IR 05000298/2006005: Difference between revisions

CNS-2006-08999. The finding is more than minor because it is associated with the human performanceattribute of the Mitigating Systems cornerstone and affects the cornerstone objective to

ensure the availability, reliability, and capability of systems that respond to initiating

events to prevent undesirable consequences. Using the NRC Manual Chapter 0609,

Appendix GProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,Appendix G" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., "Shutdown Operations Significance Determination Process," Phase 1

Checklist, the finding is determined to have very low safety significance because one

operable diesel generator was still capable of supplying power to the Class 1E electrical

power distribution subsystems. This finding has a crosscutting aspect in the area ofhuman performance given that the licensee's work practices did not ensure that

personnel do not proceed in the face of uncertainty or unexpected circumstances.

(Section 1R19)*Green. A self-revealing, noncited violation of Technical Specification 5.4.1.a wasidentified for the licensee's failure to establish adequate maintenance procedures for

safety-related, motor-operated valves. Between 1993 and 2006, maintenance

procedures for Limitorque motor actuators did not contain sufficient detail to ensure that

actuator motor pinion gears were installed correctly. This deficiency resulted in the

failure of a low pressure safety injection valve on October 17, 2006, due to its pinion

gear migrating off the motor shaft. This issue was entered into the licensee's corrective

action program as Condition Report

10 CFR Part 50, Appendix B,Criterion

CNS-2006-07490. The finding is more than minor because it is associated with the Mitigating Systemscornerstone attribute of equipment performance and affects the associated cornerstone

objective to ensure the availability, reliability, and capability of systems that respond to

initiating events. The Phase 1 worksheets in NRC Manual Chapter 0609, "Significance

Determination Process," were used to conclude that a Phase 2 analysis was required

because it resulted in the loss of a train of low pressure coolant injection for greater than

the Technical Specification allowed outage time. The inspectors performed a Phase 2

analysis using Appendix A, "Technical Basis For At Power Significance Determination

Process," of Manual Chapter 0609, "Significance Determination Process," and the

Phase 2 worksheet for Cooper Nuclear Station. Based on the results of the Phase 2

analysis, the finding is determined to have very low safety significance. (Section 1R22)*Green. A self-revealing, noncited violation of

XVI, was identified regarding the licensee's failure to correct a nonconforming

condition in safety-related, motor-operated valves. In 1994, Limitorque and the NRC

notified the industry that the torque switch roll pin in certain Limitorque valve actuators

was susceptible to failure. The licensee took no corrective actions based on this

notification. On November 8, 2006, the acceptable torque range was exceeded during

stroking of the high pressure coolant injection inboard steam isolation valve due to the

failure of the torque switch roll pin. This issue was entered into the licensee's corrective

action program as Condition Report

4OA 2.1)*Green. A self-revealing, noncited violation of 10

CNS-2006-08821.

Enclosure-5-The finding affected the Mitigating Systems cornerstone and is more than minorbecause, if left uncorrected, it would become a more safety significant concern. Using

the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet,

the finding is determined to have very low safety significance because there was no loss

of safety function for the high pressure coolant injection system. (Section

CFR Part 50, Appendix B,Criterion XVI, was identified regarding the licensee's failure to identify and correct age-

related degradation in the motor coupling for Service Water Discharge Strainer A.

Corrective maintenance designed to identify and replace degraded components was

performed in February 2006; however, the licensee failed to identify and replace a

degraded rubber sleeve in the coupling which subsequently failed on October 29, 2006.

This issue was entered into the licensee's corrective action program as Condition Report

CNS-2006-08226. The finding is more than minor because it is associated with the Mitigating Systemscornerstone attribute of equipment performance and affects the associated cornerstone

objective to ensure the availability and reliability of systems that respond to initiating

events. The Phase 1 worksheet in Manual Chapter 0609, "Significance Determination

