weak understanding
and review of the plant's design basis failed to identify that full insertion of the spent fuel
assembly is a condition of the spent fuel criticality analysis described in the Final Safety
Analysis Report (FSAR) (Section M1.2).
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~
The licensee decreased
the effectiveness of its emergency plan between February 1997
and April 1998, when it reduced on-shift health physics expertise and overburdened the
chemistry technician with health physics responsibilities during emergencies.
A violation
of 10 CFR 50.54(q) was identified. The licensee returned a third health physics
technician to on-shift following notification of the noncompliance (Section P3).
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The plant began the inspection period in Mode 5, with core alterations in progress.
Upon
completion of in-vessel maintenance,
reactor pressure vessel reassembly was completed and
the plant reentered Mode 4 on May 27. The plant remained in Mode 4 for the balance of the
inspection period.
0 ea
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01
Conduct of Operations
01.1
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a.
777
The inspectors observed portions of the reactor plant shutdown and cooldown in
preparation for Refueling Outage R13. Focus of the inspection was on command and
control of the evolution and procedural implementation.
b.
b
ai
Reactor shutdown was commenced on April 18, in accordance with Plant
Procedure 3.2.1, Revision 32, "Normal Shutdown to Cold Shutdown." The preevolution
brief was observed and found to be sufficiently detailed to establish proper expectations
for the significant actions to be performed.
Senior management presence
in the control
room was noted.
RPV cooldown and initiation of shutdown cooling were properly executed with notable
improvement on the control of the cooldown as compared to the forced outage in March
1998. Weak control of RPV cooldown'during the March forced outage led to changes
in
Plant Procedure OSP-RCS-C102,
"RPV Cooldown Surveillance." The changes,
including a higher resolution pressure-temperature
curve and the addition of a table of
minimum temperature versus pressure, were considered an effective component in
controlling the R13 coo!down evolution.
The inspectors noted that Plant Procedure 4.12.1.1, Revision 9, "Control Room
Evacuation and Remote Cooldown," was not revised to include similar enhancements
for controlling cooldown. Also, discrepancies were identified between the pressure and
temperature limits provided in Attachment 8.1 of Procedure 4.12.1.1, those in
Procedure
andTechnicalSpecifications(TS).
However, thelimitsin
Procedure 4.12.1.1 were more restrictive than those in TS and, therefore, the
discrepancy was not considered safety significant. The inconsistencies between
Attachment 8.1 of Procedure 4.12.1.1 and Procedure OSP-RCS-C102 and TS, indicated
a weakness
in the licensee's procedure maintenance process.
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'
-2-
The routine shutdown for Refueling Outage R13 was properly executed with a detailed
preevolution brief and good command and control.
Operations performance in
monitoring and controlling the coo!down was improved over that observed during the
March 1998 forced outage.
02
02.1
Operational Status of Facilities and Equipment
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The inspectors walked down accessible portions of the following EFS:
Low Pressure Core Spray
Division I EDG and Starting Air
Standby Service Water A
b.
Oserv
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'd'he
focus of the walkdowns was on Division I systems which received the majority of
maintenance during Refueling Outage R13. System configurations for operability were
verified following system restoration from maintenance.
No discrepancies were
identified. Licensee-identified material condition concerns with the Division I emergency
diesel generator are discussed
in Section M1.4.
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M1
Conduct of Maintenance
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The inspectors. observed and/or reviewed the following work activities:
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WO¹ HNJ8
SLC-RV-29A Replacement
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WO¹ LHK3
Removal and Testing of Relief Valve RHR-RV-25C
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WO¹ LHF3
Removal and Testing of Relief Valve RHR-RV-30
WO¹ JBY3
Calibration of Diesel Lube Oil Level Switch DLO-LS-1A1
Additional niaintenance activities were observed and are discussed
in Sections M1.2
through M1.7.
1
-3-
b.
bserv
Proper use of FMC was noted in each of the activities observed.
Where appropriate,
adequate radiological controls and practices were noted.
During observations of the replacement of the RHR relief valves, the inspectors noted
that the workers were not documenting their progress in the field copy of the work order.
Although no discrepancies were noted with performance of the activities, placekeeping
. is a management expectation.
Failure to track work progress in the field was also
observed during testing of excess flow check valves (see Section M1.4) and, in one
instance, resulted in a partial reactor protection system actuation.
Following the installation of relief Valve SLC-V-29A, the inspectors observed sodium
pentaborate solution leaking from the bonnet cap of the valve. Valve SLC-V-29A
provides overpressure
protection of the standby liquid control (SLC) system piping
downstream of the positive displacement SLC pump. The discharge of the relief valve
returns to the suction of the pump. The leakage observed was a result of both stroke
testing of, and minor leakage past the SLC tank outlet Valve SLC-V-1A. The leakage
path was via the suction piping of the SLC pump, to the discharge of relief
Valve SL'C-V-29A', and to the valve bonnet.
From a maintenance perspective, the
leakage was of concern in that neither the work order, nor the worker involved,
recognized the need to properly torque the valve's bonnet cap due to the installation
configuration.
From a safety perspective, the'impact of the leakage was indeterminate.
However, over time with the condition remaining uncorrected, the potential existed for
sodium pentaborate to precipitate in the valve bonnet and affect the valve's operation.
To address the leakage concerns, the licensee properly tightened the valve bonnet and
initiated a change to the valve's setpoint data sheet to identify the requirement of
tightening the bonnet after valve installation. With the bonnet properly tightened, the
licensee also quantified the leakage past the SLC tank outlet valves and determined that
the leakage was small, but acceptable.
The inspectors reviewed the licensee's
justification for accepting the leakage and found it to be technically sound.
