ML20045A535
| ML20045A535 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 05/27/1993 |
| From: | Johnson W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20045A531 | List: |
| References | |
| 50-482-93-08, 50-482-93-8, NUDOCS 9306110040 | |
| Download: ML20045A535 (29) | |
See also: IR 05000482/1993008
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APPENDIX B
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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NRC Inspection Report:
50-482/93-08
Operating License No.: NPF-42
Docket:
50-482
Licensee: Wolf Creek Nuclear Operating Corporation
P. O. Box 411
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Burlington, Kansas 66839
Facility Name: Wolf Creek Generating Station
Inspection At: Coffey County, Burlington, Kansas
Inspection Conducted:
March 28 through May 8,-1993
Inspectors:
G. A. Pick, Senior Resident Inspector
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G. E. Werner, Resident Inspector, Unit 1
Comanche Peak Steam Electric Station
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R. B. Vickrey, Reactor Inspector, Division of Reactor Safety
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R. P. Mullikin, Senior Resident Inspector, Fort Calhoun Station
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Approved:
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5/nf(13
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W. D. Johnsp~h", Chief, Project Section A
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Division o'f Reactor Projects
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Inspection Summary
Areas Inspected:
Routine, unannounced inspection including plant status,
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operational safety verification, maintenance observations, surveillance
observations, engineered safety features system walkdown, followup,' onsite
review of licensee event reports (LER), and inoffice review of LERs.
Results:
There was a violation of Technical Specification 4.0.5 involving a
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missed surveillance. The licensee ineffectively implemented an '
investigation into a potentially missed surveillance, and management
oversight was lacking (Section 2.7).
There was. a violation of Technical
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Specification 6.8.1 a involving inadequate work instructions that.
allowed personnel to. deflect Class 1 piping beyond design deflection
values (Section 2.8).
The inspectors found the self-identification by
license personnel to be an indicator of increasing sensitivity to
stopping work when problems are encountered.
9306110040 930604-
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ADOCK 05000482
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Failure to comply with a limiting conditions for operation action
statement was a noncited violation. A licensee manage'r identified the
concern that flux doubling should be operable in Modes 4 and 5.
The
operations manager implemented prompt corrective actions. The licensee
found that a lack of operator knowledge resulted in an inappropriate
interpretation of a Technical Specification. The corrective actions
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addressed the root cause (Section 2.11).
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The licensee established an investigation team to review clearance order
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deficiencies.
The team identified both programmatic and human factors
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deficiencies. The thorough review identified corrective actions that
address the root cause (Section 2.1).
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The licensee identified an issue relating to the adequacy of procuring
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replacement parts for safety-related components. This issue will remain
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unresolved pending further inspection (Section 2.2).
The licensee performed a hardware failure analysis related-.to a loss of
instrument air and identified the root cause as inadequate preventive
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maintenance.
The system engineer proposed corrective actions to the
design change program to prevent recurrence (Section 2.4).
This issue
will also remain unresolved pending further inspection.
The licensee established a three member investigation group to evaluate
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the circumstances surrounding a hot particle exposure. The
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investigators identified the root cause and corrective actions to
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prevent recurrence (Section 2.5).
Four instances were identified where conditions adverse to quality were
not entered into the corrective action program or the actions taken were
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not able to prevent recurrence.
The licensee has been less than fully
successful in lowering the threshold levels for initiating performance
improvement requests (PIRs) (Sections 2.5, 2.7, 3.1.3, and 4.1).
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In response to NRC concerns, the licensee initiated a surveillance.to
review the timelessness of work group Industry Technical Information
Program (ITIP) evaluations. The licensee determined that the initial
reviews were untimely.
The licensee intends to initiate actions to
address the timeliness of initial ITIP evaluations by the work groups,
including evaluation of safety significance (Section 2.8).
During this period, the inspectors reviewed licensee actions related to'
ITIP evaluations for several issues (Sections 2.8, 2.10, 3.3, and 6).
The licensee performed thorough evaluations and implemented appropriate
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actions, but some evaluations were not timely.
The licensee implemented thorough troubleshooting activities and a
hardware failure analysis investigation into the Emergency Diesel
Generator B thrust bearing failure (Section 3.1.1).
The inspectors
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reviewed troubleshooting of the shutdown air system and observed
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18-month scheduled maintenance of Emergency Diesel Generator A
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(Section 3.1.2).
While performing integrated diesel generator testing,
the licensee caused a waterhammer because of low service water system
pressure during the load' reject of the essential service water pump.
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The licensee implemented a corrective action plan and will develop
system modifications to eliminate or mitigate future system waterhammers
(Section 3.1.3).
A communication error resulted in an inadvertent
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engineered safety features actuation upon securing from the integrated.
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diesel generator testing (Section 3.1.4).
The inspectors reviewed motor-operated valve (MOV) maintenance and test
activities.
The inspectors determined that component defects-identified
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during performance of maintenance did not result from training or
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procedure deficiencies.
Engineering appropriately evaluated valve
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overthrust conditions.
Qualified, well-trained personnel performed the
testing,.and outstanding quality assurance group oversight was evident
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(Section 4.4).
The inspectors conducted a detailed review of residual heat removal.
inservice test results, outstanding work requests, and system readiness.
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The inspectors found the inservice tests- to be' properly implemented.
No
operability problems were created by outstanding work requests
(Section 5).
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Summary of Inspection Findings:
Unresolved Item (URI) 482/9308-01 was opened (Section 2.2).
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URI 482/9308-02 was opened (Section 2.4).
Violation 482/9308-03 was opened (Section 2.7).
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Violation 482/9308-04 was opened (Section 2.9).
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Inspection Followup Item 482/9212-03 was closed (Section 6).
LER 482/91-016, 482/91-020 and 91-020-01, 482/92-009, 482/92-013,
482/92-014, 482/92-015 were' closed (Sections 8'and 9).
Attachments:
Attachment 1 - Persons Contacted and Exit Meeting
Attachment 2 - Documents Reviewed
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DETAILS
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1 PLANT STATUS (71707)
At the beginning of the inspection period, the plant was'defueled and licensee
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personnel continued to troubleshoot the Emergency Diesel-Generator B thrust
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bearing failure. At the end of the inspection period the plant was in Mode 3.
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2 GPERATIONAL SAFETY VERIFICATION (71707)
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The objectives of this inspection were to ensure that the facility was being
operated safely and in conformance with license and regulatory requirements '
and that the licensee's management control systems effectively discharged.the
licensee's responsibilities for safe operation.
The methods used to perform this inspection included direct observation of
activities and equipment, observation of control room operations, tours of the .
facility, interviews and discussions with licensee personnel, independent
verification of safety-system status and Technical Specifications limiting
conditions for operation, verification of corrective actions, and review of
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facility records.
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2.1 Clearance Order Issues
At the end of the last inspection period (refer to NRC Inspection
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Report 50-482/93-03), several potentially significant issues related to
clearance orders occurred.
Consequently, on March 26, 1993, the licensee
established an investigation team in accordance with Procedure _ADM 01-116,
" Incident Investigation," Revision 4.
The investigation team reviewed
clearance order incidents over the period March 4-26, 1993. The licensee
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reviewed 10 incidents which were documented by PIRs.
Personnel identified
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many of the incidents before beginning work activities and prior to any
adverse consequences.
The investigation team reviewed the individual issues identifying human
performance and programmatic issues.
Human performance errors
included:
(1) failure of personnel to properly _ perform clearance order
verifications, (2) a lack of self-checking, (3) poor written and verbal ~
communications, and (4) reliance on the " notes" portion of a clearance order
to provide significant information.
This latter issue relates to the use of
the notes section to describe the order that clearance orders should be
released, in addition to providing guidance for plant activities such as
equipment testing.
Potentially significant programmatic weaknesses identified by the-
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investigation team included: . (1) the level of detail in General Employee
Training was insufficient for contract workers who work with clearance orders,
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(2) clearance order acceptors failed to thoroughly perform walkdowns to assure-
the clearance order bounded the' work activity, (3) the failure to have. work
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packages prepared 30 days prior to the outage impacted the clearance order
group's ability to process clearance orders for emergent' work, and (4) the
licensee failed to include local leak rate tests on the outage schedule but
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relied on the local leak rate test for system configuration control.
Additional weaknesses identified included:
(1) management expectations not
clearly identified or enforced, (2) scheduling of work activities within
outage windows needs to be better planned and coordinated, and (3) late outage
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work package preparation resulted in an inordinate amount of clearance order
changes.