Process," were used to conclude that a Phase 2 analysis was required because the

finding also increased the likelihood of a loss of service water initiating event. Based on

the results of a Phase 3 analysis, the finding is determined to have very low safety

significance. The cause of the finding is related to the corrective action component of

the crosscutting area of problem identification and resolution in that the licensee failed toidentify this issue in a timely manner. (Section 4OA2.1)*Green. A self-revealing finding was identified regarding the failure to install heat traceon the standby liquid control system in accordance with the vendor manual. The heat

trace was installed in 1994 without the required ground-fault circuit protection. This

resulted in a small fire in the heat trace on November 11, 2006. This issue was entered

into the licensee's corrective action program as Condition Report

NRC identified a noncited violation of 10

CNS-2006-09006.The finding is more than minor because it is associated with the Mitigating SystemsCornerstone attribute of design control and affects the associated cornerstone objective

to ensure the availability, reliability, and capability of the standby liquid control system

that is required to respond to initiating events, such as anticipated transients without

scrams. Using the Manual Chapter 0609, "Significance Determination Process,"

Phase 1 Worksheet, the finding is determined to have very low safety significance

because it did not result in a loss of safety function. (Section 4OA3.1)Cornerstone: Barrier Integrity

Green. The

CFR Part 50, Appendix B,Criterion XVI, involving the licensee's failure to promptly identify and correct a condition

adverse to quality regarding an unanalyzed condition in the torus. Specifically, the

inspectors identified a trolley/hoist and chain in the torus that had been in the torus for

Enclosure-6-the past five operating cycles without being evaluated for its potential impact on safety-related equipment. The licensee documented the condition in Condition Report

CNS-2006-09338.The finding is more than minor because it is associated with the Barrier Integritycornerstone attribute of design control and it affects the associated cornerstone

objective to provide reasonable assurance that physical design barriers protect the

public from radionuclide releases caused by accidents or events. Using the NRC

Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, the

finding is determined to have very low safety significance because it did not represent

an actual breach of containment. This finding has a crosscutting aspect in the area ofproblem identification and resolution in that the licensee did not implement a corrective

action program with a low threshold for identifying issues. Specifically, the unanalyzed

condition existed in a location frequently accessed during refueling outages but never

questioned by the licensee. (Section 1R20)*Green. The NRC identified a noncited violation of Technical Specification 5.4.1.aregarding the licensee's failure to follow procedures for power operation and process

monitoring. Specifically, the licensee operated the reactor above the total core flow

limit, contrary to requirements of General Operating Procedure 2.1.10, "Station Power

Changes." The licensee documented this violation in Condition Report

EDG 1 RoomDecember 8, 2006: Fire Zone 14B,

CNS-2006-

255.The finding is more than minor because it is associated with the Barrier Integritycornerstone attribute of human performance (procedural adherence) and it affects the

associated cornerstone objective to provide reasonable assurance that physical design

barriers, such as fuel cladding, protect the public from radionuclide releases caused by

accidents or events. Using the NRC Manual Chapter 0609, "Significance Determination

Process," Phase 1 worksheet, the finding is determined to have very low safety

significance because it only had the potential to affect the fuel cladding barrier. This

finding has a crosscutting aspect in the area of human performance in that the licenseedid not effectively communicate expectations regarding work practices to operators for

the control of key parameters such as total core flow. (Section 4OA2.1)Cornerstone: Occupational Radiation Safety

Green. The inspectors reviewed a self-revealing, noncited violation of TechnicalSpecification 5.4.1.a involving the licensee's procedure for reactor pressure vessel

refueling preparation was not adequate. The licensee's refueling procedure allowed the

control room supervisor or shift manager to alter the sequence to suit existing plant

conditions and time requirements. However, the procedure did not contain any

precautions or limitations to consider the impact that altering the sequence would have

on ancillary systems, such as the high efficiency particulate air filter hose connection to

the reactor pressure vessel vent. In addition, the change in sequence was not

communicated or coordinated with radiation protection to evaluate potential radiological

impacts. Consequently, when the licensee raised the reactor pressure vessel water

level at an earlier stage in the reactor head disassembly process, the increased

temperature and pressure applied to the high efficiency particulate air hose caused it to

Enclosure-7-disconnect from the reactor pressure vessel vent. The loss of this connection releasedactivation products onto the refuel floor and created an airborne radioactivity area, which

alarmed the continuous air monitor and contaminated five workers. The licensee's

immediate corrective actions were to evacuate personnel from the refuel floor and begin

decontamination of the workers and the areas involved.The finding is more than minor because it is associated with the occupational RadiationSafety cornerstone attribute of Program and Process, and it affects the cornerstone

objective to ensure the adequate protection of a worker's health and safety from

exposure to radiation from radioactive materials because it resulted in unintended

internal doses. Using the Occupational Radiation Safety Significance Determination