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FMC and practices were properly implemented in each of four maintenance activities.
Weak tracking of work progress in the field was noted in several instances and was a
generic problem during Refueling Outage R13, as noted in Section M1.4. In not
recognizing the impact of having the SLC pump relief valve discharge return to the
pump's suction, maintenance personnel failed to properly tighten the valve bonnet
resulting in system leakage.
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277
b.
The,ihspectors observed portions of the reactor disassembly process and the fuel
shuffle. Inspection emphasis was on equipment rigging, FMC, radiological protection,
and command and control.
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The inspectors observed the following evolutions, as. described in Plant
Procedure 10.3.21, Revision 3, "RPV Disassembly:"
Drywell shield plug removal
Drywell head removal
RPV head lift
Dryer/separator removal
Reactor cavity flood-up
The inspection results of the licensee's FMC associated with the reactor disassembly
are discussed
in Section M1.3.
Overall, the reactor disassembly was well coordinated between operations and the
refuel floor coordinator. With the exception of the inadvertent loss of a drywell head nut
in the fuel pool cooling drain system for the reactor-cavity, few operational challenges
arose during the evolution. However, several procedural concerns were identified.
Following the liftof the first two upper shield blocks, the inspectors questioned, rigging
personnel on the refueling floor regarding the temperature prerequisites for performing
the lifts. Personnel indicated that the temperature on the refueling floor must be greater
than 55'F.
Plant Procedure 10.4.12, Revision 9, "Crane, Hoist, Lifting Device and
Rigging Program Control," requires, when using the overhead crane (MT-CRA-2), that
temperature be greater than 64'F prior to liffingloads of greater than 50 tons. If
temperature is below 64'F, Procedure 10.4.12 requires that the RSE be contacted.
The
weight of each of the upper shield blocks is approximately 100 tons. Although the use
of Procedure 10.4.12 is referenced. in the precautions and limitations for control of heavy
loads, refuel floor personnel were unfamiliar with the more restrictive temperature
requirement.
As local temperature indication was unavailable on the refuel floor, reactor
building supply air temperature was requested from the control room and was
determined to be 55'F, below the minimum requirements for liftingthe upper shield
blocks.= The RSE had not been contacted prior to the initial lift. Subsequently,
the
refueling fioor personnel obtained a contact pyrometer and determined that ambient
temperature on the refueling floorwas 66'F.
-5-
From discussions with the RSE, it was determined that the limitingtemperature of 64'F
was based upon temperatures
utilized in fracture toughness testing of the material
utilized for the overhead crane's main girders.
Thus, use of the crane at lower
temperatures
potentially places the crane in an unanalyzed condition. However, the
RSE indicated that safety margins for the overhead crane would not be significantly
impacted by the conditions noted by the inspectors.'The
RSE's conclusion that the
safety significance of the issue was low appeared to be reasonable.
The precautions
and limitations of Procedure 10.3.21 were revised to include the temperature limits of
Procedure 10.4.12. The failure to verify that the'refuel floortemperature was within the
, limits of Procedure 10.4.12 was identified as a violation of TS 5.4.1.a
(VIO 50-50397/9800-01).
Prerequisites of Plant Procedure 10.4.5, Revision 4, "Reactor (MT-CRA-2) and Turbine
Building (MT-CRA-1) Overhead Traveling Crane Inspection, Maintenance and Testing,"
require the verification that caution Tag 95-03-066 has been placed on the local
disconnect switch for MT-CRA-2, located on the refuel floor. The caution tag was
desigried to warn personnel of potential overload concerns for Motor Control
Center E-IVIC-7CBwhen the local disconnect is closed. A review of the licensee's active
clearance order log found that caution Tag 95-03-066 was cleared and no longer
hanging on the local disconnect.
From subsequent discussions with operations
personnel it was determined that the caution tag was replaced with caution labels at
E-MC-7CB. Although Procedure 10.4.5 was performed prior to reactor disassembly, the
erroneous reference in the procedure was not brought to the attention of the site rigging
coordinator, nor was it corrected.
This was considered a weakness
in procedure use.
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Execution of the greater than 1000 movements associated with the fuel shuNe was
accomplished without error. The licensee's implementation of the requirements of Plant
Procedure 6.3.2, Revision 13, "Fuel Shuffling and/or ONoading and Reloading," was
independently verified. Good command and control was demonstrated
by both the
control room and the refueling supervisor throughout the evolution. Although several
malfunctions. of the refueling bridge crane were experienced, the problems were
appropriately'addressed
prior to resumption of fuel movement.
Qualification of the
personnel involved was spot-checked and verified.
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One weakness was identified in Section 6.5 of Procedure 6.3.2.
Prior to withdrawing a
high worth control rod for a subcritical check, Step 6.5.6 states that fuel movement
should be suspended.
-The use of the term "should," which allows flexibilityin.
implementing the procedural step, is inconsistent with the requirements of-TS 3.9.3,
"Control Rod Position." Specifically, TS 3.9.3 rabies fuel movement into the core be
suspended
when one or more control rods are withdrawn. The inspector reviewed the
licensee refueling activities and found that Section 6.5 of Procedure 6.3.2 was not
utilized during the outage.
-6-
Potential foreign material concerns were noted in the spent fuel pool during the
movement of fuel. Specifically, three separate fuel assemblies,
including one Asea
Brown Boveri (ABB) SVEA-96'assembly, were identified that would not fullyinsert into
their storage rack location. The tops of each of the assemblies were between 2 and
3 inches higher than adjacent assemblies that were fullyinserted.
Without-a detailed
investigation, the licensee had concluded that objects at the bottom of the racks were
preventing the full insertion of the assemblies.