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The investigation team recommended the following corrective actions:
Evaluate the clearance order procedure for human factor considerations,
Evaluate the training requirements for temporary personnel,
Evaluate the need to use clearance orders for local leak rate test
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boundaries and the need to schedule local leak rate tests,
Assess the effectiveness of controls that ensure that' work packages are
prepared prior to the outage,
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Ensure that personnel are aware of management expectations, and
Implement the self-checking program.
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The inspectors monitored the investigation team activities during the review
process. The investigation' team thoroughly evaluated each incident.
The
investigation report documented the individual incidents, including pertinent
human performance weaknesses and programmatic deficiencies that contributed to
the avent. The investigation team related those incidents with similar
weaknesses.
The inspectors verified that the most significant clearance order deficiencies
were those described in NRC Inspection Report 50-482/93-03.
2.2 Excessive Valve Leakage
On March 30, 1993, the licensee initiated differential pressure testing on
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MOV EN HV012, Containment Spray Pump B discharge isolation valve, in
accordance with Procedure TP TS-90, "EN HV012.MOV DP Test," Revision 0.
Licensee personnel had.previously installed a new valve disc under Work
Request 00758-93, which had provided seismic design instructions for upgrading
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the valve disc to increase existing margins, as specified by Plant
Modification Request 04439, "10-inch Flex Wedge Gate Valve Disc Replacement."
The replacement valve disc material had greater strength, and a different
disc-ear design strengthened the valve.
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The test was secured because of excessive leakage past the valve disc with the
valve closed.
The licensee subsequently disassembled the valve and
reinstalled the old disc since the old disc provided sufficient margin for the
seismic design requirements.
The licensee performed a successful differential
pressure test.
From discussions with personnel involved and review of Work Request 00758-93
special instructions, the inspectors found that the licensee appropriately
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specified a postmaintenance leak test to verify proper installation.
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licensee had previously demonstrated that lapping and blue checking the valve
seat and other functional checks were not sufficient to verify installation
inappropriate for this application.
Because of the inability to perform
functional checks on this valve, licensee personnel committed to identify
other similarly configured valves that required complete reassembly and leak
testing to verify maintenance was sufficient.
By identifying these similarly
configured valves, licensee personnel would know whether future repairs could
be implemented within a 72-hour action statement.
The licensee stated they
would have similar valves identified by August 31, 1993.
The inspectors conducted followup to determine the cause of the replacement
valve failing the postmaintenance differential pressure test.
The inspectors
determined that the valve vendor supplies slightly oversized generic
replacement valve disks that required machining and/or lapping to fit the
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valve seat wear pattern, a vendor procurement requirement the licensee was not
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aware of at the time the replacement disk was ordered.
Had the replacement
disks been ordered with dimensions specified, they would have been supplied
pre-machined by the vendor and correctly sized. The licensee initiated
Commodity Discrepancy Report (CDR) 93 0237, the corrective action document for
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conditions adverse to quality that have been discovered in their procurement
process.
This CDR identified the probitm with ensuring that correct
dimensional information was provided in procurement documents for replacement
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valve parts. This issue concerning adequate procurement of replacement parts
will remain unresolved pending further NRC inspection, and will be tracked as
URI 482/9308-01.
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2.3 Management Meetinq
On March 31, 1993, Wolf Creek Nuclear Operating Corporation personnel provided
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an update to NRC Region IV personnel on the status of the licensee's
Performance Enhancement Program.
Some well-developed action plans being
implemented included relocation of engineering personnel from Wichita to the
site, the system engineering training and implementation program, and creation
of the integrated cheduling and plann'.ng group.
The licensee discussed their
plans for conducting a midcycle self-assessment similar to a Systematic
Assessment of Licensee Performance.
2.4
Instrument Air System Failure Evaluations
In March 1993 the instrument air system failed because of sticking solenoid
valves (refer to NRC Inspection Report 50-482/93-03).
The inspectors
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performed a followup review of the licensee investigation. The licensee
initiated Hardware Failure Analysis (HFA) NP 93-005 to evaluate the root cause
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of the failure of the three-way pilot air solenoid valves and HFA NP 93-006 to
evaluate the root cause of the failure of the four-way solenoid valves.
The responsible system engineer collected data and information, inspected and
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bench tested the valves, and returned the valves to the vendor for failure
analysis. The system engineer verified that desiccant did not carry over and
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that the system air quality met specifications.
From discussions with the
vendors and review of industry information, the system engineer identified
inadequate maintenance as the root cause for the sticking solenoid valves.
The system engineer determined that the licensee failed to implement vendor
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recommended preventive maintenance following installation of new air dryer
towers in May 1991 under Plant Modification Request 02495.
This modification
had not been closed and, as a result, the licensee had not implemented into
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maintenance procedures vendor manual recommendations for annual inspections,
valve stop adjustments, and elastomer replacement.
As a result, the air dryer-
towers had not receind vendor recor., mended maintenance, which caused degrading -
and solenoid valve failure.
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The inspectors determined that, typically, when the licensee closes a plant
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modification, they ensure that all drawings were correct, affected system
operating and maintenance procedures have been properly changed, and vendor
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manuals have been updated.
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The licensee plans to implement preventive maintenance requirements for annual
inspections and replacements. The licensee intends to expeditiously close
Plant Modification Request 02495 following the outage, with the vendor
technical manuals having the highest priority.
In addition, the system
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engineer recommended the following programmatic changes to prevent recurrence:
Evaluate a method to release important documents (vendor manuals,
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drawings) independent of the plant modification closecut and
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Evaluate closing out large modification packages immediately after
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installation.
The licensee stated they ould implement one or both of these enhancements in
order to preclude recurre :e of this problem.
This issue will remain
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unresolved pending further NRC inspection, and will be tracked as URI
482/9308-02.
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2.5 Hot Particle Exposure
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On April 2,1993, the licensee found a hot particle on the left thigh of a
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nonlicensed operator. -The nonlicensed operator acquired the hot particle
while filling and venting the safety injection system inside the containment.
A personnel contamination monitor located outside of containment detected the -
hot particle.
The licensee confirmed that the hot particle consisted of.
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16 different fission product isotopes.
By using the VARSKIN code, the
licensee determined the exposure to be 33.9 rem (8 microcurie hours) to the
skin.
The licensee considered the' estimated exposure to be conservative
because VARSKIN does not account for any self-shielding effects.
Subsequently, on April 4,1993, the licensee made a 24-hour report pursuant to
10 CFR Section 20.403. Also, the licensee formed a three-member root cause
evaluation team.
The inspectors reviewed the licensee activities related to this hot particle
exposure. The licensee initiated a Level I radiological occurrence report as
required by Procedure ADM 03-011, " Radiological Occurrence Report Program,"
Revision 4.
Additionally, the licensee initiaced PIR TS 93-0301 to document
the root cause investigation and corrective actions.
The licensee reported
this event as LER 482/93-006.
This hot particle exposure differed from a
previous event (refer to LER 482/92-007) that involved a hot particle acquired
while an individual inspected reactor coolant system crossover pipe
restraints.
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The licensee's investigation determined that the hot particle transferred to
the nonlicensed operator as he rolled the drain hose, following the filling
and venting of the safety injection system.
The inspectors found the
investigation by the root cause team to be superior. The. team identified the
root cause, including several underlying weaknesses such as inadequate
training and procedures.
The proposed corrective actions address the
identified weaknesses and the root cause. The corrective actions _to prevent
recurrence include:
creating a preventive maintenance activity to
decontaminate the drain trenches, revising appropriate qualification
requirements related to venting / draining of contaminated systems, training of
affected personnel on the revised qualification requirements, and fabricating
nozzles that eliminate back splash.
2.6 Valve Stroke Time Testinq
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On April 5,1993, licensee personnel determined that MOV EJ HV8716A, Residual-
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Heat Removal A to safety injection system hot leg recirculation loops 2 and 3
isolation, failed to meet the stroke-time testing specified in
Procedure STS EJ-202, "RHR System Inservice Valve Test," Revision 2.
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licensee determined that the stroke time met design specifications and
initiated a procedure change to adjust the allowable stroke time. The
licensee identified other valves that would probably exceed the allowable
stroke time listed in surveillance procedures.
Subsequently, the licensee
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provided information to control room personnel stating changes should be made
to surveillance procedures, as needed.
If the stroke time exceeded design-
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specifications, the instructions specified that personnel should document the
test deficiency and contact system engineering.
