ML20135C851
ML20135C851 | |
Person / Time | |
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Site: | Vogtle ![]() |
Issue date: | 02/24/1997 |
From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
To: | |
Shared Package | |
ML20135C844 | List: |
References | |
50-424-96-14, 50-425-96-14, NUDOCS 9703040340 | |
Download: ML20135C851 (26) | |
See also: IR 05000424/1996014
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U. S. NUCLEAR REGULATORY COMMISSION (NRC)
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REGION II
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Docket Nos. 50-424 and 50-425
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License Nos. NPF-68 and NPF-81
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Report No:
50-424/96-14. 50-425/96-14
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Licensee:
Georgia Power Company
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Facility:
Vogtle Electric Generating Plant Units 1 and 2
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Location:
7821 River Road
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Waynesboro. GA 30830
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Dates:
December 22. 1996 - February'1. 1997
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Inspectors:
C. Ogle. Senior Resident Inspector
M. Widmann. Resident Inspector
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K. O'Donohue. Resident Inspector (in training)
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Approved by:
P. Skinner. Chief
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Reactor Projects Branch 2
Division of Reactor Projects
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Enclosure
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9703040340 970224
ADOCK 05000424
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EXECUTIVE SUMMARY
Vogtle Electric Generating Plant Units 1 and 2
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NRC Inspection Report 50-424/96-14, 50-425/96-14
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This integrated inspection included aspects of. licensee operations.
engineering, maintenance, and plant support. The report covers a six-week
period of resident inspection.
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ODerations
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In general, the conduct of operations was satisfactory (Section 01.1).
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A non-cited violation (NCV) was identified for operations personnel
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improperly venting air from a nuclear service cooling water (NSCW)
system supplied component prior to restoration of the component to
ser. ice following maintenance (Section 02.1).
An NCV was identified as a result of a solenoid valve vent port which
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became blocked by painting. This resulted in an inadvertent partial
depressurization of one train of starting air for the Unit 2 train A DG
(Section 02.2).
An example of an ap)arent violation was identified following discovery
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by the inspectors tlat the DG 2A air start receiver outlet valve was
open and unlocked. The valve is normally locked open (Section 02.3).
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The second example of an apparent vMlation was identified as a result
of an observation by the inspectors that a jumper installed in the
control circuit of valve 1-HV-8802A, Safety Injection (SI) Pump A to Hot
leg 1 and 4 Isolation Valve, was improperly positioned (Section 02.4)
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A third example of an apparent violation was identified as a result of a
discovery by the inspectors that fifteen spare breakers on motor control
centers (MCCs) 1BBE and 2BBE were open instead of shut.
While the
safety consequences of this mispositioning were minimal, it represents
another example of inadequate configuration control (Section 02.5).
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The inspectors reviewed the circumstances associated with the licensee's
discovery of potentially inadequate testing of the turbine trip from
reactor trip circuit. P-4 interlock.
Pending further review by the
inspectors, this was identified as an unresolved item (Section 03.1),
Maintenance
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Maintenance activities were generally completed thoroughly and
professionally (Section M1.1 and M1.2).
Enclosure
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An NCV was identified for inadequate maintenance in the re) air of a
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failed journal bearing on the Unit 2 train A centrifugal clarging pump
(CCP) speed increaser. Specifically, maintenance personnel failed to
properly follow work package and vendor manual instructions during
performance of the repairs (Section M2.1).
The licensee's identification of missed steps in the reassembly of the
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Unit 2 train A CCP speed increaser was an example of good attention to
detail (Section M2.1).
Two examples of an NCV were identified for deficiencies associated with
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the licensee's development and implementation of procedures to test the
turbine trip from reactor trip circuit (Section M3.1)
Enaineerina
A strength was identified for the efforts by the event review team to
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determine the root cause of the failed journal bearing on the Unit 2
train A CCP speed increaser.
The corrective actions develo]ed as a
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result of the team's efforts should provide data to trend t1e pump's
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performance in the future (Section E7.1).
Plant Suooort
In general, conduct in the plant security area was satisfactory
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(Section S1.1).
Minor deficiencies were identified in the protected area (PA) barrier,
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but these did not rise to the level of a regulatory non-compliance
(Section S2.1).
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Enclosure
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Report Details
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Summary of Plant Status
Unit 1 operated at 100% Rated Thermal Power (RTP) throughout the inspection
period.
Unit 2 operated at 100% RTP throughout the inspection period.
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Doerations
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Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations and, in general
the reviews
indicated that the conduct of operations was satisfactory.
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Operational Status of Facilities and Equipment
02.1 Air Bindina of Nuclear Service Coolina Water (NSCW) Supolied Motor
Coolers on Safety In.iection (SI) Pumo 2A
a.
Insoection Scooe (71707)
The inspectors reviewed resolution of a loss of NSCW flow condition
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identified for one of the Unit 2 Train A SI pump motor coolers.
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inspectors reviewed maintenance work orders (MW0s) associated with
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plenum orientation verifications: Preventive Maintenance (PM) checklist
SCL02677. NSCW Heat Exchanger - Periodic Inspections; control room logs:
and Procedures 13150-1 and 13150-2. Nuclear Service Cooling Water System
(Units 1 and 2. respectively).
The inspectors also interviewed
personnel involved with plenum orientation verification activities and
cognizant management as to their review of this issue.
b.
Observations and Findinas
On December 18. 1996, a plant equipment operator (PEO) observed that the
inboard motor cooler on the Unit 2 SI pump train A had a higher return
3iping temperature than that of the corresponding outboard motor cooler.
ion-intrusive measurements revealed that no NSCW flow existed through
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the inboard motor cooler.
On December 19. following troubleshooting.
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the licensee determined that the no flow condition was the result of air
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binding of the inboard motor cooler.
Following this discovery, the
licensee addressed the potential air binding condition by venting NSCW
supplied components.
No other incidents of air binding were identified.
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Upon discovery of the no flow condition maintenance personnel
disassembled the motor cooler piping for SI pump 2A to identify any
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potential sources of blockage.
No foreign material was identified in
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either motor cooler's NSCW piping. After reassembly. NSCW flow was
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restored to the SI pump motor without venting. Again, a no flow
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condition developed: however, this time it occurred on the outboard side
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motor cooler.
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The licensee determined that the original no flow condition was probably
the result of air introduced into the system during maintenance
undertaken to verify plenum baffle plate orientation.