The licensee believes that the objects
are likelyfuel channel fasteners, which would not adversely impact cooling of the spent
fuel.
In reviewing Problem Evaluation Request (PER) 298-0424, which documents the
condition of the three fuel assemblies,
it was noted that the licensee had no operability
concerns due to the fact that the assemblies were not in the core and did not pose
.interference concerns with movement of other fuel. The fuel assemblies were left in
their as-found condition. The inspectors discussed the as-found condition with the
licensee's engineering personnel responsible for the spent fuel pool criticality analyses,
focusing on the impact of the condition on the analyses.
From that discussion, the
inspectors determined that the licensee had not identified inconsistencies
between the
as-found condition and the parametric requirements of the ABB criticality analysis
described in Section 9.1 of the Final Safety Analysis Report (FSAR). Section 9.1.2.3.1.2
states, in part, that the criticality safety of the spent fuel storage rack, with SVEA-96 fuel,
is assessed
subject to the condition that, when stored, the fuel assemblies must be fully
inserted into the fuel storage boxes.
Although the ABB SVEA-96 fuel assembly did not
meet the analyzed condition of Section 9.1.2.3.1.2, the bundle was neither relocated to
another storage rack location, nor was an evaluation performed to document the
acceptability of the as-found condition.
Subsequent to the discussion, the licensee reviewed Section 9.1 of the FSAR and
agreed that an evaluation was required for leaving the ABB assembly in its abnormal
condition. A followup assessment
of operability was performed that demonstrated,
with
the fuel assembly partially elevated, the reactivity, described in terms of k-effective,
would be less than 0.9 (design limitis 0.95 k-effective). The licensee's operability
evaluation was found to be technically sound and the safety significance of the issue
was considered low. However, the failure of the licensee to promptly identify and
address the discrepancy between the condition of the fuel assembly and the
assumptions of the spent fuel pool criticality analysis indicated a weak understanding
and review of the plant's design and licensing basis.
The failure to properly identify and
address the condition, without prompting from the inspectors, was identified as a
violation of 10 CFR Part 50, Appendix B, Criterion XVI,"Corrective Actions"
(VIO 50-397/98009-02).
>i~cu.'~on
Both the reactor disassembly and the fuel shuffle were generally well executed between
the control room and the refueling fioor. However, two instances of weak procedure use
resulted in: 1) the failure to identify an incorrect precaution in the maintenance
-7-
procedure for the reactor building overhead crane, and 2) failure to verify that
appropriate minimum temperature requirements were being met prior to liftingthe
drywell upper shield blocks.
During the fuel shuffle, the licensee accepted the condition of a partially elevated fuel
assembly in the spent fuel pool without fullyevaluating its impact. Weak understanding
'nd
review of the plant's design basis failed to identify that full insertion of the spent fuel
assembly is a condition of the spent fuel criticality analysis described in the FSAR.
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The inspectors observed or reviewed selected maintenance activities during the plant's
1998 refueling outage (R13) to evaluate the licensee's implementation of its FMC
program.
The scope of the inspection activities was adequate to address NRC
Inspection Followup Item 50-397/97009-02.
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Overall, the implementation of FMC on the refueling floorwas acceptable.
However,
several lapses in FMC resulted in operational challenges and procedural
noncompliances.
At the beginning of the reactor disassembly evolution, it was observed that the refueling
bridge was not properly posted as an FMC area boundary.
Specifically, the stairs
leading onto the refueling bridge were not posted while the bridge was within the spent
fuel pool FMC area.
The lack of a visible posting could have allowed access to the
bridge without implementing the proper FMC requirements.
This was considered a
weakness
in implementing Plant Procedure 1.3.18, Revision 15, "FMC Around the Spent
Fuel Pool, the Reactor Cavity and the Dryer Separator Pit," which provides, in part,
guidance on posting of the FMC area boundary.
Other weaknesses
in implementing
Procedure 1.3.18 were:
'he
refueling bridge provides two separate personnel access points into the
FMC area, contrary to the guidance in Procedure 1.3.18 which states that the
FMC boundary should have a single opening.
I
Routine audits of the spent fuel pool FMC log were not being performed during
nonoutage periods as outlined in Procedure 1.3.18.
It was also identified that the licensee had failed to perform an inventory of the spent
fuel and equipment pools prior to removal of the RPV head.
This inventory is required
by Plant Procedure 6.1.1, Revision 4, "Spent Fuel and Equipment Pools Inventory," to
-8-
establish a baseline of material in the pools and provide confidence that the material
was not introduced into the RPV while the vessel head was removed.
Without a baseline inventory for the Refueling Outage R13, the inspectors reviewed the
documented inventories performed in the Refueling Outage R12.
In reviewing those
inventories, it was noted that the number of control rod blades inventoried prior to RPV
head removal was 32, while the number inventoried after RPV head reinstallation was
31.Resolution of the discrepancy was not documented in the latter inventory. From
discussions with the engineer who performed both inventories, the discrepancy
. apparently resulted from'personnel error in documenting the second inventory.
Subsequently, the engineer verified that the second inventory should have shown a total
of 32"control rod blades.
Both the error and the failure to identify it during review
reduced the value of the inventories in supporting FMC. The failure to perform the spent
fuel and equipment pool inventories prior to removing the RPV head during Refueling
Outage R13 did not result in a loss of control of foreign materials.
This failure
constitutes a violation of minor significance and is being treated as a noncited violation,
, consistent with Section IVof the NRC Enforcement Policy (NCV 50-397/98009-03).
Weaknesses
were also noted in work practices for the prevention of introducing foreign
materials into the spent fuel pool, reactor cavity, and the RPV.