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Licensee personnel modified stroke times when they changed the MOV gear ratios
in order to comply with Generic Letter 89-10, " Safety-Related Motor-Operated
Valve Testing and Surveillance," requirements.
The personnel, while
concentrating on performing differential pressure testing and correcting the
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design, did not consider the effect'of changing stroke times on other plant
programs.
The licensee did not issue a PIR to document the coordination
problems associated with changing the stroke times-in the valve surveillance
procedures.
The inspectors identified two other occurrences that appeared to reach the
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threshold for PIR initiation; however, no PIR was issued (refer to
Sections 2.7 and 4.1).
The reluctance of station personnel to generate.PIRs
has been a problem previously identified in NRC Inspection
Report 50-482/92-24.
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Subsequent to the inspectors identifying these issues, the licensee initiated
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PIRs for each of the three instances and conducted meetings with the affected
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groups to discuss the appropriate threshold.
In addition, the licensee
initiated a separate PIR addressing the inspectors' concerns so that generic
actions would be taken. Also, the licensee conducted a briefing about changes
to their corrective action program which are scheduled to be implemented by
June 1, 1993. The major changes to the program included:
Simplifying the process by removing the initial supervisor review,
Creating a screening group to review all PIRs for significance, and
Allcwing personnel to submit PIRs anonymously.
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From discussions with personnel, the inspectors found that these actions, if
adequately taken, should lower the threshold for PIR initiation since.
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personnel will no longer be required to justify writing a PIR. The screening
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group would appear to make the process more effective by providing consistency
in determining significance and priority. Also, these actions would appear to
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remove any perception by supervisors that PIRs increase workload. The
licersee plans to hold departmental meetings and will promulgate the
information in the weekly and monthly newsletters. The inspector will
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continue to closely monitor the actions taken by the licensee to improve their
corrective action program.
2.7 Late Surveillance
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On April 13, 1993, the licensee determined that the quarterly operability test
for Residual Heat Removal Pump B was overdue. The surveillance became due on
March 18, 1993, and _ late on April 10, 1993.
The licensee performs the
surveillance in accordance with Procedure STS EJ-100B, "RHR System Inservice-
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Pump B Test," Revision 8.
The licensee immediately performed the surveillance
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test and initiated'PIR OP 93-0331-to document the. event, determine-the' root
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cause, and implement corrective actions. The licensee promptly reviewed the
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late surveillance list in order to identify other late surveillances. The
licensee reported the_ event as LER 482/93-007. With Residual Heat'
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Removal- Pump B inoperable, the licensee violated the limiting conditions for
operation of Technical Specification 3.9.8.2.
The Technical Specification
requires, in Mode 6 with water level less than 23 feet above the reactor
vessel. flange, two residual heat removal loops shall be OPERABLE with one
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operating.
The licensee lowered the refueling pool level below 23 feet above
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the reactor vessel flange on April 11, 1993.
On April 12, 1993, operators
decreased reactor vessel level to approximately 5 feet below the flange and,
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on April 13,1993,-licensed operators stabilized the water level at 15 inches
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below the reactor vessel flange. Although Residual Heat Removal Pump B was
inoperable, the pump remained functional. '
The licensee identified several causes for the missed surveillance-test.
Surveillance group personnel failed to initiate a thorough investigation of
the potentially late surveillance, as specified in Procedure ADM 02-300,
" Surveillance Testing," Revision 18. Although surveillance group personnel
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informed management of the surveillance requirement as it approached'the due
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date, they failed to notify the control room so that appropriate action could
be taken to ensure the surveillance was completed.
A second reason involved a
lack of oversight by management personnel of the surveillance group's
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investigation. Also, surveillance group personnel removed the surveillance
from the test schedule after operators removed the pump from service.
Personnel added the test to the work activity schedule; however, operators do
not utilize the work activity schedule for planning during outages.
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The failure to properly conduct the potentially overdue surveillance
investigation in accordance with Procedure ADM 02-300 was a violation of
station procedures.
Additionally, the failure to perform the operability test
as.specified by Technical Specification 4.0.5 resulted in the violation of
Technical Specification Limiting Conditions for Operation 3.9.8.2
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(482/9308-03).
The licensee will develop a procedure for the investigation process to ensure
that a complete evaluation is performed. The licensee will evaluate the use
of a single schedule and will review other methods to add, delete, and
reschedule surveillance tests.
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The inspectors reviewed previous instances of Technical Specification
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violations involving failure to perform surveillance-tests within required
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time limits.
The most recent examples related to problems with the database
and a failure of a personnel outside of operations to follow procedure.
In
July 1991, personnel did not complete all portions of a' surveillance test but
documented test completion, resulting in a Technical Specification violation.
As a corrective action, the licensee initiated the investigation requirement
for potentially late surveillances.
The inspectors considered the most recent
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failure to be ineffective implementation of corrective actions.
Upon completion of Procedure STS EJ-100B, reactor vessel level unexpectedly
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rose 16 inches.
The licensee identified the problem to be a misplaced step in
the procedure. Despite this procedural problem being identified, a PIR was
not initiated until the problem was questioned by the inspectors.
This was
considered another example of poor implementation of the licensee's corrective
action program and the second example of licensee personnel's low threshold
for initiation of PIRs.
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2.8 Quality Assurance Surveillance Activities
During this period, quality assurance auditors completed an evaluation of the
timeliness of work group ITIP reviews.
The licensee initiated the
surveillance after inspectors expressed concern about the timeliness of these
reviews. The licensee documented the review in Surveillance Report S-2031,-
"ITIP Evaluation." The auditor selected a sample of 92 outstanding ITIPs that
exceeded the original 45-day evaluation due date.
The surveillance documented
strengths and several weaknesses related to'the program.
The surveillance documented that Nuclear Safety Engineering personnel
performed good initial evaluations. The auditor found that work groups that
process large numbers of ITIPs did not always complete timely. reviews.
Since
the extension process did not provide acceptance or rejection criter.ia,
Nuclear Safety Engineering personnel granted all extension requests. Also,
extension requests failed to properly document the basis for extension.
Programmatic problems included:
(1) personnel did not differentiate between
evaluation of ITIPS for significance and implementation of corrective actions
and (2) personnel used the 45-day initial evaluation period to establish a
forecast date for corrective actions, instead of performing evaluations. The
auditor recommended that the procedure requircments for extension requests and
evaluations be strengthened and clarified.
ITIPs generally resulted in plant
enhancements.
The auditor determined the program would be more effective. if
initial 45-day evaluations identified significance and required corrective
actions to be implemented in a manner relative to safety significance.
The
inspectors found the audit to be detailed, exhaustive, and effective. The
auditor provided many useful observations about the program.
2.9 Pressurizer Safety Valve Discharge Pipe Alignment
On April 10, 1993, licensee personnel identified a 1 1/2-inch vertical and
2 3/4-inch horizontal misalignment between the Pressurizer Safety
Valve BB 8010C flange and the discharge pipe flange. The pressurizer-safety
valve is ASME Class 1 and the discharge piping was fabricated and -installed in
accordance with the B31.1 power piping code'.
Licensee personnel had
disassembled the flanges and bench tested the' safety valve in accordance with
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a preventive maintenance work request.
A maintenance engineer initiated Work
Request 02447-93 that requested design engineering to approve reworking the
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' discharge piping to allow alignment of the piping, to evaluate the existing-
condition to determine the effects on the piping service life, and to review
the potential for additional cold springing of the piping. -Additiona'lly, the
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licensee initiated Reportability Evaluation Request 93-024 'to evaluate
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reportability_and operability and' initiated PIR MA 93-0374 to review
circumstances related to previous cold springing of the pipes.
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discussions with licensee personnel, the inspectors determined-that personnel
had -to jack the piping during previous refueling outages when assembling the
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pressurizer safety valve to the discharge piping.
During Refuel II, the licensee found the Constant Support BB02-H004 strut'
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paddle bent. Upon investigating, the licensee noted that an installed load
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pin prevented free movement of the pressurizer safety valve line. The
licensee performed a liquid penetrant examination of all piping and elbows
between the pipe support and the first upstream _ field weld. The licensee
performed radiot.aphy, visual examinations, hardness tests, and metallographic
examinations. The licensee inspected other constant supports, verifying that-
no other load pins remained installed.
Engineering determined from the above
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tests that the piping had not exceeded its tensile strength and that the
plastic deformation experienced would not offset the ability of the piping to
perform its design function.
Engineering determined that the piping was
acceptable for six previous heatup/cooldown cycles and an added six
unrestrained cycles.