Process, the finding is determined to have very low safety significance (Green) because

it was not an as low as is reasonably achievable finding, there was no overexposure or

substantial potential for an overexposure, and the ability to assess the dose was not

compromised. Additionally, this finding had a crosscutting aspect in the area of humanperformance associated with the component of work control because the licensee failed

to coordinate work activities by incorporating actions to address the impact of the work

on different job activities and communicate, coordinate, and cooperate with each other

during activities in which interdepartmental coordination is necessary to assure

appropriate plant and human performance. (Section 2OS1)B.Licensee Identified ViolationsViolations of very low safety significance that were identified by the licensee have beenreviewed by the inspectors. Corrective actions taken or planned by the licensee have

been entered into the licensee's corrective action program. These violations and

correction action tracking numbers are listed in Section 4OA7 of this report.

Enclosure-8-REPORT

DETAIL [[]]

SSummary of Plant StatusThe plant began the inspection period at essentially full reactor power in coastdown toRefueling Outage 23. The reactor was manually scrammed on October 21, 2006, for the

refueling outage. A plant startup was conducted on November 21, 2006, and the and the main

generator was synchronized to the grid on November 22, 2006. Reactor power was reduced to

percent on November 24, 2006, and the main turbine was removed from service to repair a

steam leak on Moisture Separator C. Full power operation was achieved on November 27,

2006. The plant remained at full power for the remainder of the period.1.REACTOR

SAFET [[]]

YCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather (71111.01A) a.Inspection ScopeThe inspectors completed a review of the licensee's readiness for seasonalsusceptibilities involving extreme low temperatures. The inspectors: (1) reviewed plant

procedures, the Updated Final Safety Analysis Report (UFSAR), and Technical

Specifications (TS) to ensure that operator actions defined in adverse weather

procedures maintained the readiness of essential systems; (2) walked down portions of

the three systems listed below to ensure that adverse weather protection features (heat

tracing, space heaters, weatherized enclosures, etc.) were sufficient to support

operability, including the ability to perform safe shutdown functions; (3) evaluated

operator staffing levels to ensure the licensee could maintain the readiness of essential

systems required by plant procedures; and (4) reviewed the corrective action

program (CAP) to determine if the licensee identified and corrected problems related to

adverse weather conditions. *Fire protection*Condensate storage

Emergency diesel generators (EDGs)Documents reviewed by the inspectors included:

Maintenance Procedure 7.2.80, "Intake Structure Guide Wall Winterization andRestoration," Revision 5*General Operating Procedure 2.1.14, "Seasonal Weather Preparations,"Revision 8The inspectors completed one sample.

Enclosure-9- b. FindingsNo findings of significance were identified.1R04 Equipment Alignment (71111.04)Partial System Walkdowns a.Inspection ScopeThe inspectors: (1) walked down portions of the two risk important systems listed belowand reviewed plant procedures and documents to verify that critical portions of the

selected systems were correctly aligned; and (2) compared deficiencies identified during

the walkdown to the licensee's

UFSAR and

CAP to ensure problems were being

identified and corrected. *September 29, 2006: Offsite power sources during planned maintenance on thestation startup service transformer*December 11, 2006: Service Water (SW) Loop A while Loop B was inoperablefor planned maintenanceDocuments reviewed by the inspectors included:

Surveillance Procedure 6.EE.610, "Offsite Power Alignment," Revision 16*System Operating Procedure 2.2.71, "Service Water System," Revision 90The inspectors completed two samples. b.FindingsNo findings of significance were identified.1R05 Fire Protection (71111.05Q) a.Inspection ScopeThe inspectors walked down the six plant areas listed below to assess the materialcondition of active and passive fire protection features and their operational alignment.