~
During removal of the drywell head, one of its fastener nuts was inadvertently
kicked into a reactor cavity drain line. Retrieval of the nut required significant
resources and resulted in an additional cumulative outage dose of
0.32 person-rem.
During removal of the RPV head, an o-ring retaining clip was lost in the vessel.
Also, during core shroud weld inspections, damage to the inspection equipment
resulted in the loss of a small spring and several ball bearings into the RPV. As
retrieval was not practical, the licensee performed a loose parts evaluation to
determine the potential impact of the foreign material during plant operation.
The licensee concluded that the material did not present a safety concern.
The
,inspectors reviewed the licensee's analyses and found the conclusions to be
acceptable.
or
Sse
During inspection activities involving maintenance of breached systems, the inspectors
observed the implementation of FMC in accordance with Plant Procedure 10.1.13,
Revision 15, "FMC For Systems And Components."
FMC for systems and components
were noted to be improved over Refueling Outage R12. Adequate controls were being
implemented in all activities observed.
A selected review of completed work orders also
noted that system closeout inspectioris were being performed, an area where
weaknesses
were identified in 1997 (Refueling Outage R12).
-9-
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The inspectors conducted three separate tours of the drywell and one tour of the wetwell
to assess
both material condition of structures, systems, and components in the areas
and control of foreign material.
One of the inspections included the drywell closeout
tour,. Overall, the licensee's efforts to control foreign materials in the containment were
effective. Although the licensee identified several discrepancies
in foreign material
accountability process, the licensee's cleanup efforts in the drywell adequately
compensated for any shortcomings in the accountability of materials.
The drywell
. closeout inspection verified that the cleanup efforts were effective and found that
performance in this area continued to improve over past outages.
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I'he
licensee's actions to address previously identified weaknesses
in implementing their
FMC program for plant systems and containment have been effective in raising the
sensitivity "and improving performance of plant personnel.
Inspection Followup
Item (IFI) 50-397/97009-02 is closed.
Licensee performance in implementing FMC for the spent fuel pool, reactor cavity, and
RPV was mixed. Weaknesses
were identified mainly in the administrative controls of
foreign materials.
These included the failure to perform inventories of the spent fuel and
equipment pools prior to removal of the RPV head.
The failure to perform the
inventories eliminated an objective measure of the effectiveness of FMC and was
identified as a noncited violation of Plant Procedure 6.1.1.
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The inspectors observed and/or reviewed surveillance testing of several EFC valves to
evaluate the adequacy of the procedures, the performance of personnel involved, and
performance of equipment.
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The following surveillances were reviewed:
ISP-EFC-B102, Revision 1, Testing EFC Valves For Main Steam Leakage
Control
ISP-EFC-B103, Revision 0, EFC Valves Testing of Jet Pump, RPV Drain and
Core Plate Flow
~
ISP-EFC-B108, Revision 0, EFC Valve Test of Containment Atmosphere And
Suppression
Pool Level Instrument Sensing Lines
-10-
ISP-EFC-B108:
On May 19, while performing Plant Procedure ISP-EFC-B108, an
unexpected half-scram was initiated.
In reviewing the cause of the scram signal, the
licensee determined that in performing testing on EFC 62b, the instrumentation and
controls (l&C)technicians had not properly isolated an associated
reactor protection
system pressure switch in accordance with the procedure.
The failure to isolate the
switch was due to a combination of miscommunications between the l&Ctechnicians
and inadequate tracking of,surveillance progress on the field copy of the procedure.
Through discussions with the Maintenance Manager and the I&C Supervisor it was
determined that procedure placekeeping is a management expectation.
The failure to
. properly implement the requirements of Plant Procedure ISP-EFC-B108 was identified
as the first example of a violation of TS 5.4.1.a (VIO 50-97/98009-04).
ISP-EFC-B102:
On May g6, during a routine plant tour, the inspectors observed
technicians performing testing on EFC 18B utilizing Plant Procedure ISP-EFC-B102. A
number of discrepancies were identified with regard to p'ersonnel knowledge and
performance iri implementing the procedural requirements:
II
The I&Ctechnician operating the test cart was unable to identify the required
pressure to be maintained while testing the EFC (85 -110 psi).
In fact,
inattention on the part of the technician allowed the air-operated test pump to
raise test pressure to 60 psi above the required band, as noted on the pressure
gage initiallyby the inspector.
Contrary to the guidelines of Site Wide Procedure
SWP-PRO-1, Revision 1, "Description and Use of Procedures and Instructions,"
Step 3.6.3.e, the l8C technician did not have a copy of the governing test
procedure for reference.
Additional review of Procedure ISP-EFC-B102 identified that the demineralized
water system header is stipulated to be utilized as the water source for testing
EFC 18B. The use of the air-operated test pump is not described as an option.
The steps of Procedure ISP-EFC-B102 that specifically require the connection of
the demineralized water header were initialed as being completed, as written,
without clarifying comments on the use of the test pump. Subsequent
discussions with I&Csupervision indicated that the technicians had utilized the
test pump because they, were unable to obtain the required test pressure with
the demineralized water header.
It was also indicated that this was a
non-proceduralized,
accepted practice. The inspector reviewed the operating
characteristics of the demineralized water system and determined that, in fact,
the system could not provide the required pressure for performing the test. The
failure of Procedure ISP-EFC-B102 to specify the need for a water source other
than the demineralized water header for testing EFC 18B was identified as the
first example of a violation of TS 5.4.1.a for inadequate procedure
(VIO 50-397/98009-05).