After engineering learned about the cold springing of the piping on four
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occasions from 1987 to 1993, they performed additional evaluations. The
engineers visually confirmed that the safety valve flange was below the
discharge pipe mating flange.
The licensee determined that the Class 1 pipe
sloped downward, away from the pressurizer, at 3/8 inch per foot. The licensee
performed additional liquid penetrant testing to look for defects. The piping
thermally expended 2.78 inch, but the pinned restraint allowed 0.5 to
0.75 inches of movement before the pipe would start deforming.
The piping
plasticly deformed 1.5 to 1.75 inches that corresponded to the 1.5-inch
vertical offset.
The licensee determined that the stresses required to cold spring the piping
approximated 60 percent of the tensile stress. The motion of the safety _
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nozzle during the heatup relieved the stresses created by the cold springing.
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The licensee performed a design analysis in accordance with the ASME Code.
The licensee fatigue analysis determined the fatigue usage from cold springing
to be 0.001 out of a total fatigue usage of 0.163.
Since the calculated
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fatigue usage remained less than the allowable of 1.0, the licensee concluded
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that the pipe was acceptable for the plant life.
However, because the fatigue
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usage exceeded 0.1, the licensee postulated an additional break.at the
a
affected elbow. This elbow was not listed in the Updated Safety Analysis
Report; consequently, the licensee will update the Updated Safety Analysis _
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Report.
Specification M-204(Q), Appendix D, " Compensation Allowances For Piping
Misalignment," Revision 40, provided guidance to be observed in the field for
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aligning safety-related piping. The licensee determined _that the maximum
allowed pipe movement for alignment was 1/2 inch.
The inspectors determined
that the licensee moved the pipe during past refueling outages for greater
!
distances.
From review of records'from Refuel V, the inspectors determined
that the Work Request 60097-91 instructions failed to specify the design
specification limits or any precautions to prevent excessive cold springing.
,
further, the inspectors determined that licensee personnel did not document
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the distance that they deflected the piping. The failure to provide adequate
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work instructions was a violation of Technical Specification 6.8.1.a
(482/9308-04).
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2.10 Lead-Lag Time Constant Setpoints
The licensee conducted an evaluation of Technical Specification trip setpoint
lead-lag time constants in response to ITIP 02226, " Operating
Experience OE 5779:
Use of Tolerances for Time Constant Settings Required In
Technical Specification."
ITIP 02226 documented that another facility's
procedures allowed the lead-lag time constants to be incorrectly set.
Because
the time constants were misadjusted, the facility considered their instruments
The licensee's nuclear analysis group evaluated the effects on Technical
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Specification setpoints of varying time constants
5 percent.
The reactor
trip setpoints affected included steam line low pressure and steam line
pressure negative rate high. The nuclear analysis group determined that the
lag term (Tau-2) could range from 4.75 to 5.25 seconds.
The lead term (Tau-1)
could range from 47.5 to 52.5 seconds.
The licensee determined that these
ranges were adequate because a range of values 'are an accepted methodology
when performing calibrations.
The inspectors expressed concern that, even though the methods allow for a-
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range of values, the Technical Specifications require Tau-l to be greater than
or equal to 50 seconds and Tau-2 to be less than or equal to 5 seconds.
With
the inequality, the inspectors questioned why as-left values should not be
within the boundary values including allowances for instrument inaccuracies.
As a result, the licensee changed the effective procedure's acceptance
criteria to require that the time constant settings meet the Technical
Specification acceptance criteria and allow for instrument inaccuracies. The
licensee demonstrated that varying the time constants significantly had
minimal effect on the Technical Specification setpoints and less than a 0.loF
rise in the peak design basis containment temperature. Additionally, industry
information demonstrated that leaving the as-left values outside the limits
but within the test instrument accuracy was accepted practice.
2.11 Limiting Conditions For Operation Violation
On April 28, 1993, the licensee determined that they failed to comply with-the
action statement associated with Limiting Conditions For Operation 3.3.1,
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Table 3.3-1, " Reactor Trip System Instrumentation," Functional Unit 6,b.
Functional Unit 6.b specified requirements for maintaining the minimum number
of source range channels operable in Modes 3, 4, and 5, including the flux
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doubling circuitry.
The action statement specified,~with no channels
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operable, verify the reactor trip breakers open, stop all positive reactivity.
changes, verify compliance with shutdown-margin requirements within I hour,
and verify two valves to be closed and secured in position'within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
From interviews with licensee personnel, the inspectors determined that a
1
shift outage manger initiated PIR OP 93-0375 that questioned the Technical
r
Specification requirements that applied when _ blocking the flux doubling
circuit in Modes 3, 4, and 5,
aso, PIR OP 93-0375 specified that the Updated.
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Safety Analysis Report analysis may have bean outside the analyzed band,- and
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inadequate criticality protection existed.
The shift outage manager raised
this potential problem with the on-duty operating crew.
Licensed operators
considered the functional unit requirements applicable to only the source
range channels when in Modes 4 and 5 because of the Technical Sp'ecification
table description of the source range channel.
Subsequently, the operations
manager determined that the Limiting Conditions for Operation 3.3.1,
Table 3.3-1, Functional Unit 6.b, applied to the flux doubling circuitry and
that previous interpretations were incorrect.
The licensed operators
immediately entered the action statement and met its requirements.
Since the
flux doubling circuitry was blocked 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 16 minutes earlier, the licensee
failed to comply with all actions as specified in Technical Specification
Limiting Conditions for Operation 3.3.1, Table 3.3-1, Functional Unit 6.b.
The inspectors reviewed the licensee response to this deficiency.
The
licensee immediately issued a memorandum to all shift supervisor / supervising.
operators documenting the deficiency, describing the system operation, and
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specifying proper interpretation of the Technical Specification. Additional
long-term actions to prevent recurrence included:
(1) enhancing appropriate
procedures to reference Technical Specification 3.3.1, Table 3.3-1, Functional
Unit 6.b; (2) changing Procedure ALR 00-0578, "SR Flux Doubled
Bypassed / Blocked," to reference Technical Specification 3.3.1; and
(3) incorporating this occurrence into industry events training.
The
violation of Technical Specification 3.3.1, Table 3.3-1, Functional Unit 6.b,
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will not be cited because the criteria specified in Paragraph VII.b.2 of the
NRC Enforcement Policy were satisfied.
The inspectors considered the self-identification and proactive nature of
licensee management in response to this problem to be very good.
The licensee
will report this event as LER 482/93-008.
On May 6,1993, Source Range Detector N-31 failed low then returned on scale.
As this occurred, the flux doubling circuits actuated, swapping the charging
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pump suction from the volume control tank to the refueling water storage tank,
as designed. Operators promptly entered the appropriate action statement and
took the necessary actions. The licensee identified the detector failure to
be a problem in the instrument cable connector.
2.12 Conclusions
An investigation team performed a comprehensive evaluation of clearance order
deficiencies that identified several human performance and programmatic
deficiencies.
Maintenance personnel properly determined the appropriate
postmaintenance test for an MOV.
Because of the potential to impact Technical
Specification limiting conditions for operation time limits, the licensee
,
committed to complete an evaluation to identify MOVs that have similar
postmaintenance test requirements by August 31
1993. An additional issue was
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identified concerning the adequacy of procuring replacement parts for
safety-related valves. This issue will remain unresolved.
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The instrument air system engineer performed an outstanding evaluation of the
root cause of the loss of instrument air. The engineer identified
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programmatic weaknesses in the design change process during his review.
These
programmatic weaknesses will remain unresolved pending further NRC review.
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The licensee established a root cause team to evaluate a hot particle
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exposure.
The root cause team provided comprehensive recommendations to
prevent recurrence.
The inspector identified several issues where the licensee's threshold for PIR
initiation does not appear to have attained an adequate level where problems
are identified and resolved utilizing their corrective action program.
Late surveillance test performance resulted in the licensee failing to meet
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residual heat removal pump operability requirements. After inspectors
questioned the timeliness of work group ITIP evaluations, the licensee
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initiated a quality assurance surveillance. The licensee found that work
groups with large workloads failed to perform timely initial evaluations of
ITIPs. The licensee determined that personnel needed to perform the
evaluation in a timely matter then initiate corrective actions in a time frame
pursuant to the safety significance of the issue.
Deflection of
safety-related piping outside permissible limits was a violation.
The
licensee performed a comprehensive review of an ITIP related to lead-lag time
constants, determining that misadjustment of the constants had minimal effect
on Technical Specification setpoints.
A noncited violation resulted from a
failure to properly follow a limiting conditions for operation action
statement.