During that
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maintenance. the motor cooler alenum drain plugs were removed and a
small tool was inserted ir.to t1e plenum to determine the orientation of
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the internal baffle plate.
The drain plug was then reinstalled.
During
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this. activity, small amounts of water drained from the isolated motor
coolers. Air )otentially introduced into the system during this
activity then
3ecame trapped in the return )iping of the motor cooler.
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After the cooler was returned to service, t1e resultant flow was not
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enough to sweep the air through the NSCW system.
The licensee
determined that the air binding occurred at the SI pump due to
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configuration of the NSCW piping. The licensee informed the inspectors
that the other emergency core cooling system pumps have a different
piping configuration and may not be susceptible to the air binding
phenomenon.
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Procedures 13150-1 and 13150-2. Precautions and Limitations section.
provided instructions to operations personnel to thoroughly vent all
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isolated NSCW supplied components prior to returning them to service.
This action would minimize the potential for system performance
degradation due to air entrapment.
Based on observations and
discussions with the licensee the inspectors concluded that following
this maintenance, operations personnel did not vent the isolated NSCW
supplied components prior to restoration.
During discussions with
operations management, the licensee acknowledged that guidance was not
provided to operators to vent affected components following this
maintenance. The licensee indicated that draining, filling and venting
a system is " skill of the craft" and that specific guidance to perform
these activities was unnecessary. The operations shift crew supervision
stated that support of the maintenance activity to isolate NSCW supplied
components did not constitute draining the system, therefore, no formal
process to install a clearance and restore the system to service was
coordinated for the operations activities.
Upon identification of the no flow condition on December 18. the
licensee took a)propriate immediate corrective action to vent other NSCW
components whic1 could have been affected. The licensee stated their
intention to counsel operations personnel involved regarding their
methods used to isolate and return systems to service following
maintenance activid os.
The licensee also )lans to review NSCW system
operation to determine if air is presently ]eing entrained and if
further venting is required.
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Enclosure
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c.
Conclusions
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The inspectors concluded that although this activity is considered by
the licensee to be a " skill of the craft" activity. the guidance.
instructions, or training which is provided to operations personnel must
be sufficient to ensure that equipment remains operable.
The inspectors also concluded that the no flow condition in the SI
pump 2A probably resulted from air introduced into the NSCW piping
following maintenance as a result of the pump being returned to service
without being properly vented.
This is contrary to the Precautions and
Limitations of Procedures 13150-1 and 13150-2.
However, consistent with
Section VII of the NRC Enforcement Policy this was identified as
Non-Cited Violation (NCV) 50-425/96-14-01. NSCW Motor Cooler Not Vented
Prior To Being Returned To Service.
02.2 Unit 2 Diesel Generator (DG) Air Start Block Valve Stickina Ooen
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a.
Insoection Scooe (71707)
The inspectors reviewed an inadvertent, partial depressurization of the
Unit 2 train A DG air receiver tank number 2 which occurred as a result
of an air start block valve that failed to shut. This review included:
the deficiency card (DC) written in response to the issue:
Procedure 25021-C. Coating: the MWO associated with troubleshooting the
suspect solenoid valve: Updated Final Safety Analysis Report (UFSAR)
Section 9.5.6. DG Starting System: and commitments /open items written
against Procedure 25021-C.
The inspectors discussed this issue with the
plant maintenance and modifications managers. licensing department
personnel, and operations management.
b.
Observations and Findinas
On December 18. 1996, while starting the Unit 2 train A DG. air receiver
number 2 was depressurized to approximately 80 pounds per square inch
gauge (psig) as a result of a malfunctioning solenoid valve. This
resulted in the air start block valve remaining open after the diesel
had started.
The solenoid valve malfunctioned as a result of paint
blocking a vent port on the valve.
The operator at the diesel took
immediate corrective action to stop the inadvertent depressurization by
isolating the air receiver.
As a result of this isolation, the number 2 air receiver tank was not
available to provide supplemental starts to the DG if required. The
UCSAR states that each air receiver contains sufficient air to start the
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diesel at least five times.
The DG remained operable since the number 1
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cir receiver tank was available during the post-event maintenance
activities.
Following replacement of all four vent ports on the train A
DG the licensee returned the number 2 air receiver tank to service.
The restoration to normal operating pressure was performed without
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incident.
Upon identification of the solenoid vent port plugging, the
licensee conducted a walkdown of the other DGs.
No other similar
discrepancies were identified.
The inspectors determined that on November 7, 1996, painting personnel
were given approval 'to commence painting the Unit 2 train A DG.
Painting was finished on December 3.1996.
Procedure 25021-C contains a coating request form (CRF) that is used to
identify and authorize )aintwork and review its potential impact on
plant equipment. A wal(down using the CRF is normally performed by the
plant modification group and operations personnel prior to beginning
work.
However, in this case, operations supervision informed the
inspectors of their assumption that the painting to be performed on the
Unit 2 train A DG was routine in nature and, therefore. did not.
necessitate a CRF-specific walkdown. The inspectors also determined
that no special instructions were given to the painters prior to the
painting activity.
The inspectors identified that earlier revisions of the CRF included a
more descriptive checklist of items to be reviewed prior to painting.
In particular, the checklist in Revision 12 of Procedure 25021-C.
included a specific step to assess instrument and control (I&C)
equipment to be painted and masked including vent ports.
This step,
and several others, were deleted during subsequent revisions. The
licensee was unable to provide justification to the inspectors for the
deletion of
avious details of the earlier CRF.
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As correcti.
aon. the licensee stated their intention to:
revise
the Procedure 25021-C CRF checklist to require a more comprehensive
pre-painting walkdown, require the system engineer to participate in a
walkdown of the items / areas to be painted, and provide a basic
mechanical systems class to onsite painters to aid in their
understanding of the type of equipment their efforts could impact.
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Conclusions
The inspectors concluded that the painters did not have adequate
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procedural guidance to address potential issues with painting, such as
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obstruction of vent ports.
This lack of procedural guidance. coupled
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with the lack of a pre-painting walkdown resulted in mis-applied paint
which impacted the operation of a portion of the DG 2A starting air
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system.
This is contrary to the requirements of 10 CFR 50. Appendix B.
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Criterion V. Instructions. Procedures, and Drawings. which specifies
.that activities affecting quality be prescribed by documented
instructions and procedures.
However, consistent with Section VII of
the NRC Enforcement Policy this was identified as NCV 50-425/96-14-02.