A second I&Ctechnician, responsible for manipulating valves downstream of the
EFC'to stroke the valve closed, failed to ensure that an independent veriTication
was performed prior to'anipulation of the valves. Additionally, although the
~
~
second technician did have a copy of the governing procedure, he was not
documenting the progress of the surveillance on his copy. The failure to
implement the independent verification requirements of
Procedure ISP-EFC-B102 was identified as the second example of a violation of
TS 5.4.1.a (VIO 50-397/98009-04).
~
.
The lead technician for controlling the testing, located in the control room, was
not fullycognizant of actions being taken in the field by the other technicians.
Command and control of the evolution was weak as evidenced by differing
perceptions on the part of the technicians involved as to where they were in the
test procedure.
Specifically; the lead technician believed that, at the time of the
inspector's observations, the surveillance test was in progress.
Contrary to that
perception, the technicians in the field believed they were still troubleshooting the
failure of the valve's closed position indication that was identified a day earlier.
The failure of the maintenance personnel to track their progress in the field copies of the
governing procedure was a recurring problem in both of the above surveillances and has
been identified as a potential generic problem by the licensee's maintenance
'rganization.
Followup discussions with the maintenance manager and I&Csupervisor
found that the number of discrepancies
identified for the testing of EFC 18B were
attributable to several factors. These included field troubleshooting of the valve that was
performed outside of the 'defined requirements of the procedure and without an
approved troubleshooting plan and weak control of the evolution by the lead technician
in the control room.
ISP-EFC-B103:
On May 30, during backfill operations of the instrument lines
associated with EFC Valves 44Be and 44BI, an unexpected engineered safety feature
(ESF) actuation and scram were initiated. The ESF actuation resulted in the automatic
start of both the Division I and Division III emergency diesel generators (EDGs), and the
initiation of Division I (low pressure core spray and low pressure coolant injection A) and
Division III (high pressure core spray (HPCS)) emergency core cooling systems
(ECCS).
Both Division I ECCS pumps injected into the vessel.
The HPCS pump did not
start due to removal of the control power fuses to its associated
motor supply breaker.
This configuration was consistent with.plant conditions at the time of the event.
In response to the transient, operators secured the operating control rod drive pump to
limitthe pressure rise in the RPV. -.Following verification that the ESF signal was invalid,
operators also secured the Division.l ECCS pumps.
During the transient, RPV pressure
increased from initially100 psig to a maximum of 425 psig, approximately the shutoff
head of the low pressure ECCS pumps.
RPV temperature and pressure remained
within allowable limits. The operating crew's actions were timely and appropriate.
Subsequent
investigation ofthe transient by the licensee determined that the cause of
the event was an improper lineup to backfill the instrument lines associated with EFC
Valves 44Be'and 44BI. Plant Procedure ISP-EFC-B103, which governs the backfill of
these instrument lines followin'g testing of the check valves, did not provide adequate
g r..
-12-
guidance on the location of the backfill injection point. Recognizing the lack of specificity
in the procedure, the l8C technicians performing the evolution concluded that they
should backfill the instrument lines from each of the three instruments supplied by EFC
Valves 44Be and 44BI. The 18C'technicians did not reference a piping and
instrumentation diagram when determining the appropriate backfill lineup(s) to be used.
As such, they failed to recognize that, in backfilling the low side of level
Transmitter MS-T~A, they would be backfilling a reference leg that was shared by
several other Division I and Division Ill,instruments. When the air-operated pump was
utilized to backfill the low side of MS-LT-44A, the pressure perturbations from the pump
. action were transmitted to the other instruments, generating erroneous outputs to ESF
actuation relays. The inspector concluded that both inadequacies
in
Procedure ISP-FC-103 and an over-reliance on skill-of-the-craft knowledge for-
backfilling the instruments contributed to the event. The failure of
Procedure ISP-FC-B103 to identify the specific lineup for backfilling Valves EFC 44Be
and 44BI was identified as the second example of a violation of TS 5.4.1.a for
inadequate procedure (VIO 50-397/98009-05).
c.
QoOnclusl
s
Personnel performance in the conduct of testing EFC valves was inadequate,
as
evidenced by: (1) multiple examples of poor procedural adherence and procedure
adequacy, (2) personnel knowledge deficiencies on testing requirements and plant
impact, (3) weak use of procedures in the field, and (4) weak command and control.
In
one case, performance deficiencies resulted in the initiation of an engineered safety
features actuation signal and plant transient.
Two violations of TS 5.4.1.a, each with
two examples, were identified regarding adequacy and use of surveillance procedures.
The violations included inadequate procedure guidance for establishing and restoring
from test conditions, and failure to independently verify a valve location prior to valve
manipulation.
M1.5
iv sion
I
0 d
a.
s eci
o
62
The inspectors observed and/or reviewed the following work activities:
~
OSP-ELEC-M701, Revision 2, Diesel Generator
1 - Monthly Operability Test
~
TSP-DG1/LOP-B501, Revision 0, Standby Diesel Generator DG1 Loss of Power
'est
~
Plant Procedure 10.25.122, Revision 4, Locating and Identifying DC Distribution
System Grounds
-13-
bse
aio
d
i di
s
oor-0 er edPoenio
ee
F 'lu
On May 2, 1998, the Division I EDG was tested in accordance with surveillance test
Procedure TSP-DG1/LOP-8501, "Standby Diesel Generator DG1 Loss of Power Test,"
Revision 0. During the test procedure, the EDG was loaded per Step 7.5.11 by
paralleling the EDG to meet a requirement for a 24-hour run at certain loads.
The EDG
tripped while the operators were adjusting the load, and the problem was traced to the
, motor-operated potentiometer in the speed governor. The motor-operated
potentiometer had an apparent "dead" area in the resistive portion of the potentiometer.