The licensee response to the issue was prompt and effective.
3 MAINTENANCE OBSERVATIONS (62703)
The purpose of inspections in this area was to ascertain that maintenance
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activities on safety-related systems and components were conducted in
accordance with approved procedures and Technical Specifications. Methods.
used in this inspection included direct observations of maintenance
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activities, interviews with personnel, and review of records.
3.1
3.1.1
Emergency Diesel Generator B Activities
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During a 24-hour maintenance test of Emergency Diesel Generator B on
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March 23,1993, the licensee received a thrust bearing high temperature alarm
(refer to NRC Inspection Report 50-482/93-03).
During this period,'the
inspectors monitored and reviewed licensee activities.for repairing the thrust
bearing and for evaluating the root cause. The licensee initiated Hardware
Failure Analysis NP 93-008 to identify the root cause and . determine corrective
actions required to prevent recurrence.
!
The licensee machined the journal surface of the crankshaft by 1.5 mm and
installed an oversized bearing supplied from vendor stores. .The licensee
performed a hardness test to assure that the journal shaft met design
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specifications.
The licensee inspected two m&in shaft bearings and found
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aluminum oxide particles in the babbitt material.
The licensee shipped the
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bearings to a root cause expert for evaluation and installed new bearings.
The licensee replaced the other main bearings tpon recommendation of the root
cause expert to positively assure that no problems occurred because of trapped
particles.
Because vendor personnel had removed and overhauled seven cylinders to install
cylinder rings, the licensee reinspected the babbitt insert for one connecting
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rod bearing. The licensee found a small indication; hence, the licensee
inspected the remaining connecting rod bearings.
The licensee replaced
Connecting Rod Bearings 6, 11, and 13 and reused the other connecting rod
bearings.
The licensee removed Piston 13 from the engine for additional
inspections, after they identified a slight indication in the bearing surface
metal. The licensee found that the cylinder walls were unaffected and no
particulate contaminated the wrist pin bearing.
The licensee inspected the
cam lobe surfaces and the cam oil troughs, finding no debris.
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The licensee determined the root cause of the failure to be debris introduced
into the emergency diesel generator during maintenance activities.
The
e
licensee could not determine how the debris entered the emergency diesel
generator and flowed past the lubricating oil filters and strainers.
The
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licensee determined that the debris ,ocated on the bearing surfaces included
aluminum oxide particles with some nickel.
The licensee measured several
particles sized larger than 100 microns, with the strainer sized at
56 microns.
Since the lubricating oil header was never disassembled or
breached after installation of the emergency diesel generator skids, the
licensee narrowed the ingress of debris to maintenance activities related to
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the strainers.
The licensee performed an extensive lubricatii g oil flush of
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the lubricating oil headers, followed by the main bearings ano the cylinders.
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The licensee hired a second root cause failure expert to confirni the opinions
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of the original expert.
Both experts confirmed debris contamination caused
the failure. Other failure mechanisms reviewed and eliminated included thrust
bearing housing vibration, lubricating oil thinning / overheating, oil
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starvation, alignment problems, and radial / torsional crankshaft vibration.
!
The licensee evaluated the strainer cleaning method, element- assembly, and
piping arrangement for connecting the clean and dirty sides. Although each
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had a high potential for allowing particle ingress, the licensee methods were
not contributors at this time.
The root cause team recommended that personnel
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evaluate rerouting the strainer drain piping to eliminate any potential.to
cross-connect the clean and dirty side and that the work instructions be
revised to require removal of the strainer assembly prior to disassembly.
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While placing an I-beam to support the main generator shaft to allow
inspection of the outer thrust bearing, personnel nicked the stator windings.
The licensee broke the insulation in two locations and nicked the insulation
in two locations.
The licensee consulted the vendor and developed a thorough,
detailed method for repairing the generator stator windings. The licensee
blended the nicks and retaped the windings in accordance with vendor
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recommendations.
During the first attempt to reinsulate the windings, a
- plastic thermocouple housing melted and shorted, allowing the bake temperature
to increase. The licensee retaped the windings and reinitiated the insulation
bake process to assure good repair of the stator insulation.
!
3.1.2
Emergency Diesel Generator A Repairs
During the 18-month overhaul of Emergency Diesel Generator A, the inspectors
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observed maintenance implementation, in part, as specified in.
Procedure STS MT-016, " Standby Diesel Generator Inspection," Revision 9.
The
inspectors observed personnel perform web deflection measurements and bearing
clearance measurements.
The inspectors monitored licensee inspections of the -
thrust bearing, cleaning of the lubricating oil strainers, and governor
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mechanism oil replacement.
The licensee identified minimal scratching of the-
inner thrust bearing.
The inspectors reviewed the licensee activities for t:aubleshooting the
shutdown portion of the starting air system as discussed in NRC Inspection
Report 50-482/93-01. The licensee performed the troubleshooting as specified-
in Work Request 00642-93.
The licensee measured the pressure at eight
locations, determining that the air pressure did not decrease. The licensee
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selected the locations because they provided information about suspected
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trouble points.
!
The licensee replaced several components in the shutdown air system and
modified others to ensure system reliability.
The licensee replaced the.
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shutdown tank inlet check valve internals, overhauled the excess flow check
valves that included drilling a 1/64-inch hole in the poppet, and replaced the
sticking three-way vent valves. Quality assurance personnel performed
independent coverage of the air system troubleshooting for both Emergency
Diesel Generators A and B.
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3.1.3
Waterhammer
On May 4,1993, while performing the load reject-test of the single largest
load for Emergency Diesel Generator B, as required by Technical Specification
Surveillance Requirement 4.8.1.1.2.g.2, a waterhammer occurred at Containment
!
Coolers B and D.
The licensee performed the test in accordance with
Procedure STS KJ-001B, " Integrated D/G and Safeguards Actuation
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Test - irain B," Revision 11, Section 5.4.17.
Following similar waterhammers~
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in Refuel V, the licensee altered both Train A and B procedures to require
operation of the service water pumps and opening of the cross-connect valves'
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to the respective essential service water train. The single largest load is.
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the applicable essential service water pump. ' Previously, when rejecting the
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essential service water pump, the water in the stand pipe to the containment
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coolers would begin gravity draining, and a waterhammer resulted when the
essential service water pump was started.
During the Train A test, no waterhammer occurred. Two service water pumps
were operating, and the service water system pressure was 120 psig.
During
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the Emergency Diesel Generator B load reject test, the licensee secured a
service water pump and decreased the system pressure to 105 psig. The
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licensee initiated these actions to decrease vibration of a flow orifice
sensing line flange that had a 2700 circumferential crack in a weld continuing-
to propagate. The licensee concluded that the low system pressure was not
sufficient to prevent gravity draining of the containment coolers;
consequently, the waterhammer occurred.
The inspectors noted that similar waterhammer events occurred in November 1988-
and November 1991.
Although the corrective action taken to address the 1991
waterhammer event appeared to take appropriate actions to prevent recurrence,
the procedural changes were not suffi.ciently thorough to specify the minimum
service water pressure required to prevent gravity draining of the piping from
the containment coolers.
This issue constitutes the third example of the
licensee's poor implementation of their corrective action program. The
licensee informed the inspectors the following actions would be implemented:
Identify the minimum service water system pressure required to prevent
gravity draining,
Evaluate the effects on the safety-related piping-and components, and
t
Implement a modification to eliminate the waterhammer or minimize the
consequences.
3.1.4
Engineered Safety Features Actuation
On May 4, 1993, while restoring from Procedure STS KJ-001B, a communication
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error resulted in an inadvertent engineered safety features actuation. . The
test director specified resetting the safety injection signals and blocking
the low steam line pressure signals. The supervising operator repeated the
instructions; however, upon directing the reactor operator, the supervising
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operator only mentioned resetting the safety injection signals.
The reactor
operator failed to recognize. plant conditions while following the
instructions.
Because of the integrated safeguards testing, most components
were disabled to prevent actuations. However, the components which were not
isolated actuated.
The control room ventilation began . recirculating,
Emergency Diesel Generator B autostarted, and the containment purge system
isolated.
The licensee made a 4-hour nonemergency 10 CFR Section 50.72
3
notification. The licensee will issue an LER.
3.2 Feedwater Valve Repair
On April 28, 1993, the inspectors observed maintenance personnel reassemble
.,
Valve AF LV009, High Pressure Heater 7A to low pressure condenser level
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control.
The licensee repaired the valve because water leaked past the valve
seat when operators closed the valve.