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Inadequate Procedure Results in Loss of One Train of Starting Air for
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the Unit 2 DG Train A.
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Enclosure
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02.3 Unlocked DG Air Start Receiver Discharae Isolation Valve
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a.
Insoection Scone (71707)
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The ins)ectors reviewed the circumstances surrounding valve
2-2403-J4-765. Unit 2 DG A Air Start Receiver Number 1 Discharge
Isolation Valve, being discovered open and unlocked.
(This valve is
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normally open and locked.) This review included interviews of operators
responsible for the last manipulation of the valve: review of the
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Safety-Related Locked Valve Manipulation Log Sheet of Procedure 11888-C
)re)ared for that manipulation: and Procedure 11867-2. Safety-Related
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_octed Velve Verification Checklist. The inspectors also reviewed the
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DC generated for this issue.
b.
Observations and Findinas
On December 30, 1996, during a routine tour, the inspectors observed
that valve 2-2403-U4-765 was o)en with a chain and unlocked padlock
attached. The unlocked padloc( was through both sides of the chain.
After verification of this observation by operations personnel, the
padlock was closed, as required.
The licensee generated a DC in
response to the issue. This valve is the DG 2A air receiver number 1
discharge isolation valve and, per Procedure 11867-2. is a normally
locked open valve.
The valve position and lock status were last verified following
maintenance troubleshooting on the engine on December 19. 1996. The
initial restoration and independent verification were documented on a
Procedure 11888-C. Safety-Related Locked Valve Manipulation. Log Sheet.
Two operators signed the data sheet indicating that the valve was locked
open and independently verified in that position.
During interviews, the operators described the method they used to
verify the valve's position and status of its lock. The inspectors
noted that their descriptions were consistent, plausible, and in
accordance with valve verification practices observed by the inspectors
on previous occasions. The inspectors also noted from reviewing
security access records, that both operators were in the appropriate
DG room about the time the verifications were documented as complete.
The inspectors noted that neither individual could recall pulling on the
lock during the positioning or verification to verify that the lock
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remained locked.
The inspectors noted that though the valve was unlocked, it was in the
proper position.
Hence, not locking the valve did not impact the
operability of the DG.
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c.
Conclusions
The safety consequence of not maintaining valve 2-2403-U4-765 locked, as
required by Procedure 11867-2. was minimal. However, this represents
another example of a configuration control deficiency identified by the
inspectors as well as a failure of the two-party verification system.
This was identified as an example of an apparent violation
EEI 50-424.425/96-14-03. Configuration Control Deficiencies Involving
Mispositioned Components and Improper Independent Verification.
02.4 Misoositioned Jumoer For Thermal Overload Device
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a. Insoection Scooe (71707)
The inspectors conducted walkdowns of the accessible portions of the
Units 1 and 2 SI systems. This included in-plant and control room
verification of component positioning and operability; a review of the
UFSAR: comparison of selected technical specification (TS) requirements
and their associated surveillance procedures: and verification of
licensee lineup procedures against system drawings.
b.
Observations and Findinas
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housekeeping were good. quipment operability, material condition and
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The inspectors noted several minor administrative differences between
lock status as specified in Procedures 11105-1 and 11105-2. Safety
Injection System Alignments, and the system drawings. These did not
impact system operability and in all cases the components were found to
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be in the correct position.
These were identified to the licensee for
resolution.
On January 9, 1997, during a walkdown of the 480-Volt breaker enclosures
of four Unit 1 SI system valves, the inspectors identified that a jumper
installed in the control circuit of valve 1-HV-8802A, SI Pump A to Hot
Leg 1 and 4 Isolation Valve, was improperly positioned.
Thejumperwas
installed between breaker terminal points "14" and "W1."
This jumper is
provided as the thermal overload protection bypass device required by
TS 3.8.4.2 and should have been installed between breaker terminal
points "15" and "W1." As a result of this mis-wiring, the thermal
overload protection device for the breaker was not by>assed.
requires that the thermal overload protective device 3e bypassed
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whenever the valve is required to be operable.
If this is not
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accomplished, the action statement requires that the valve be declared
inoperable and the appropriate action statement for the valve be
entered.
TS 3.5.2 ap) lies to this valve as part of the SI system and
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specifies actions witlin 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> if the valve is inoperable.
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Following confirmation of this observation, the licensee declared the
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valve inoperable and restored the jumper to the correct position later
that day.
The following day, operators conducted a walkdown of a
portion of the Unit 1 breakers specified in TS 3.8.4.2 and found no
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other configuration problems.
On January 13. the licensee commenced
Surveillance Procedure 28905-C. Motor Operated Valve Thermal Overload
Bypass 18 Month Verification, to verify the jumper positions for
breakers specified in TS 3.8.4.2.
Based on a review of MWO 19600079 and interviews of the appropriate
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maintenance personnel, the inspectors determined that maintenance on the
breaker, requiring lifting and restoring the jumper, was last performed
on March 28, 1996.
The lifting and restoration of the jumper were
accomplished in accordance with Procedure 20429-C. Short Term
Documentation of Temporary Jumpers and Lifted Wires.
This included an
independent verification of the restoration of the jumper to the
recuired terminal location.
Both the initial positioner and the
incependent verifier annotated on a lifted lead form that the wire had
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been properly restored.
When interviewed by the inspectors. neither
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technician could describe anything particularly noteworthy about the
restoration of this particular jumper that would have prevented landing
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it in the correct location.
They did indicate that the terminal block
cover which had the terminal labelling annotated on it, had to be
removed to connect the jumper.
However, the inspectors were informed
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that the cover would only reattach in'the correct position.
Both
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indicated that they were surprised by the discovery of the mispositioned
jumper.
Their descriptions of their implementation of the lifted lead
procedure were consistent with inspector observations of this practice
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in the past.
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The effect of the mispositioned jumper was to restore the thermal
overload device into the breaker control circuit. A review of the
wiring diagram and examination of the breaker cubicle by the ins)ectors
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indicated that there were no other implications as a result of tie
improper jumper installation.
The licensee informed the inspectors that
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the valve was satisfactorily dynamically tested with the thermal
overload in the circuit in May 1993 and statically tested with the
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thermal over!oad in the breaker control circuit in March 1996, again
without incident. At the time of discovery, the inspectors verified
that the thermal overload device was set at the setpoint specified by
the licensee's procedure.