'he "dead" portion of the potentiometer affected the EDG, so that as the load was
changed, the unit'experienced a sudden change of load as the dead area of the
potentionmeter was passed.
This sudden decrease
in demand caused the diesel
generator to.trip on reverse power. The speed governo's motor-operated potentiometer
was replaced and a subsequent
start and 24-hour run of the EDG were successful.
The inspector's review of the governor circuit determined that the effect that this failure
would likely have had on the EDG met the criteria for a valid failure to load for the EDG.
The reason for this determination was that the motor-operated potentiometer is required
for the speed governor to control engine speed when the EDG is running in the
isochronous mode as it would on an engineered safety feature actuation.
The test was
conducted in the droop mode for parallel operation of the EDG and had the effect of
causing a sudden change in load demand.
e
w'c
On May 19, 1998, during an attempt to start, the Division I EDG tripped from a
generator lockout relay actuation.
During the investigation, the system engineer
determined that a lube oil pressure switch had failed to open prior to the 1-minute time
delay in the start circuit. With the switch contacts closed, this completed the logic for the
actuation of the generator lockout relay, resulting in a trip of the EDG. The inspector
observed the investigation of the switch during the troubleshooting effort. The switch
appeared to have failed to open when its setpoint pressure was met. The testing did not
identify an apparent cause for the failure. There was no indication of an actual low lube
oil pressure during the" actual EDG start.
From these conditions, and the fact that the
lube oil pressure switch is bypassed
in the engineered safety feature start of the EDG,
the inspector concluded that the failure of the EDG to run in this instance did not meet
the criteria for a valid failure to run in the EDG reliability program.
f,
DD
Br
'eo
lo
On May 19, 1998, while performing OSP-ELEC-M701 "DG-1 Monthly Operability Test,"
the output Breaker E-CB-DG1/7 failed to close during the portion of the test where the
EDG is paralleled to the plant electrical system.
Normal practice is to perform a slow
start to idle of the diesel engirie, and after a period of warmup to load and.parallel the
-14-
unit. Subsequent
investigation identified what appeared to be loose leads in the
synchronizing circuitry that were suspected of contributing to the problem. The leads
were tightened, and a subsequent attempt to parallel and load the diesel resulted in a
successful paralleling of the unit. The unit was unloaded and another attempt to parallel
the unit failed. The unit was left in the as-tested condition and was subjected to a
troubleshooting plan. The previously identified loos'e terminal leads were determined
not to be the cause.
The observed condition was determined to be a design feature of
the terminals. The troubleshooting efforts identified the probable cause as the latch
check switch, which'was confirmed through a test that was observed by the inspector.
f
The latch check switch is a micro-switch that closes when the trip mechanism is properly
latched.
This protects the breaker from closing without a properly latched trip
mechanism.
The apparent cause of the breaker failure to close was an improperly
adjusted lever arm on the latch check switch. The lever arm was inspected and
adjusted as specified in the procedure to a tolerance of 1/8 to 3/16 inch, as described in
Step 7.2.23 of Plant Procedure 10.25.13, "4160/6900 Circuit Breakers 4 Year
Inspection." This is the intended range within which the'switch is expected to close, to
indicate that the trip latch pawl is made up, therefore indicating that the trip mechanism
is properly latched.
The latch check switch lever arm was determined to be out of
adjustment during this investigation. The switch lever arm was adjusted and the breaker
cycled several times to assure proper functioning.
The licensee staff was still pursuing the root cause of the misadjustment at the time of
the inspection.
Possible causes were an inadequate procedure, personnel error,
or'ome
other factor undetermined at the time. Based on the observations and
discussions, the inspectors concluded that the two failures of the breaker to close
represented
valid failures of the EDG to load.
D
'il'he
inspector discussed the repeated failures of the Division I EDG during the. outage
with cognizant system engineering staff. The licensee indicated that, based on their
preliminary analysis, the Division I EDG was likelyto be placed in a goal-setting status,
as required by.10 CFR 50.65(a)(1) and their Diesel Generator Reliability Program.
The licensee's Diesel Generator Reliability Program was established to help ensure a
reliability level of 0.95 for the EDGs. To accomplish this, the program directs action to
be taken when either 3 or more failures are experienced
in 20 demands, or 5 in 50, or 8
in 100. The reliability program goal of 0.95 equates to a demand/run failure rate of 0.05,
while the trigger value of 3 failures in 20 demands equates to a failure rate of 0.15.
Additionally, the licensee's individual plant examination assumes
a demand failure rate
of 0.03. The reason(s) for the discrepancies
between the failure rates could not readily
be determined.
The adequacy of the licensee's performance criteria and reliability
trigger values to support the assumptions of the individual plant examination, and the
licensee's long-term actions to address the recent reliability concerns for.the Division I
EDG, willbe reviewed in a future inspection (IFI 50-397/98009-06).
-15-
c.
~~ciao
The Division I EDG experienced multiple material deficiencies during Refueling
Outage R13 which resulted in several failures to run and/or load. The material
'eficiencies
included:
(1) the failure of the mechanical governor's motor operated
potentiometer, (2) failure of the lube oil low pressure switch to reset, and (3) failure of
the diesel generator output breaker to close due to improper setting of the breaker's trip
latch check switch. The licensee's short-term corrective actions for the failures were
appropriate.
Long-term actions willbe reviewed in future inspection activities.
M1.6
iTca 'on
S
essio
Su
iners
a.
s
Sc
e7
/
5
Inspectors observed portions of installation and removal of RHR pump suction strainers
located in the suppression
pool. Maintenance activities were located in the suppression
pool under water and was performed from May 4-14. Maintenance was controlled by
Work Order GYC9. Inspection activities included observation of installation activities,
inspection of new strainers, and review of design changes for RHR Pump RHR-P-28's
suction strainer.