The inspectors: (1) verified that transient combustibles and hot work activities were

controlled in accordance with plant procedures; (2) observed the condition of fire

detection devices to verify they remained functional; (3) observed fire suppression

systems to verify they remained functional and that access to manual actuators was

unobstructed; (4) verified that fire extinguishers and hose stations were provided at their

designated locations and that they were in a satisfactory condition; (5) verified that

passive fire protection features (electrical raceway barriers, fire doors, fire dampers,

steel fire proofing, penetration seals, and oil collection systems) were in a satisfactory

material condition; (6) verified that adequate compensatory measures were established

Enclosure-10-for degraded or inoperable fire protection features and that the compensatory measureswere commensurate with the significance of the deficiency; and (7) reviewed the CAP to

determine if the licensee identified and corrected fire protection problems. September 29, 2006: Fire Zone 3A, 4160V Bus 1F RoomSeptember 29, 2006: Fire Zone 3b, 4160V Bus 1G RoomNovember 1, 2006: Fire Zone 20A, Service Water Pump RoomNovember 11, 2006: Fire Zone 5A, Reactor Building 976 EastDecember 8, 2006: Fire Zone 14A,

EDG 2 RoomDocuments reviewed by the inspectors included:

CNS Fire Hazards Analysis Report, June 20, 2002The inspectors completed six samples. b. FindingsNo findings of significance were identified.1R07Biennial Heat Sink Performance (71111.07B) a.Inspection ScopeThe inspectors reviewed design documents (e.g., calculations and performancespecifications), program documents, implementing documents (e.g., test and

maintenance procedures), and corrective action documents. The inspectors interviewed

chemistry personnel, maintenance personnel, engineers, and program managers. For heat exchangers directly connected to the safety-related service water system, theinspectors verified whether testing, inspection, maintenance, and the biotic fouling

monitoring program provided sufficient controls to ensure proper heat transfer.

Specifically, the inspectors reviewed: (1) heat exchanger test methods and test results

from performance testing, and (2) if necessary, heat exchanger inspection and cleaning

methods and results. For heat exchangers directly or indirectly connected to the safety-related service watersystem, the inspectors verified that: (1) the condition and operation was consistent with

design assumptions in the heat transfer calculations, (2) the potential for water hammer

was assessed, as applicable, and (3) chemistry controls for heat exchangers indirectly

connected to the safety-related service water system were appropriate. For the ultimate heat sink and its subcomponents, the inspectors reviewed the followingrequirements: (1) macrofouling controls, (2) biotic fouling controls, and (3) performance

tests for pumps and valves.

Enclosure-11-If available, the inspectors reviewed additional nondestructive examination (NDE) resultsfor the selected heat exchangers that demonstrated structural integrity. The inspectors selected heat exchangers that ranked high in the plant-specific riskassessment and were directly or indirectly connected to the safety-related service water

system. The inspectors selected the following specific heat exchangers: Division

II residual heat removal (

RHR ) heat exchangerDivision

II reactor equipment cooling (

REC) heat exchanger

Turbine equipment cooling heat exchangersThe inspector completed three of the required two to three samples. b.FindingsNo findings of significance were identified.1R08Inservice Inspection Activities.1Performance of

NDE Activities a.Inspection ScopeProcedure 71111.08 requires the review of five

NDE activities of at least two or threedifferent types. The inspector witnessed the performance of two unltrasonic, two

penetrant, and two visual examinations. In addition, the inspector reviewed other visual,

penetrant, magnetic particle, and ultrasonic inspections. The complete list of NDE

activities reviewed is listed in the "List of Documents Reviewed" attachment to this

report. For each of the selected

NDE activities, the inspector verified that the examinationswere performed in accordance with American Society of Mechanical Engineers (

ASME)

Code requirements.During the review of each examination, the inspector verified that appropriate NDEprocedures were used, that examinations and conditions were as specified in the

procedure, and that test instrumentation or equipment was properly calibrated and within

the allowable calibration period. During the underwater visual inspections of the steam

dryer, two cracked tack welds were identified. The tack welds are located on one of the

four steam dryer lifting lugs. An evaluation of the cracked tack welds was performed

and were found to be acceptable as is. The inspector also reviewed the evaluation

documentation to verify that these indications revealed by the examinations were

dispositioned in accordance with the

ASME Code specified acceptance standards. The inspector verified the certifications of ten Level

II and three Level

III [[]]

NDE personnelobserved performing examinations or identified during review of completed examination

packages.