The inspectors noted from their review of the emergency o)erating
procedures (E0Ps) that valve 1-HV-8802A is used when esta)lishing hot
leg recirculation following a loss of coolant accident. The other SI
pump is provided with its own hot leg injection valve.
Additionally,
the E0P for hot leg recirculation provides actions which are to be taken
if the SI train A hot leg recirculation flow path cannot be established.
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Enclosure
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c.
Conclusion
This mis-positioning represents another example of a configuration
control deficiency identified by the inspectors as well as a failure of
the two-party verification system.
This also represents another
instance involving the improper implementation of the lifted lead form
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documented by the inspectors in the last 18 months. The inspectors
concluded that the failure to proaerly install the thermal overload
protection by) ass device between iarch 28, 1996 and January 9. 1997 was
contrary to t1e requirements of TS 3.8.4.2 and 3.5.2.
This was
identified as an example of an apparent violation EEI
50-424.425/96-14-03. Configuration Control Deficiencies Involving
Mispositioned Components and Improper Independent Verification.
02.5 480-Volt MCC Soare Breakers Miscositioned
a.
Insoection Scooe (71707)
The inspectors compared actual breaker positions on motor control
centers-(MCCs) 1BBE and 2BBE with the required positions s)ecified in
Procedures 11429-1 and 11429-2, 480-Volt AC 1E Electrical )istribution
System Alignments,
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b.
Observations and Findinos
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On January 19, 1997, the inspectors conducted a walkdown of the 480-Volt
breakers on MCCs 1BBE and 2BBE.
All load equipped breakers were
]roperly positioned.
However, the inspectors noted that between the two
iCCs. fifteen breakers labelled as spares were improperly positioned.
Specifically Procedures 11429-1 and 11429-2 require that spare breakers
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be shut unless tagged.
In fact. the inspectors observed that these
fifteen spare breakers were open and untagged.
The inspectors confirmed from a review of the one-line diagrams for the
two MCCs. that the open breakers were in fact spares and not connected
to loads. Additionally. the inspectors reviewed the clearance database
and determined that the spare breakcrs were not under clearance when the
lineups were last completed.
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The last performances of the 1E system alignments were reviewed (Unit 1
- April 1996 and Unit 2 - February 1995). The Unit 2 alignment clearly
indicated that all spare breakers were closed at that time. The Unit 1
breaker alignment is less clear in that no initials are contained in the
procedure blanks for the "ALL OTHER BREAKERS" entry.
However, the two
clearance exceptions provided in these blanks do not relate to spare
breaker clearances.
The licensee informed the inspectors that their subsequent review of the
breaker alignments of other 1E MCCs yielded similar inconsistencies in
the alignment of spare breakers.
Enclosure
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c.
Conclusion
The inspectors concluded that while the safety consequence of the
fifteen spare breakers being open on 1BBE and 2BBE was minimal, it
represented another example of an NRC identified configuration control
deficiency. Accordingly. the failure to properly position the spare
breakers on MCCs 1BBE and 2BBE in accordance with the requirements of
Procedure 11429-1 and 11429-2 is identified as an apparent violation
EEI 50-424.425/96-14-03. Configuration Control Deficiencies Involving
Mispositioned Components and Improper Independent Verification.
03
Operations Procedures and Documentation
03.1 Identification Of Potentially Inadeouate Surveillance Testina Of Turbine
Trio From Reactor Trio (P-4 Interlock)
a.
Insoection Scooe (71707)
The inspectors reviewed the circumstances regarding the licensee's
identification of potentially inadequate testing of the turbine tiip
from reactor trip circuit (P-4 interlock).
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The ins)ectors reviewed operator log entries regarding this issue.
a) plica)le TSs. and the associated DC. The review by the inspectors of
t1e surveillance procedures subsequently used to test the affected
circuits is documented in Section M3.1 of this report.
b.
Observations and Findinos
At 5:00 p.m. on January 22, 1997, the licensee entered TS 3.0.3 on both
units in response to their identification of potentially inadequate
surveillance testing used to demonstrate the operability of the turbine
trip from reactor trip circuit.
This testing is used to demonstrate
operability of this P-4 circuitry in accordance with the requirements of
TS 3.3.2 Functional Units 5.b.2 and 9.b. Reactor Trip. P-4.
The licensee invoked the provisions of TS 4.0.3.
This allows delay of
action requirements, with a duration of less than one day. for up to 24
hours to permit completion of a surveillance which has not been
performed within the allowed surveillance interval.
The following day, after comaletion of the surveillance of the A train
)ortion of these circuits, t7e licensee exited TS 3.0.3 at 8:29 a.m. on
Jnit 1 and at 9:47 a.m. on Unit 2.
Testing of the respective B trains.
and exiting the remaining TS 3.3.2. was completed at 11:43 a.m. on
Unit 2 and 2:43 p.m. on Unit 1 on January 23, 1997.
Enclosure
~ _ . _ . _ _ _ _ _ _ _ _ _ _ _
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_ _ _ _ _ . - .
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c.
Conclusion
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!
The review of this issue by the inspectors was ongoing at the end of the
j
report period.
Pending additional review, this is identified as
j
Unresolved Item (URI) 50-424.425/96-14-06. Potentially Inadequate
Surveillance Testing of P-4 Circuitry.
03.2 Walkdown of Clearances (71707)
The inspectors walked down the following clearances:
29600433
Chemical and volume control system (CVCS) positive
!
displacement pump (PDP): repair stuffing box leak
i
29600437
CVCS Centrifugal Charging Pump (CCP) train A; repair
oil leak and speed increaser
.
29700049
Post accident sampling system backflush waste to fuel
handling building drains: repair valve 2-1212-U4-125
b.
Observations and Findinaq
The inspectors did not identify any problems or concerns with the
clearances.
j
08
Miscellaneous Operations Issues (71707)
08.1
(Closed) Insnector Follow-uo Item (IFI) 50-424/96-03-03: Mispositioned
l.
Auxiliary Building Drain Valve
This item documents an improperly positioned Unit 1 auxiliary building
drain valve discovered by the 1acensee following inspector questions on
,
the positioning of the same val >e in Unit 2.
l
,
The inspectors reviewed the acticas taken by the licensee in response to
this finding identified by SAER. The ins)ectors have not identified any
I
other mispositioned drain valves during t1eir routine inspection.
This
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valve is not safety-related.
Bssed on this review, this item is closed.
II.