Inspectors observed portions of maintenance for the installation of several strainers that
were modiTied. Maintenance was performed in the suppression
pool and could be
observed via a closed circuit camera mounted to the diver's helmet.
No deficiencies
were noted with observed maintenance.
The RHR Pump RHR-P-28 suction strainer
could not be installed as originally'designed.
Due to a small inaccuracy in initial
measurements
in the distance between a structural support column and the strainer
flange, the RHR-P-28 strainer was manufactured slightly larger than the space allowed
for. The vendor modified one edge of the suction strainer by reducing the length to
accommodate the structural support column. The inspectors qualitatively evaluated the
modification and concluded that the change had an insignificant impact on the ability of
the strainer to perform its safety function.
Inspectors observed portions of the installation of the modified strainer for
Pump RHR-P-28 performed under Work Order GYC9, Task 7, on May 12. Technicians
had completed and properly tracked steps outlined within the work package.
Quality
control inspectors were observed performing verification of torquing requirements.
Inspectors reviewed the methodology for validation of torque wrench values, which
ensured that the use of the torque wrenches in an underwater environment were
accounted for.
-16-
c.
QggcIt~io s
The installation of the new ECCS suppression
pool suction strainers was well executed.
An unanticipated interference identified during the installation of the RHR Loop B suction
strainer was appropriately addressed.
M1.7
a'af
e'lv
S
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i
e
ace
e
n
Te
i
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c'
627 7
From May 5-22, inspectors reviewed MSRVtesting performed during reactor shutdown
for Refueling Outage R13. The inspection included a review of MSRV performance
history, applicable procedures, engineering interviews, and associated
TS.
i
sa
The inspectors reviewed relief valve test data for 18 MSRVs tested during the'shutdown
for Refueling Outage R13. Test data indicated that 3 of 18 valves were found low out of
tolerance.
Four additional valves were not tested due to inoperable installed test
devices.
Ofthe four valves not tested, three were removed from service due to leakage
and the remaining valve was demonstrated
to be within tolerance during power
ascension.
Valve performance was within the requirements of TS 3.4.3, which requires
that 12 of 18 valves be operable for operation above 25 percent power.
Cause,
corrective actions, and generic implications for the MSRVs that failed were properly
tracked under PER 298-0390.
Procedure ISP-MS/IST-R101, Revision 0, "MSRVSetpoint Verification Using Set
Pressure Verification Device," indicates that the MSRVs are required to be tested at a
rate of 4 valves every 24 months and 100 percent of the population every 5 years.
The
inspectors noted that valve testing has multiple requirements associated with tracking
and evaluation.
One requirement was that valves in the test sample be selected from
the valves with the longest interval since the test was last performed. Additionally,
inspectors questioned meth'odologies fortracking valves rotated with spares.
Currently
the licensee tests 100 per'cent of installed valves every outage.
The inspectors found
that the practice of performing a 100 percent verification each outage significantly
reduced the burden associated with tracking various
requirements.'he
inspectors reviewed maintenance rule tracking with the applicable engineer and
found that the system is tracked as a function of the TS Surveillance and associated
requirements.
The maintenance rule database for all systems was under review and
revision to better quantify component requirements.
The licensee indicated that as a
part of the review process MSRVs were being evaluated for individual tracking and
establishment of specific performance criteria.
c.
QoOl~sio
-17-
Main steam safety relief valve testing demonstrated
that the safety relief system met TS
operability requirements."
The licensee's current practice of performing a 100 percent
verification during each outage eased the tracking burden associated with specific
testing requirements.
I
En
i eeri
E1
Conduct of Engineering
E1.1
aeValv
M d'o
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even Pe
u
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s
c
S
Inspectors reviewed modifications to Valves RHR-V-42A, RHR A.injection valve, and
HPCS-V-15, HPCS suppression
pool suction valve. The inspectors reviewed
'odiTication
documentation including: Plant ModiTication Record, 94-0043-2, Pressure
Locking Bypass Modification; Work Order, JBM9 01, HPCS -V-15 Bypass Line
Installation; and B'asic Design Change, El 2.8, Modify Pressure
Locking Susceptible
Valves; RHR-V-42A and HPCS-V-15.
b.
b
i n
F
Generic Letter (GL) 95-07, "Pressure Locking and Thermal Binding of Safety-Related
Power-Operated
Gate Valves," further addresses
pressure locking and thermal binding
'ssues
originally identified in GL 89-10. As a result of the licensee's review of GL 95-07,
several valves considered operable, but possessing
minimal margins to operability
under certain operating configurations, were designated as requiring modifications.
Safety-related double disk gate Valves RHR-V-42A and HPCS-V-15 were two of the
valves identified as requiring modifications and scheduled for modifications during
Refueling Outage R13.
Modifications were performed to provide relief path from the bonnet of the valve to the
high pressure side piping. The inspectors reviewed the modification-packages and
interviewed engineering.
Several changes were made to Work Order JBM9 01 to
accommodate the extraction of a drill bit that broke off in the bonnet during initial drilling.
Interviews with engineering indicated that the broken parts were recovered without
incident. The inspectors reviewed nondestructive test data collected for HPCS-V-15 and
found the data to be complete.
The engineering evaluation, associated
design detail
drawings, drawing change notices, design safety analysis and screening provided
sufficient detail for installation and proper documentation of the modification.
-18-
Design changes to split disc gate Valves RHR-V-42A, and HPCS-V-15, which
addressed
pressure locking and thermal binding issues identified in response to
GL 95-07, were properly evaluated and developed.