Enclosure-12-The inspection procedure requires review of one or two examinations from the previousoutage with recordable indications that were accepted for continued service to ensure

that the disposition was done in accordance with the

AS [[]]

ME Code. There were no

recordable indications that required evaluation during the last outage. The licensee completed welding on one pressure boundary Class 2 structure at the endof Refueling Outage RF23. The licensee modified the support for the vent/purge line in

containment for Valve AOV-237. The inspector verified that acceptance and preservice

examinations were completed in accordance with the

ASME Code.The procedure also requires verification that one or two

ASME Code Section XI repairsor replacements meet Code requirements. There were no Code repairs or

replacements available at the time of this inspection. The inspector reviewed three licensee Request for Relief submittals for the fourth10-year interval inservice inspection. These relief requests pertained to peripheral

control rod drives, buried service water piping, and reactor vessel head flange leak

detection lines. The inspector reviewed the licensee's compliance to the relief request

response.The inspector completed the minimum one sample for this inspection. b.FindingsNo findings of significance were identified..2Identification and Resolution of Problems a. Inspection ScopeThe inspector reviewed selected inservice inspection related condition reports issuedduring the current and past refueling outages. The review served to verify that the

licensee's corrective action process was being correctly utilized to identify conditions

adverse to quality and that those conditions were being adequately evaluated,

corrected, and trended. b.FindingsNo findings of significance were identified.1R11Licensed Operator Requalification (71111.11Q).1Quarterly Requalification Activities a.Inspection ScopeThe inspectors observed testing and training of senior reactor operators and reactoroperators in the simulator on October 2, 2006, to verify adequacy of the training, to

Enclosure-13-assess operator performance, and to assess the evaluator's critique. The inspectorsobserved a simulator scenario involving a failure of the main turbine hydraulic control

system. Documents reviewed by the inspectors included:Lesson Plan

SKL [[051-51-49, Loss of Main Generator Cooling and Failure of theDigital-Electrohydraulic Control SystemThe inspectors completed one sample. b.FindingsNo findings of significance were identified..2Licensed Operator Requalification (71111.11B)Biennial Inspection a.Inspection ScopeThe inspectors: (1) evaluated examination security measures and procedures forcompliance with 10]]

CFR 55.49; (2) evaluated the licensee's sample plan for the written

examinations for compliance with

10 CFR 55.59 and

NUREG-1021, as referenced in the

facility requalification program procedures; and (3) evaluated maintenance of license

conditions for compliance with 10 CFR 55.53 by review of facility records (medical and

administrative), procedures, and tracking systems for licensed operator training,

qualification, and watchstanding. In addition, the inspectors reviewed remedial training

and examinations for examination failures for compliance with facility procedures and

responsiveness to address areas failed.Furthermore, the inspectors: (1) interviewed six personnel (three operators, twoinstructors/evaluators, and one training supervisor) regarding the policies and practices

for administering examinations; (2) observed the administration of two dynamic

simulator scenarios to a requalification crew by facility evaluators, including an

operations department manager, who participated in the crew and individual

evaluations; and (3) observed two facility evaluators administer five job performance

measures, including two in the control room simulator in a dynamic mode and three in

the plant under simulated conditions. Each job performance measure was observed

being performed by an average of four requalification candidates. The inspectors also reviewed the remediation process for three individuals, one of whichinvolved a written examination failure, one a simulator examination failure, and one

periodic weekly quiz failure. The inspectors also reviewed the results of the annual

licensed operator requalification operating examinations for 2004 and 2006. The results

of the examinations were also reviewed to assess the licensee's appraisal of operator

performance and the feedback of that performance analysis to the requalification

training program. Inspectors also observed the exam security maintenance during the

exam week. Examination results were also assessed to determine if they were

consistent with the guidance contained in

NUR [[]]

EG 1021, "Operator Licensing

Enclosure-14-Examination Standards for Power Reactors," Revision 9, and NRC ManualChapter 0609, Appendix I, "Operator Requalification Human Performance Significance

Determination Process [SDP]." Additionally, the inspector reviewed 12 licensed

operators' medical records maintained by the facility licensee and assessed compliance

with the medical standards delineated in

10 CFR 55.21, "Medical Examination," and 10

ANS 3.4-1983, "American National

Standard Medical Certification and Monitoring of Personnel Requiring Operator Licenses

for Nuclear Power Plants," and with

10 CFR 55.21 and 10

CFR 55.25. During the in-office review, the inspectors evaluated the written examination results,whether the written examination was developed and administered in accordance with

the standards described in

NUR [[]]

EG 1021, and any issues identified in accordance with

NRC Manual Chapter 0609, Appendix I. The written examination review was focused on

quality aspects of the examination, such as discrimination validity, examination question

psychometric quality, and examination integrity. b.FindingsIntroduction: The inspector identified a Green, noncited violation (NCV) of