Maintenantg
M1
Conduct of Maintenance
M1.1 Maintenance Work Order (MWO) Observations
a.
Insoection Scope (62707)
,
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The inspectors observed portions of maintenance activities involving the
i
following work orders:
!
Enclosure
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19700027
Reactor trip breaker train A springs would not charge
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after being tripped open
29600433
Chemical and Volume Control System (CVCS) Positive
Displacement Pump (PDP) repair stuffing box leakage
1
29600437
CVCS Centrifugal Charging Pump (CCP) investigate /
'
repair oil leak
29603144
Unit 2 CCP train A speed increaser gearing and bearing
change out
b.
Observations and Findinas
The observed maintenance activities were performed satisfactorily.
M1. 2 Surveillance Observation
i
a.
Insoection Scoce (61726)
The inspectors observed the performance of or reviewed the following
surveillances and plant procedures:
14420-1
Solid state protection system (SSPS) and reactor trip
breaker train A operability test
14421-2
SSPS and reactor trip breaker train B operability test
!
14475-1
Containment integrity verification - valves outside
containment
14485-2
Containment spray system flow path verification
i
14546-1
Turbine driven auxiliary feedwater pump operability
test
,
'
b.
Observations and Findinas
The observed surveillance activities were performed satisfactorily.
1
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 CCP ?A Soeed Increaser Bearina Failure
a.
Insoection Scope (62707)
!
l
The inspectors reviewed maintenance on the Unit 2 train A CCP speed
increaser following the licensee's entry into a 72-hour limiting
condition for operation (LCO) on the pump on December 27. 1996.
This
review included MWO 29603144. Unit 2 CCP Train A Speed Increaser Gearing
,
Enclosure
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. _ _ _ _
_ _ _ _
_ _ _ .
. . __.
_
12
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and Bearing Change Out, and MWO 29700025. Thrust Head Socket Plate
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Torquing: Vendor Manual 2X6AH02-85. Charging / Safety Injection Manual:
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Procedure 27115-C. Westinghouse SU-1023-8X5 Speed Increaser: and
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Deficiency Card (DC) 2-97-003.
l
b.
D.bservations and Findinas
On December 27, 1996, the Unit 2 train A CCP experienced a journal
l
bearing failure on the pump end of the high speed shaft of the speed
increaser.
Subsequently, a high speed gear seal failed that resulted in
a loss of lubricating oil. This allowed lubricating oil to spray into
'
the pump room causing smoke when the oil came in contact with the hot
metal of the speed increaser.
At approximately 5:55 a.m. a fire alarm
was received in the main control room for the CCP train A pump room.
l
Operators stopped the train A pump at approximately 6:00 a.m. and
i
swapped operation to the CCP train B pump without incident. At
6:00 a.m. operations entered a 72-hour LC0 to disassemble and repair the
!
Maintenance replaced all speed increaser rotating
components, bearings, and oil seals including the main oil pump. At
3:28 a.m.. on December 30,1996, the LC0 was exited following com)letion
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of maintenance activities and restoration of the pump to an opera)le
'
status.
1
,
On January 6,1997, during the MWO 29603144 closure review, a quality
control inspector identified that the thrust plate cap screws were not
installed as required per the vendor manual.
Vendor manual 2X6AH02-85
was included as an attachment to MWO 29603144 work instructions and
!
!
contained a drawing of the s
General Assembly SU-1023-8. peed increaser. On that drawing. 1930012.
a note provided instructions to install the
thrust plate cap screws with a locking compound and to torque the cap
screws to 50-60 foot-pounds.
During the performance of the MWO. a
locking com
reassembly. pound was not used nor were the cap screws torqued during
The CCP 2A's speed increaser was reworked under MWO 29700025. The MWO
i
required work description addressed the proper installation of the cap
'
screws. including torquing and locking compound requirements.
During
review of the MWO instructions, maintenance personnel ide~ified an
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additional requirement on the speed increaser drawing for the use of
lockwire during the spray nozzle hardware installation. This also had
,
not been performed prior to returning the pump to an operable condition.
!
On January 7. the rework activity was completed and the CCP 2A was
declared operable after a successful functional test.
U)on identification of the inadequately torqued thrust plate cap screws
tie licensee initiated DC 2-97-003 and performed an engineering
evaluation.
Results of engineering evaluation REA-VE-3100 & X6AH02.
Thrust Plate Screw Torque Evaluation, indicated that based on the
,
as-found condition of the pump speed increaser. CCP 2A may have
eventually failed if required to provide long term cooling. The
Enclosure
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13
engineering evaluation concluded that the pump was operable, but in a
degraded condition.
c.
Conclusions
Based on this review, the inspectors concluded that the corrective
actions taken by the licensee to address the identified deficient
conditions were adequate and performed in a timely manner.
In addition,
the licensee has submitted a revision to Procedure 27115-C to include
the torquing and lockwire issues discussed above.
The inspectors
concluded that these actions were adequate to prevent recurrence.
The inspectors concluded that the improper installation of the thrust
plate cap screws was the result of a failure to properly follow MWO and
vendor manual instructions.
Failure to properly follow instructions
during performance of MWO 29603144 was contrary to the requirements of
Technical Specification (TS) 6.7. Procedures and Programs.
However,
consistent with Section VII of the NRC Enforcement Policy this was
identified as non-cited violation NCV 50-425/96-14-04. Failure to
Implement Work Instructions For Unit 2 CCP 2A Speed Increaser.
The inspectors also concluded that the identification of the missed
4
'
steps in the reassembly of the speed changer were examples of good
attention to detail.
M3
Maintenance Procedures and Documentation
'
M3.1 Testina of Reactor Trio Inout to Turbine Trio Loaic
l
a.
Insoection Scope (61726)
The inspectors reviewed the procedures used to test the reactor trip
input to the turbine trip logic (P-4 interlock).
Specifically, the
inspectors reviewed the following:
Procedure 14420-1
SSPS and Reactor Trip Breaker Train A
Operability Test
Procedure 14420-2
SSPS and Reactor Trip Breaker Train A
Operability Test
Procedure 14421-1
SSPS and Reactor Trip Breaker Train B
Operability Test
Procedure 14421-2
SSPS and Reactor Trip Breaker Train B
Operability Test
The inspectors also witnessed performance of Procedure 14421-2.
Enclosure
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14
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b.
Observations and Findinas
The conduct of the' testing witnessed by the inspectors was satisfactory.