Postmaintenance
testing
requirements were sufficient to ensure that the integrity of the associated systems was
maintained.
V
la
Su
o
P3
Procedures and Documentation
a.
nS
o
0
By memorandum dated June 28, 1997, Region IVrequested the Office of Nuclear
Reactor Regulation to review Washington Nuclear Project-2 Emergency Plan Revisions
17 (partial),.18, and 19, via Task Interface Agreement (TIA97-017). The licensee
submitted the revisions-on August 5, 1996, October 23, 1996, and April 3, 1997,
respectively.
The licensee determined that the changes did not decrease the
effectiveness of the. emergency plan.
and Radiation Protection Branch completed its review of
the revisions on March 23, 1998. The resulting safety evaluation was transmitted to
Region IVon April 13, 1998. The safety evaluation was forwarded to the licensee by
letter dated April 16, 1998.
b.
b
i
s
Regarding the Revision 17 drill program description (the subject of the partial review),
the safety evaluation stated that during a November 13, 1997, telephone conversation
the licensee agreed to modify drill requirements in the next emergency plan revision to
clarify that annual radiological monitoring drills are not used to replace one semiannual
health physics drill. This response was considered acceptable.
Regarding Revision 18, the safety evaluation confirmed that the licensee had
satisfactorily fulfilleda commitment to designate an alternate emergency operations
facility location in the emergency plan. A Notice of Deviation concerning this matter was
identified in NRC Inspection Report 50-397/96-14, dated October 25, 1996.
In contrast, the safety evaluation concluded that the licensee decreased
the
effectiveness of its emergency plan in Revision 19 when it reduced on-shift health
physics expertise and overburdened the on-shift chemistry. technician with health
physics responsibilities during emergencies.
The on-shift chemistry technicians were
given responsibility for health physics emergency response
in February 1997.
10 CFR 50.54(q) permits licensees to make emergency plan changes, without prior
J.
-19-
NRC approval, only ifthe changes do not decrease the effectiveness of the plan. The
failure to receive NRC approval prior to reducing the level of on-shift health physics
expertise was identified as a violation of 10 CFR 50.54(q) (VIO 50-397/98009-07).
The licensee was informed of the Office of Nuclear Reactor Regulation's determination
during an April 16, 1998, conference call with the NRC's Region IVstaff. The Plant
Support Branch Chief and Senior Emergency Preparedness
Analyst represented
the
NRC, and the licensee's Emergency Preparedness
Manager and one emergency
planner represented
the licensee.
During the conference call, the Emergency
. Preparedness
Manager stated that immediate corrective actions had been taken in
anticipation of the outcome.
Corrective actions included returning to three on-shift
health physics technicians and issuing a PER to validate the reduction. The licensee
was informed that the corrective actions alleviated the NRC's immediate concern.
c..
~oclu~i
Based on information provided by the licensee, Revision 17 continued to meet drill
guidance criteria. Revision 18 fulfilleda commitment to designate an alternate
emergency operations facility location. The licensee decreased
the effectiveness of its
emergency plan between February 1997 and April 1998, when it reduced on-shift health
physics expertise and overburdened the chemistry technician with health physics
responsibilities during emergencies.
A violation of 10 CFR 50.54(q) was identified. The
licensee returned a third health physics technician to on-shift following notification of the
noncompliance.
V
a
a ement
ee
s
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management on
June 24, 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.
4
~cerise
Supplemental Information
PARTIALLIST OF PERSONS CONTACTED
R. Barbee, Instrumentation and Controls Supervisor
S. Bian, Reactor Engineering
D. Coleman, Regulatory Affairs Manager
D. Giroux, System Engineering
D. Hillyer, Radiation Protection Manager
P. Inserra, Licensing Manager
S. Oxenford, Operations Manager
G. Sanford, Maintenance Manager
G. Smith, Plant General Manager
J. Kane, Acting Engineering Manager
R. Webring, Acting Chief Executive Officer
INSPECTION PROCEDURES USED
~
IP 37551:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 82701:
IP 92902:
Onsite Engineering
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support
Program
Followup - Maintenance
ITEMS OPENED, CLOSED, AND DISCUSSED
50-397/98009-01
'IO, failure to verify that the refuel floortemperature was within the
limits of Procedure 10.4.12 prior to lifting loads greater than 50
tons.
50-397/98009-02
50-397/98009-03
50-397/98009-04
failure to identify and address design requirements of a partially
elevated fuel assembly with regards to the spent fuel pool
criticality analysis
failure to perform the spent fuel and equipment pool inventories
prior to removing the RPV head
two examples of failure to properly implement procedural
requirements for testing EFC valves
t~
0
J
C5
0
-2-
50-397/98009-05
two examples of inadequate procedures for performing testing of
EFC valves
50-397/98009-06
IFI
licensee actions to address failures of the Division I EDG and
adequacy of EDG performance criteria
50-397/98009-07
failure to receive NRC approval prior to making an emergency
plan change that decreased
the effectiveness of the plan
goad
50-397/97009-02
50-397/98009-03
IFI
adequacy of foreign material controls
failure to perform the sperit fuel and equipment pool inventories
prior to removing the RPV head.
jl
LIST OF ACRONYMS USED
FMC
GL
'I&C
IFI
NRC
PER
RSE
TS
WNP-2
Asea Brown Boveri
excess flow check
engineered safety feature
foreign material controls
Final Safety Analysis Report
Generic Letter
instrumentation and control
inspection followup item
main safety relief valve
noncited violation
U.S. Nuclear Regulatory Commission
problem evaluation request
rigging system engineer
Technical Specifications
violation
Washington Nuclear Project-2
- l
0