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The mechanic assembling the retainer ring into the valve body demonstrated
detailed, thorough knowledge of the valve design, the failure mechanism (steam
cutting), and equipment operation. The mechanic used a hydraulic torque
machine to torque the retainer ring to 2250 foot-pounds.
3.3 Limit Switch Replacements
On May 5,1993, the inspectors observed electrical maintenance personnel
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replace "close" limit switches on main steam isolation valves and main
feedwater isolation valves.
The inspectors observed limit switch replacements
controlled by Work Requests 03159-93, 03162-93, and 03158-93.
Discussions
with electricians and quality control personnel indicated they were familiar
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with the job purpose.
The inspectors considered the work instructions to be
detailed.
Instrumentation and control personnel found the switches to be
sticky while implementing Plant Modification Request 04546, " Modify Limit
.
Switch Mounting Bracket for MSIV and FWIV." The plant modification request
specified installing new limit switch brackets that would allow fine tuning of
the limit switch positions.
Concurrently, the licensee determined that
ITIP 2259, "NAMCO Controls Corporation Letter: Maintenance and Surveillance
Instruction For EA180 Series Limit Switches," specified the useful qualified
grease life at various temperatures and specified that spare parts were no
longer available.
3.4 Position Indication Test
The inspectors observed the postmaintenance testing on MOV EM HV88218, the
Safety injection Pump B discharge accumulator injection isolation valve. The
operators conducted the stroke test in accordance with Procedure STS EM-201,
" Safety Injection System Inservice Valve Test," Revision 3, Section 5.2.2.
This section measured the closing stroke time and verified that the position
indicator accurately reflected the valve position.
The licensed operators
used appropriate communications and good self-checking.
3.5 Conclusions
The licensee implemented extensive repairs to Emergency Diesel Generator B to
assure operability. The licensee conducted a comprehensive hardware failure
analysis review to identify the root cause. The licensee performed-
troubleshooting to identify the root cause for the failure of Emergency Diesel
Generator A to shutdown.
The inspectors determined that personnel performing
maintenance were knowledgeable, and appropriate postmaintenance testing was
specified.
Licensee activities to prevent a waterhammer of the containment =
coolers were not totally effective and were considered another example of poor
corrective action implementation.
The licensee stated they would perform
reviews to ensure the waterhammer would be mitigated or prevented in the
future,
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4 SURVEILLANCE OBSERVATIONS (61726, 92702)
The purpose of inspections in this area was to ascertain whether surveillance
of safety-significant systems and components was being conducted in accordance
with Technical Specifications and approved procedures.
4.1 Centrifugal Charging Pump Curve Verification
On April 10, 1993, the inspectors observed test engineers perform a pump curve
surveillance as required by Procedure STN BG-100B, " Centrifugal Charging
Pump B Reference Pump Curve Determination," Revision 1. ~The inspectors
observed erratic instrument indications when personnel opened the equalizing
valve.
Also, the inspectors noted from discussions among the test engineers-
that the test results could be invalid.
The test personnel informed the
inspectors that a PIR would be written if they repeated the test, since a
likely cause involved a failure to completely close the equalizing valve.
On April 12, 1993, the inspectors learned that personnel repeated the pump
test but failed to initiate a PIR. The inspectors expressed concerns that a
PIR was not initiated even though a human error caused a test deficiency.
Subsequently, the licensee initiated a PIR.
The licensee had repeated the
surveillance test to obtain a proper baseline flow,. since the pump exceeded
the runout flow.
The inspectors considered the failure of licensee personnel
to initiate a PIR to be a weakness and the fourth example of the licensee's
poor utilization of their corrective action program. .By failing to identify
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performance problems, adequate attention to common root causes could not be
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addressed. The Vice President, Plant Operations informed the inspectors that
he refocused the personnel in the affected group on the type of events for
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which PIRs should be initiated.
The responsible manager informed the
inspectors that several simila- test control events occurred during the outage
and that the group initiated a PIR to address generic test control concerns.
4.2 Response Time Testing
On April 17, 1993, the inspectors observed instrumentation and control
technicians perform response time testing of Protection Set 11 overtemperature
delta-T, increasing delta-flux penalty and power range flux for Channel- N-42
in accordance with Procedure STS IC-725B, "7300 Process and N.I. Response Time-
Test (2/4 Logic) Protection Set II," Revision 5. 'The technicians varied the
signal inputs at the nuclear instrument cabinet and measured the actuation
time between the 7300 process computer and the solid state protection system.
The inspectors verified that the technicians obtained approval 'from control:
room personnel prior to starting the surveillance. .All test instruments were
within calibration. The procedure provided excellent step-by-step guidance.
The inspectors found the technicians knowledgeable and familiar with the test
equipment.
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4.3 4.16 kV Degraded Voltage Calibration Check
On April 22, 1993, the inspectors observed instrumentation and control
technicians perform a calibration of the grid undervoltage sensing element for
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the Train A safety-related 4.16 kV bus in accordance with
Procedure STS IC-803A, "4 KV Undervoltage - Grid Degraded Voltage Channel
,
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Calibration NB01 Bus," Revision 0.
The technicians followed good practices while performing the surveillance,
such as repeat backs while communicating. Because the power leads were
energized, the technicians properly taped the bare wire as directed by the
procedure.
The as-found data met the acceptance criteria but was close to the
minimum acceptable value; consequently, the technicians made a slight
adjustment and reverified that the as-left values fell at the setpoint
midrange.
4.4 MOV Maintenance and Testing
The licensee scheduled 42 MOVs to be differential pressure flow tested during
Refuel VI. While conducting maintenance and testing on the MOVs, the licensee
identified cases where the measured maximum thrust, including inertia,
exceeded certain valve weak link and seismic limits.
Two valve component
failures also occurred related to a worm gear broken thread and damage to a
limit switch hypoid gear. Two valve overthrust occurrences were related to
these failures.
The inspectors reviewed engineering dispositions for overthrust of the
following MOVs:
EJ HV8701A, RCS Hot Leg 1 to Residual Heat Removal A suction;
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BB PV87028, RCS Hot leg 4 to Residual Heat Removal B suction; EM HV8803A and
-B, charging pump header to boron injection tank from the centrifugal charging
isolations; and EM HV8801A and -B,
boron injection tank outlet isolations.
The inspectors concluded that the licensee adequately evaluated and properly
dispositioned each of the valve overthrust conditions based on Limitorque
Corporation Maintenance Update 92-01 and KALSI testing results.
The inspectors reviewed the evaluations of component failures for
MOVs BB HV8037A and -B, pressurizer relief tank to containment normal sump
isolations.
After refurbishment and installation of the MOV BB HV80378 valve
actuator, the licensee discovered that the valve operator would not engage to
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the motor without using the declutch lever. The licensee determined that the
clutch return spring was weak and needed to be replaced. Upon disassembly,
the mechanics found other damaged or worn parts. The. mechanics replaced the
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worm shaft gear with a hammer blow type, replaced the worm, and replaced the
declutch shaft. The mechanics coordinated replacement of the shaft gear to a
hammer blow type with MOV system engineering personnel. The licensee replaced
the worm because a small end piece of gear thread was found broken off during
disassembly.
The broken thread on the worm consisted of about one centimeter
of thread as it runs out.
This portion of the thread is thinner than the
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engaged portion and more susceptible to' damage if not handled delicately
during maintenance activities. The licensee failed to. determine the cause of
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the broken worm thread but speculated that the worm was damaged during
assembly or disassembly.
During postmaintenance Valve Operation and Test Evaluation System testing of
MOV BB HV8037A, the geared limit switch assembly locked up. After replacement
of the limit switch assembly, the mechanics noticed that the geared limit
switches made metallic noises during motor operation.
During subsequent
disassembly, the licensee found a damaged limit switch hypoid gear.
The
licensee attributed the damaged hypoid gear teeth to the limit switch locking.
up.
During this repair activity, the licensee replaced the worm shaft gear
with a hammer blow type.
The inspectors concluded that the licensee had
adequately evaluated individual valve component failures.
The inspectors observed the licensee conduct differential pressure flow
testing of three valves simultaneously. The licensee recorded pressures,
flows, temperatures, and stroke times while opening and closing valves against
the pressure and flow provided by a centrifugal charging pump.