Step 3.9 of Procedures 14420-1, 14420-2, 14421-1 and 14421-2 originally
l
contained a precaution and limitation that stated:
"This procedure
i
shall be performed by licensed personnel only." However. Procedures
j
14421-1 and 14421-2 were changed on January 23, 1997. using )en and ink,
to modify this step to:
"This procedure shall be performed )y or under
the direction of licensed personnel only."
When questioned, the approving authority for the change, the Shift
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Superintendent (SS). described three basic reasons behind his changing
!
this precaution and limitation. These were:
-
Only 4 reactor operators (R0s) were available on shift that
day. Given the critical nature of the surveillance and the
l
possibility of a plant trip, he stated his desire to
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maintain 2 R0s on each unit.
i
He stated his desire to involve Plant Equipment Operators
-
(PE0s) in the manipulation of plant equipment. He described
his intention that the participation of the PE0 be directly
supervised by a senior reactor operator (SR0).
-
The SS also indicated that his review revealed that there
!
were no commitments or bases behind the requirement to use
only licensed personnel to perform these procedures.
The inspectors observed from their review of the completed Procedure
14420-2. that a PE0 had initialled for completing several steps.
.Primarily, these ste)s-involved manipulation of the reactor trip bypass
breaker.
However, t1e Step 3.9 precaution and limitation had not been
changed in 14420-2 to allow performance of the surveillance by other
than licensed personnel.
When questioned on this apparent discrepancy, the SS stressed to the
inspectors that the PE0 was under the direct supervision of an SR0
during his work on the surveillance.
Likewise, similar comments,
stressing the involvement of an SRO in overseeing and directing the
actions of the PEO. were made by other members of the operations
management organization during the inspection of this issue. The
Operations Manager informed the inspectors that a PE0 accomplishing the
procedure under the supervision of an SRO was an acceptable combination
and more than met the intent of the procedure.
He further stated that
this exceeded the standard of a having a licensed operator perform the
procedure.
The licensee also pointed out that the testing was
successfully accomplished using the PE0 with SR0 supervision.
Notwithstanding arguments to the contrary, the inspectors concluded that
i
j
Enclosure
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15
the PE0 who' accomplished the actions of the statement and initialed the
procedure was performing the steps.
?
The inspectors also observed that the changes to Step 3.9 in
i
Procedures 14421-1 and 14421-2 were initialled by the approving
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authority for the change, the SS.
The inspectors were concerned that
the approving authority making changes during his review could bypass
,
the required reviews.
When questioned on this, the SS acknowledged
making the changes prior to implementation of the procedures.
He stated
j
that the procedures were subsequently reviewed by the respective Unit
!
Shift Supervisors (USSs).
Both USSs stated to the inspectors that they
!
reviewed Step 3.9 in the procedure following the change by the SS.
j
However, neither the quality reviewer nor the change originator reviewed
the change to Step 3.9 after the SS made his change to the procedure.
The inspectors identified that the reviews performed by the USSs. were
not documented in accordance with the licensee *s administrative process
for procedure changes. Procedure 00051-C. Procedure Review and Approval.
i
The inspectors identified from a review of the USS logs, that plant
staffing exceeded TS requirements on the day these surveillances were
s
performed.-
c.
Conclusions
The inspectors concluded that having a PEG perform steps within
!
Procedure 14420-2. was contrary to the requirements of Step 3.9 of that
!
procedure.
In addition, the failure to document the reviews of changes
!
made to Step 3.9 of Procedures 14421-1 and 14421-2 was not in accordance
with the requirements of Procedure 00051-C. Procedures Review and
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Approval. These are identified as two exam)les of a minor violation for
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failure to properly im)1ement procedures.
iowever consistent with
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.
Section IV of the NRC Enforcement Policy this was identified as
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NCV 50-424.425/96-14-05. Failure to Implement Procedures During P-4
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Testing. Two Examples.
!
III.
Enaineerina
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E7
Quality Assurance in Engineering Activities
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E7.1 Failure Analysis of the Unit 2 Charaina Pumo Soeed Increaser Bearinas
,
a.
Insoection Scooe (37551)
i
!
The inspectors followed the licensee's engineering event review team
!
efforts involving the Unit 2 train A Centrifugal Charging Pump (CCP)
speed increaser bearing failure that occurred December 27. 1996. The
)
inspectors observed portions of the event review team's root cause and
{
corrective action determination: reviewed event report 2-96-06. Bearing
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Failures in Speed Increaser for Centrifugal Charging Pump 2A: the
l
Enclosure
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16
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Deficiency Card (DC) generated in response to the event: personnel
statements; and auxiliary building rounds sheets (that monitor lube oil
)
temperatures). The inspectors also had discussions with engineering and
maintenance management. in addition to corporate engineering vibration
i
experts. as to their investigation and findings based on the
i
circumstances surrounding this event.
b.
Observations and Findinas
A detailed event description is provided in section M2.1 of this report.
i
Based on the facts and evidence as a result of this event. the licensee
l
theorized that the CCP 2A speed increaser bearing failure occurred due
to metal fatigue as a result of one of two causes. The first failure
i
theory was a shortened service life resulting from harsher than expected
i
conditions (i.e.. higher dynamic loading, and number of unlubricated
l
starts) which ultimately resulted in the failure of the journal bearing.
,
The second proposed theory was that the failure was due to misalignment
i
between the motor and the speed increaser. This latter theory was
supported by the need to realign the motor to the speed increaser during
'
repair activities.
The event review team also determined that the quarterly Preventive
Maintenance (PM) program performed was lacking, in that the program was
unable to provide warning of the bearing's imminert failure >rior to the
,
event.
The current PM performed on the CCP requires pump vi) ration
'
measurements and a lubricating oil analysis.
The PM was last performed
on December 17, 1996.
PM results indicated normal (acceptable)
measurements.
Corrective actions recommendations developed and adopted by plant-
!
management included:
further analysis of the damaged high speed gear to
!
determine its failure mode mechanism: installation of temperature
sensors on the speed increaser gear box and proximity vibration sensors
on gear box shafts to improve vibration data collection: and to perform
i
a gear box bearing and gear inspection after additional data collection
-has been performed.
r
c.
Conclusions
-
The ins)ectors concluded that the engineering event review team did a
thorougl job in exploring possible contributors to the event. The
planned examination of the damaged CCP 2A s)eed increaser should assist
in conclusively determining the failure meclanism.