CFR 55.23, "Certification," involving the failure to

conduct all the medical testing required by

10 CFR 55.21 and 55.23 with respect to

ANS 3.4-1983, "Medical Certification

and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants." Description: The inspector determined that an apparent long-standing programmaticdeficiency had existed at the Cooper Nuclear Station, whereby the licensee's medical

physician was not adequately testing all licensed operators (both initial and renewal

licensees) in accordance with

ANSI/ANS 3.4-

1983Property "ANSI code" (as page type) with input value "ANSI/ANS 3.4-1983" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.. Specifically, certain medical conditions identified by the inspector in the licensedoperators' medical records led to the identification that a medical test required to be

conducted in accordance with

ANS 3.4 (nose sensitivity, Section 5.4.2) was not

tested on any of the 57 licensed operators. At a minimum, this issue involved the last

two biennial medical examinations conducted in years 2004 and 2006. The lack of

testing also included the most recently licensed operators following the June 2005 initial

license examination. The failure to conduct all the required medical examination tests

was a potential violation of 10 CFR 55.21 and 55.23. The inspector verified the adequacy of immediate corrective actions implemented by thelicensee. The licensee took the following corrective actions, which were considered to

be prompt, from the time the licensee was informed by the NRC that a problem existed,

involving complete and accurate performance and reporting requirements of medical

examinations. The medical physicians who performed these medical evaluations were givenadditional training on the requirements of

ANS 3.4-1983.The contracts between the medical facility and the utility were altered tospecifically require a review against the

AN [[]]

SI standard.

Enclosure-15-The administrative procedure governing the medical reporting process wasrevised, including the development of a comprehensive medical checklist.The Cooper Nuclear Station medical records were audited to identify anyadditional problems with medical conditions that were not reported to the NRC.The licensee implemented immediate corrective action to conduct the missedtest on all operators before they were allowed back on-shift. The missed medical test was conducted using a scratch and sniff card to verify thatlicensed personnel could detect odors. The licensee had this test conducted and

reviewed and certified by a medical physician. Analysis: The inspector reviewed the missed medical examination issue against theguidance contained in Appendix B, "Issue Dispositioning Screening," of Inspection

Manual Chapter 0612, "Power Reactor Inspection Reports." This finding affected the

mitigating system cornerstone objective because inadequate medical examinations

on operator license applicants and licensed operators could result in potential

consequences of licensed operators who may not be medically qualified to perform

licensed duties and could cause operational errors, therefore, potentially endangering

the health and safety of the public. Consequently, the safety significance of this issue

was determined to be more than minor. Additionally, this finding has a crosscutting

aspect in the area of human performance associated with work practices because the

licensee did not effectively supervise the work performed by the doctor, a contract

worker, to ensure the requirements in the applicable procedures,

AN [[]]

SI 3.4-1983, were

met. The inspector reviewed this issue in accordance with Manual Chapter 0609,"Significance Determination Process," Appendix I, "Operator Requalification Human

Performance Significance Determination Process." The SDP concerning medical issues

focused on general record deficiencies exceeding a specified threshold of 20 percent of

the records reviewed. Based on this SDP, the inspector determined that this finding

was of very low safety significance (Green) because the failure to conduct the required

medical examination tests for all licensed operators and initial license applicants

exceeded the 20 percent threshold for record deficiencies. Enforcement: Part 55.21 of

10 CFR required, in part, that an applicant for a 10

CFRPart 55 license and current 10 CFR Part 55 licensee have a medical examination by a

physician every 2 years. The physician shall determine that the applicant or licensee

meets the requirements of

10 CFR 55.33(a)(1). In addition, 10

CFR 55.23 required that

to certify the medical fitness of the applicant, an authorized representative of the facility

licensee complete and sign Form NRC-396, "Certification of Medical Examination by

Facility Licensee." The licensee committed to follow

ANS 3.4-1983 as the way

they would meet Part 55.46 (d)(1).