The licensee
performed the tests in accordance with Procedure TP TS-97, "EM HV8801A and -B
MOV DP Test," and Procedure TP TS-98, "EM HV8803A MOV DP Test." The licensee
performed diagnostic testing in parallel with these tests in accordance with
MGE E00P-13, "MOV Diagnostic Testing." The inspectors found the MOV testing
program to be well coordinated and administered by a qualified, well trained
staff. Management and quality control oversight of the program was observed
to be present and actively involved during MOV testing.
4.5 Conclusions
During performance of a pump curve test, the centrifugal charging pump
exceeded the runout flow because personnel failed to properly close a pressure
gage equalizing valve. The licensee did not issue a PIR until questioned by
the inspectors. This was another example of the inspectors PIR initiation
threshold concern (refer to Sections 2.6 and 2.7).
The inspectors determined
that qualified personnel used calibrated test equipment while implementing
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surveillance procedures.
The inspectors determined that the licensee properly
evaluated potential valve overthrust conditions.
Licensee personnel
appropriately performed valve actuator maintenance and evaluated valve
component failures. The inspectors found the MOV testing program to be well
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coordinated and administered by a qualified, well trained staff with
management and quality control oversight.
5 ENGINEERED SAFETY FEATURES SYSTEM WALKDOWN (71710)
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The inspectors conducted a detailed review of residual heat removal equipment
located both inside and outside the containment building. The inspectors
verified system components to be operable as required by Technical
Specifications.
The review included _ repetitive or outstanding work requests
from the previous 2 years that could affect system operability.
The system
engineer was cognizant of ongoing and outstanding maintenance items.
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The inspectors compared Piping and Instrumentation Drawing M-12EJ01 (Q),
,
" Residual Heat Removal System," Revision 3, to Procedure CKL EJ-120, "RHR
Normal System Lineup," Revision 14. Three valve positions on the system
drawing differed from the valve lineup sheet. Valve EJ V033, residual heat
removal Heat Exchanger A component cooling water outlet isolation,
Valve EJ V038, residual heat removal Heat Exchanger B component cooling water
outlet isolation, and Valve EJ V154, RCS Hot Leg 1 to Residual Heat Removal
Pump A suction vent, had locked positions indicated on the lineup sheets,
while the system drawings had no locking devices shown. The inspectors
discussed these discrepancies with operations personnel.
Procedure ADM 02-021, "Use of Procedures in Operations," Revision 14,
Step 3.1.3, describes the priority for determining the correct configuration
of locked components.
The priority for reference documents are in the
following order:
(1) Procedure ADM 02-102, " Control of Locked Components,"
(2) system lineup and operating procedures, and (3) system piping-and
instrumentation diagrams. The inspectors considered the. operation policy an
adequate resolution to the discrepancies.
The system walkdown consisted of equipment located within the auxiliary
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building, the control room, and the containment building. After the
inspectors identified that Valve EJ 8842, residual heat removal to safety
injection system relief valve, was incorrectly labeled as Valve 8856A,
residual heat removal to accumulator injection discharge Loops 1 and 2 relief-
valve, the licensee initiated a label request to correct the valve
identification label and initiated a PIR. The licensee initiated work
requests and label requests in response to identified system leakage and minor
labeling discrepancies. The inspectors found all valves, controls, and
breakers aligned in accordance with the system lineup and operating
procedures.
The inspectors reviewed the inservice testing of all required residual heat
removal system components fro" 1990 to present._ No short or long-term trends
were identified; however, p p vibration data for 1990 and 1991 was extremely
scattered. Discussions wita a results engineer indicated that different
technicians collecting the data contributed to the inconsistent data.
The
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licensee assigned a dedicated ind51 dual to collect ASME Section XI data.
While observing a technician collect vibration data, the inspectors noted that
the predictive maintenance vibration data monitoring points were not clearly
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marked.
Collection of vibration data at different locations can lead to
inconsistent predictive maintenance data collection.
The inspectors verified
that the ASME Section XI monitoring points were clearly labeled.
6 FOLLOWUP-(92701)
(Closed) Inspection Followup Item (482/9212-03):
Industr_y Experience Reviews
The inspectors initiated this followup item to ensure NRC review of the
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licensee resolutions to outstanding ITIPs.
PIR SE 92-0208 documented that
25 Westinghouse Technical Bulletins had not received initial evaluations in
accordance with the ITIP program. Also, the PIR-documented that 43 out of
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339 NRC Information Notices required additional reviews.
During a-later NRC
inspection (refer to NRC Inspection Report 50-482/92-24), the inspectors found
that 6 of the 43 Information Notices required further actions.
During review
of Information Notice 90-06, " Potential For Loss of Shutdown Cooling While at
Low Reactor Coolant Levels Due to Loss of Power to the RHR Control Valve," the
licensee determined that they improperly canceled a plant modification request
used for closecut of the information notice. The licensee included a review
of existing ITIPs to determine whether other ITIPs referenced canceled plant
modification requests.
The inspectors reviewed licensee activities for closing selected vendor
technical bulletins, for resolving the information notices reopened, and for
evaluating plant modification requests.
Additionally, the inspectors reviewed
other selected closed ITIPs listed in onsite safety review committee minutes.
The inspectors reviewed the ITIPs listed in Attachment 2.
The ITIPs described
below had detailed reviews performed by the inspectors.
ITIP 01850, " Westinghouse Technical Bulletin 75-01:
Pump Thermal Barrier," discussed problems associated with hydrostatic
testing of thermal barriers at pressures exceeding 225 psig.
The
licensee revised their procedures to ensure that hydrostatic testing of
the tube side does not exceed 225 psig.
Procedure STS PE-036,
" Component Cooling Water System Hydrostatic Test," Revision 1, did allow
testing to a minimum of 2875 psig; however, the test was never
performed.
ITIP 02129, "NRC Information Notice 88-73, Supplement 1:
Direction
Dependent Leak Characteristics of Containment-Purge Valves - Fisher
Anomaly Notice 88-2," provided information regarding the direction
dependent characteristic of certain types of butterfly valves. The
licensee's complete response was due July 1,1993.
The inspectors
reviewed results of three valves tested by the licensee during Re fuel.VI
to determine directional leak dependency. The results determinej the.
valves had no directional dependency and in one instance testing between
the valves was conservative.
ITIP 01630, "NRC Information Notice: Closecut of NRC Bulletin 79-33
' Cracking in Feedwater System Piping.'" The ITIP response referred to
,
the results of feedwater nozzle weld inspections from Refuel I and
'
specified that additional inspections of the same welds would be
implemented during Refuel VI. Additional reviews for ITIP 01672, " Steam
Generator Feedline/ Nozzle Thermal Stratification," resulted in the
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licensee delaying the Refuel VI inspections and initiating plans for
inspecting the welds during Refuels VII, VIII, and IX. The licensee
determined they had used one third of the nozzle design life.
ITIP 01247, "Information Notice 90-10:
Primary Water Stress Corrosion
Cracking (PWSCC) of Inconel 600." 'The industry information discusses
cracking of Inconel 600 welds in pressurizers of selected facilities.
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The licensee reopened ITIP 01247 after they determined the control rod
drive mechanisms have Inconel 600 welds subject to reactor coolant
system conditions.
The inspectors confirmed that the owners group was
addressing this issue. Three plants will complete penetration weld
inspections in 1994.
The NRC staff met with industry representatives on
this issue in March 1993. The licensee has Category 3 (lowest)
susceptibility to the weld cracking phenomenon.
The susceptibility was
based on factors such as the reactor vessel head temperatures, operating
history, number of loops, material composition, and primary chemistry.
The inspectors concluded that the licensee appropriately dispositioned the
ITIPs reviewed.
7 ONSITE REVIEW 0F LICENSEE EVENTS REPORTS (92700)
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7.1
(Closed) LER 482]91-020 and 91-020-01:
Containment Isolation Valves
Failed Local Leak Rate Test Causing Total Path Leakage to be Above 0.6 La
On October 22, 1991, the licensee determined that the total path leakage for
Type B and C local leak rate tests exceeded 0.6 La.
Erosion / corrosion of
fiOV EF HV032, ESW B to containment air coolers butterfly valve, and
MOV EF HV034, ESW 8 to containment air coolers butterfly valve, caused
excessive valve leakage.
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Although previous local leak rate tests of the valves indicated no valve
degradation, the licensee committed to evaluate erosion / corrosion of the
valves during Refuel VI.
The licensee inspected the valves and identified
some corrosion on the disc face but determined that the seating surfaces were
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not affected.
Corrosion product deposits were evident on the nonmachined
center of the discs and on the welded end plugs.