The event review
team appropriately consulted outside personnel (i.e.. pump vendor and
vibration experts) in an effort to determine the root cause(s).
The
inspectors also concluded that the licensee's )lanned corrective actions
'
to address the deficiencies identified in the )M program were
appropriate.
t
Enclosure
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17
The team's effort to determine the root cause of the event is identified
as a strength.
E8
Hiscellaneous Engineering Issues (37551)
E8.1 (Closed) Licensee Event Report (LER) 50-424/96-001 Revision 1: Pipe
Fatigue Leads To Nuclear Service Cooling Water System Inoperability.
This issue was documented in Inspection Report 96-01 (paragraph 2.4) and
Inspection Report 96-02 (paragraph 4.5).
The original LER was closed in
4
Inspection Report 96-03 (paragra>h 4.2).
This revision to the LER
updates information related to tie licensee's corrective action.
No new
issues were revealed by this revision to the LER.
This item is closed.
E8.2 NRC Notification For Condition Outside The Desian Basis
a.
Insoection Scoce (37551. 90712)
At 5:39 p.m. on January 21, 1997, the licensee made a one-hour
'
non-emergency notification to the NRC in accordance with the
requirements of 10 CFR Part 50.72 (b)(1)(ii)(B). condition outside the
design basis of the plant.
The licensee's notification stated that
portions of the Nuclear Service Cooling Water (NSCW) system and several
containment penetrations had been determined to be outside their design
basis,
b.
Observations and Findinas
When advised of the pending notification. the inspectors responded to
the site and reviewed the basis for the licensee's notification. The
inspectors also reviewed the issue with the Manager of Engineering
Support and one of his direct reports. Additionally. the inspectors
'
discussed the licensee's planned strategy for compensatory actions with
the Shift Supervisor (SS).
The licensee's notification was based on the results of reviews
conducted in response to NRC Generic Letter 96-06. Assurance of
Equipment Operability and Containment Integrity During Design Basis
Accident Conditions. As a result of their review, the licensee
preliminarily determined that portions of the NSCW system may be
susceptible to water hammer during certain design basis events. The
inspectors were informed that a hydraulic transient analysis indicated
that during the potential water hammer, some postulated stresses in the
system exceeded American Society of Mechanical Engineering (ASME) code
values.
However, the licensee informed the inspectors that the NSCW
system would stay intact and capable of performing its intended safety
function.
Enclosure
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18
During the same review, the licensee also postulated that thirty
containment penetrations, fifteen in each unit. could be susceptible to
thermally induced over)ressurization of water filled, isolated piping
inside containment.
T1e inspectors were informed that subsequent
analysis indicated that twenty-six penetrations would either relieve any
overpressurization through an isolation valve, due to the isolation
valve designs or would remain capable of performing their intended
safety function.
For the four remaining penetrations. the licensee
added caution tags to ensure that the system was operated so as to
prevent any overpressurization of the penetrations during a design basis
event.
On February 14, 1997, this one-hour emergency notification
report was withdrawn.
IV.
Plant Sucoort
R8
Miscellaneous Radiological Protection and Chemistry (RP&C) Issues
(71750)
R8.1
(Closed) Licensee Event Report (LER) 50-425/96-004: Water Sample Not
Taken For Isotopic Analysis Following Power Change.
This issue was previously documented as non-cited violation (NCV)
50-425/96-09-04 in paragraph R2.3 of Inspection Report 96-09.
The
inspectors reviewed the corrective actions identified in the LER and
concluded they are sufficient.
No new issues were raised in the LER.
This LER is closed.
51
Conduct of Security and Safeguards Activities (71750)
S1.1 Routine Observations of Plant Security Measures
During routine inspection activities the inspectors verified that
portions of site security plan were being pro)erly implemented. This
was evidenced by:
proper display of picture Jadges by plant personnel:
l
appropriate key carding of vital area doors: proper searching of
,
packages / personnel at the Protected Area (PA) entrance; and adequacy of
'
compensatory measures (i.e. . posting of guards) during disablement of
vital area Parriers.
Security activities observed during the inspection
i
period were well performed and appeared adequate to ensure physical
protection of the plant. Guards were observed to be alert and
attentive.
Enclosure
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S2
Status of Security Facilities and Equipment
}
S2.1 Walkdown of PA Barriers
a.
Insoection ScoDe (71750)
3
Using Procedure 71750. Plant Support, the inspectors walked down the PA
i
barriers to observe the general condition and verify that the integrity
[
of the fencing and isolation zones around the barriers was maintained.
b.
Observations and Findinas
,
4
i
On January 30 and 31. 1997, the inspectors reviewed the integrity of the
PA barrier.
In general, the fence fabric and barbed wire were in
satisfactory condition.
The isolation zones were well maintained and
clearly posted.
However, during these walkdowns the inspectors
j
identified several minor discrepancies in the material condition of the
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PA boundary. These items were identified'to security management' for
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resolution.
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c.
Conclusions
.
i
The inspectors concluded that for the most 3 art, the general condition
'
of the fencing and isolation zones around t1e PA was being properly
maintained except as noted above.
The inspectors noted that although
minor discrepancies were identified, none of the items represented a
regulatory non-compliance.
V.
Manaaement Meetinas
X
Review of Final Safety Analysis Report
A recent discovery of a licensee operating its facility in a manner
i
contrary to the Updated Final Safety Analysis Report (UFSAR) description
i
highlighted the need for a special focused review that compares plant
practices, procedures and/or parameters to the UFSAR descriptions.
While performing the inspections discussed in this report. the
inspectors reviewed the applicable portions of the UFSAR that related to
the areas inspected. The inspectors verified that the UFSAR wording was
'
consistent with the observed plant practices, procedures and/or
parameters.
X1
Exit Meeting Summary
The inspectors ) resented the inspection results to members of licensee
management at tie conclusion of the inspection on February 6.1997. The
licensee acknowledged the findings presented.
l
Enclosure
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____.m.
.
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20
The inspectors asked the licensee whether any materials examined during
the inspection should be considered proprietary.
No proprietary
information was identified.
PARTIAL LIST OF PERSONS CONTACTED
i
Licensee
J. Beasley. Nuclear Plant General Manager
P. Rushton. Plant Support Assistant General Manager
W. Burmeister Manager Engineering Support
M. Griffis. Manager Plant Maintenance and Modifications
K. Holmes. Manager Maintenance
J
C. Stinespring. Manager Plant Administration
D. Huyck Manager Nuclear Security
M. Slivka. Independent Safety Evaluation Group (ISEG) Supervisor
C. Tippins, Jr., Nuclear Specialist I
INSPECTION PROCEDURES (IPs) USED
'
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IP 37551:
Onsite Engineering
IP 61726:
Surveillance Observations
i
IP 62707:
Maintenance Observations
IP 71707:
Plant Operations
IP 71750:
Plant Support Activities
!
IP 90712:
In-Office Review of Written Reports of Nonroutine. Events at Power
.
Reactor Facilities
l
REFERENCED PROCEDURES AND DRAWINGS
Procedures 11429-1. Rev. 7. and 11429-2. Rev. 11, 480-Volt AC IE
'
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Electrical Distribution System Alignments (Units 1 and 2)
1
Procedure 13150-1 Rev. 18. and 13150-2. Rev. 17. Nuclear Service
!
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Cooling Water System (Units 1 and 2)
Procedure 25021-C. Rev. 14. Coating
1
-
Procedure 11888-C. Rev. 8. Safety Related Locked Valve Manipulation Log
-
Sheet
-
Procedure 11867-2. Rev. 20. Safety Related Locked Valve Verification
)
Checklist
Procedures 11105-1 Rev. 16. and 11105-2 Rev. 8. Safety Injection
-
System Alignment (Units 1 and 2)
1
-
Procedure 28905-C. Rev. 12. Motor Operated Valve Thermal Over Load
l
Bypass 18 Month Verification
-
Procedure 20429-C. Rev. 14. Short Term Documentation of Temporary
Jumpers and Lifted Wires
-
Procedure 27115-C. Rev. 7. Westinghouse SU-1023-8X5 Speed Increaser
Enclosure
I
.
.
.
.
21
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Procedure 14420-1. Rev. 23T. and 14420-2. Rev. 15T. SSPS and Reactor
Trip Breaker Train A Operability Test (Units 1 and 2)
Procedure 14421-1. Rev. 4T. and 14421-2. Rev. 3. SSPS and Reactor Trip
-
Breaker Train B 0)erability Test (Units 1 and 2)
Procedure 00051-C. Rev. 21. Procedure Review and Approval
-
Vendor Manual 2X6AH02-85. 3810-SU-1978. Charging / Safety Injection Manual
-
Drawing 1X3D-AA-F25A Rev. 16. One Line Diagram 480 V Motor Control
-
Center 1BBE
Drawing 2X3D-AA-F25A, Rev. 15. One Line Diagram 480 V Motor Control
-
Center 2BBE
-
Drawing 1X4DB121. Rev. 27. and 2X4DB121. Rev. 32. Safety Injection
System (Unit 1 and 2)
-
Drawing 1X4DB122. Rev. 37. and 2X4DB122. Rev. 35. Residual Heat Removal
System (Units 1 and 2)
l
-
Drawing 1X4DB116-2. Rev. 21. and 2X4DB116-2. Rev. 20. Chemical and
!
Volume Control System (Units 1 and 2)
-
Drawing 1X3AC03-295. Rev.1. Wiring Diagram for Valve 1-HV-8802A
.
l
t
ITEMS OPENED AND CLOSED
j
Ooened
50-425/96-14-01
NSCW Motor Cooler Not Vented Prior To Being
Returned To Service (Section 02.1).
50-425/96-14-02
Inadequate Procedure Results in Loss of One
.
Train of Starting Air for the Unit 2 DG Train A
'
(Section 02.2).
50-424, 425/96-14-03
Configuration Control Deficiencies Involving
Mispositioned Components and Improper
j
Independent Verification (Sections 02.3. 02.4.
and 02.5).
50-425/96-14-04
Failure to Implement Work Instructions for
Unit 2 CCP 2A Speed Increaser (Section M2.1).
50-424. 425/96-14-05
Failure to Im)lement Procedures During P-4
Testing. Two Examples (Section M3.1).
50-424. 425/96-14-06
Potentially Inadequate Surveillance Testing of
P-4 Circuitry (Section 03.1).
Enclosure
.
.
4
22
Closed
50-425/96-14-01
NSCW Motor Cooler Not Vented Prior To Being
Returned To Service (Section 02.1).
50-425/96-14-02-
Inadequate Procedure Results in Loss of One
Train of Starting Air for the Unit 2 DG Train A
(Section 02.2).
50-425/96-14-04
Failure to Implement Work Instructions for
Unit 2 CCP 2A Speed Increaser (Section M2.1).
50-424. 425/96-14-05
Failure to Implement Procedures During P-4
Testing. Two Examples (Section M3.1).
50-425/96-004
LER
Water Sample Not Taken For Isoto)ic Analysis
Following Power Change (Section R8.1).
50-424/96-03-03
IFI
Mispositioned Auxiliary Building Drain Valve
(Section 08.1).
50-424/96-001. Rev. 1
LER
Pipe Fatigue Leads to Nuclear Service Cooling
Water System Inoperability (Section E8.1).
LIST OF ACRONYMS USED
- Alternating Current
--American Society of Mechanical Engineering
- Centrifugal Charging Pump
CFR
- Code of Federal Regulations
CRF
- Coatings Recuest Form
- Chemical anc Volume Control System
- Deficiency Card
- Diesel Generator
- Escalated Enforcement Item
E0P
- Emergency Operating Procedure
- Instrumentation and Controls
IFI
- Inspector Followup Item
IP
- Inspection Procedure
LCO
- Limiting Condition for Operation
LER
- Licensee Event Report
'
- Motor Control Center
MWO
- Maintenance Work Order
- Non-Cited Violation
NPF
- Nuclear Power Facility
NRC
- Nuclear Regulatory Commission
- Nuclear Reactor Regulation
- Nuclear Service Cooling Water
- Nuclear Regulations
Enclosure
,
.
.
A
23
- Protected Area
PDP
- Positive Displacement Pump
- Public Document Room
PE0
- Plant Equipment Operator
- Preventive Maintenance
)sig
- Pounds Per Square Inch Gauge
- Regulatory Guide
- Reactor Operator
RP&C
- Radiological Protection and Chemistry
i
- Safety Injection
SR0
- Senior Reactor Operator
- Shift Superintendert
SSPS
- Solid State Protection System
TS
- Technical Specifications
- Updated Final Safety Analysis Report
- Unresolved Item
USS
- Unit Shift Supervisor
- Violation
l
l
,
l
Enclosure
_