The licensee found general
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corrosion and pitting behind the ring and seat. The licensee identified an
as-found leakage of 8000 standard cubic centimeters per minute (sccm) and,
after inspection / reinstallation of the valves, the leakage was 180 sccm.
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7.2 1 Closed) LER 482/92-009:
Technical Specification Violation - Failure of
Humidity Sensors Results in Inoperability of Both Trains of the Control
Room Emergency Ventilation S_ystem
!
On April 17, 1992, the licensee determined that the relative humidity sensors
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for both control room pressurization filter absorber units would not
calibrate.
The humidity sensors control the electric duct heaters that heat
incoming air to reduce moisture in the filter and absorber units.
The
licensee declared both trains of the control room emergency ventilation system
The licensee immediately replaced the humidity sensors and attributed the root
cause of the humidity sensor failures to normal wear.
To preclude recurrence,
the licensee established a 36-month humidity sensor replacement requirement in
the preventive maintenance program. The inspectors verified that the
preventive maintenance program included the sensors.
In addition, the
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licensee initiated Engineering Evaluation Request 92-GK-02 to investigate the
feasibility of bypassing the humidity sensors and continuously energizing the
heaters during operation of the emergency ventilation system.
This evaluation-
was not completed at the end of the inspection period.
7.3
(Closed) LER 482/92-013:
Shunt Trip Contacts for Manual Reactor Trip
Breakers Not Tested in Accordance With Technical Specification
On August 14, 1992, the licensee determined that the existing surveillance
procedure did not provide for the proper testing of the manual reactor trip
function. The Technical Specification requires, once per 18 months, that the
licensee verify the operability of the undervoltage and shunt trip circuits
for both the manual reactor trip and the bypass breaker trip circuits. . The
licensee requested, and received, a Temporary Waiver of Compliance and an
emergency Technical Specification amendment.
The amendment required that
testing of the manual shunt trip circuitry be performed ~ prior to startup from
the next shutdown to Mode 3.
The licensee attributed the root cause of this
event to personnel error during the procedure development and review process.
The licensee reviewed other similar procedures'and found no additional
problems.
The inspectors reviewed Procedure STS10-215, " Trip Actuating Device
Operational Test of Manual Reactor Trip, Trip and Bypass Breaker. UV/ Shunt-
Trip, Turbine Trip on Reactor Trip and P4."
The procedure was revised to
incorporate the required manual trip testing. On November 10, 1992, the
surveillance of the manual shunt trip circuitry was performed prior to startup
from Mode 3, as committed. The inspectors reviewed the completed surveillance.
test and found that all acceptance criteria were met.
8 INOFFICE REVIEW 0F LER (90712)
,
The inspectors reviewed the following LERs, determining that-the corrective
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actions discussed in the report were appropriate and were completed.
8.1
(Closed) LER 91-016: Technical Specification Violation - Removal of
Ductwork Damper Inspection Covers Results in Inoperability of Ventilation
Systems
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8.2
(Closed) LER 92-014:
Failure to Verify Two Containment -Isolation Valves
Locked Closed Results in Violation of Technical Specification 4.6.1.1.a
8.3
(Closed) LER 92-015:
Late Completion of a Reauired Surveillance of
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Offsite AC Power Sources Caused By Personnel' Error Results In a Technical'
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Specification Violation
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ATTACHMENT 1
1
PERSONS CONTACTED
1.1
Licensee Personnel
P. D. Adams, Supervisor, Reactor Engineering
R. S. Benedict, Manager, Quality Control
M. K. Covey, Supervisor, Results Engineering
T. F. Deddens, Manager, Outage
M. E. Dingler, Manager, Nuclear Plant Engineering Systems, Support
C. W. Fowler, Manager, Maintenance and Modifications
D. E. Gerrelts, Manager, Instrumentation and Control .
D. Jacobs, Supervisor, Mechanical Maintenance
W. M. Lindsay, Manager, Quality Assurance
B. S. Loveless, Supervisor, Environmental Management
O. L. Maynard, Vice President, Plant Operations
R. A. Meister, Engineering Specialist, Regulatory Compliance
K. J. Moles, Manager, Regulatory Services
T. S. Morrill, Manager, Radiation and Protection
D. J. Neufeld, Supervisor, Outage
C. E. Parry, Director, Performance Enhancement
L. D. Ratzlaff, Supervisor, System Engineering
F. T. Rhodes, Vice President, Engineering
C. E. Rich, Jr., Supervisor, Electrical Maintenance
B. B. Smith, Manager, Modifications
C. M. Sprout, Manager, System Engineering
J. D. Weeks, Manager, Operations
S. G. Wideman, Supervisor, Licensing
B. D. Withers, President and CEO
1.2 NRC Personnel
A. T. Howell, Deputy Director, Division of Reactor Safety
T. O. McKernon, Reactor Inspector, Division of Reactor Safety
The above personnel attended the exit meeting.
In addition to these
personnel, the inspectors contacted other personnel during this inspection
period.
2 EXIT MEETING
An exit meeting was-conducted on May 14, 1993. During this meeting, the
inspectors summarized the scope and findings of the inspection. The
inspectors returned all proprietary information reviewed by them to the
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ATTACHMENT 2
Documents Reviewed
The following ITIPs were reviewed and found to be properly dispositioned by
the licensee:
ITIP 00177, "Significant Operating Experience Report 84-07:
Pressure
Locking And Thermal Binding of Gate Valves - Recommendation 2:
Ensure
Gate Valves Identified in Recommendation 1 Will Open When Required"
ITIP 00216, "Significant Operating Experience Report 83-03:
Inverter
Failures - Recommendation 5: Consider Adding Automatic Transfer Switch
to Improve Reliability"
ITIP 00830, "Limitorque Part 21 Notification, Dated 11/3/88 - Failures
of Melamine Torque Switches on SMB-000 And SMB-00 Actuators"
ITIP 00896, "NRC Information Notice:
Failure of Small Diameter Tubing
in Control Air, Fuel Oil, And Lube Oil Systems Which Render Emergency
Diesel Generators Inoperable"
ITIP 00902, "Limitorque Corporation Letter, Dated 8-17-88 (Maintenance
Update) Subjects:
Limit And Torque Switches, Torque Spring Assembly
Relaxation, Improper Use of Declutch Mechanism, DC Motors, Gasket
Materials"
ITIP 00919, "Information Notice 88-73, Supplement 1:
Direction
Dependent Characteristics of Containment Purge Valves"
ITIP 01247, "Information Notice 90-10:
Primary Water Stress Corrosion
Cracking (PWSCC) of Inconel 600"
ITIP 01485, " Environmental Qualification of Namco Limit Switches Used on
ITIP 01630, "Information Notice 91-28:
Cracking in Feedwater System
Piping"
ITIP 01687, " Westinghouse Infogram 91-2.2:
Bottom-Mounted
Instrumentation Flux Thimble Tube Leakage Due to Wear"
ITIP 01848, " Recurring Significant Event Notification 92-04"
ITIP 01850, " Westinghouse Technical Bulletin 75-01:
Pump Thermal Barrier"
ITIP 01856, " Westinghouse Technical Bulletin NSD-TB-77-14:
Misstepping"
ITIP 01858, " Westinghouse Technical Bulletin NSD-TB-78-05: Type SDF-1
Underfrequency Relays, Reactor Coolant Pump Underfrequency Protection"
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ITIP 01859, "Masoneilan Air Operated Valves"
ITIP 01863, " Westinghouse Technical Bulletin W-TB-80-03:
Oxygen in
Waste Gas Systems"
ITIP 01867, " Westinghouse Technical Bulletin W-TB-81-02: Maintenance of
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RCP Motor Oil Coolers"
ITIP 01926, "NRC Information Notice 92-26:
Pressure Locking of Motor
Operated Flexible Wedge Gate Valves"
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ITIP 01953, " Recurring Significant Event Notification 92-01, January -
March"
ITIP 02043, "Significant Event Report 14-92:
Loss of Primary
Containment Integrity During Refueling Outages"
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ITIP 02164, "Significant Operating Experience Report 82-04:
Improper
Alignment of Spray System to RHR System - Recommendation 1:
Have
Supervisors And Operators Write Down Complicated Instructions For
Aligning More Than One or Two Valves"
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ITIP 02166, "Significant Operating Experience Report 82-04:
Improper
Alignment of Spray System to RHR System - Recommendation 3:
Require
Formal Independent Verification When Safety-Related and Other Important
Plant Components are Repositioned"
ITIP 02182, " Recurring Significant Event Notification 92-05:
Loss of
Offsite Power While Performing Maintenance in Switchyard"
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