ANS 3.4-1983 required, in part, that the

primary responsibility for assuring that qualified personnel are on duty rests with the

facility licensee. In addition, the health requirements set forth within the standard

provide the minimum necessary to determine that the physical condition and general

health of the operators were not such as might cause operational errors endangering

Enclosure-16-the public health and safety. The specific health requirements and disqualifyingconditions are described in Section 5.3, "Disqualifying Conditions," and Section 5.4,

"Specific Minimum Capacities Required for Medical Qualifications," of the

AN [[]]

SI

standard. However, on August 9, 2006, prompted by the inspector's assessment

regarding the inadequacy of the facility licensee's medical examinations, the licensee

conducted reviews of all medical examinations and records and found that certain

tests in accordance with

ANS 3.4-1983 had not been performed. In fact, all initial

license applicants and previously licensed operators (32 operators) were not adequately

examined for all medical tests as required to meet the minimum standards of

NCV (05000298/2006005-01) consistent with Section

ANS 3.4-1983. Specifically, the facility licensee was not testing its operators for

nose sensitivity (Section 5.4.2).This Green finding concerning the missed medical test is considered a violation of10 CFR 55.21 and 55.23. Because of the very low safety significance, this violation

is being treated as an

VI.A.1 of

the NRC Enforcement Policy. This issue was in the licensee's corrective action program

as

10 CFR Part 50, Appendix B, and the Technical Specifications.Condition Report

CNS-2006-05775. The licensee adequately implemented immediate corrective

action and satisfactorily performed the missed medical test. In addition, the licensee

implemented additional corrective actions as indicated in this report. 1R12Maintenance Rule (711111.12Q) a.Inspection ScopeThe inspectors reviewed the maintenance effectiveness performance issues listed belowto: (1) verify the appropriate handling of structure, system, and component (SSC)

performance or condition problems; (2) verify the appropriate handling of degraded SSC

functional performance; (3) evaluate the role of work practices and common cause

problems; and (4) evaluate the handling of SSC issues reviewed under the requirements

of the maintenance rule,

CR -CNS-2006-07365, Reactor Recirculation Motor GeneratorUndemanded Speed ChangeCondition Report

CNS -2006-05981, Torus Drain Valve to Sump B(RW-AOV-768AV) Stuck ShutCondition Report

RHR Loop B Injection Valve (

CNS -2006-08190,

RHR-MOV-MO25B) Failed to OpenThe inspectors completed three samples. b.FindingsNo findings of significance were identified.

Enclosure-17-1R13Maintenance Risk Assessments and Emergent Work Evaluation (71111.13) a.Inspection Scope The inspectors reviewed the two maintenance activities listed below to verify: (1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and

licensee procedures prior to changes in plant configuration for maintenance activities

and plant operations; (2) the accuracy, adequacy, and completeness of the information

considered in the risk assessment; (3) that the licensee recognized, and/or entered as

applicable, the appropriate licensee-established risk category according to the risk

assessment results and licensee procedures; and (4) the licensee identified and

corrected problems related to maintenance risk assessments.September 29, 2006: Work Order (WO) 4451770 for planned maintenance onthe station startup service transformerOctober 23, 2006:

WO 4511138 for replacement of Switchyard Breaker 3306(Booneville 345

KV Breaker)The inspectors completed two samples. b.FindingsNo findings of significance were identified.1R15 Operability Evaluations (71111.15) a.Inspection Scope For the following equipment performance issue, the inspectors: (1) reviewed plantstatus documents such as operator shift logs, emergent work documentation, deferred

modifications, and standing orders to determine if an operability evaluation was

warranted for degraded components; (2) referred to the

UFS [[]]

AR and design basis

documents to review the technical adequacy of licensee operability evaluations;

(3) evaluated compensatory measures associated with operability evaluations;

(4) determined degraded component impact on any

TS s; (5) used the

SDP to evaluate

the risk significance of degraded or inoperable equipment; and (6) verified that the

licensee has identified and implemented appropriate corrective actions associated with

degraded components.Condition Report

WO 4296299 for replacement of the Division 1 250 voltbattery*November 1, 2006:

CNS-2006-07083, EDG Tachometers ImproperlyGroundedThe inspectors completed one sample. b.FindingsNo findings of significance were identified.

Enclosure-18-1R19 Postmaintenance Testing (71111.19) a.Inspection ScopeThe inspectors selected four postmaintenance tests associated with the maintenanceactivities listed below for risk significant systems or components. For each item, the

inspectors: (1) reviewed the applicable licensing basis and/or design basis documentsto determine the safety functions; (2) evaluated the safety functions that may have been

affected by the maintenance activity; and (3) reviewed the test procedure to ensure it

adequately tested the safety function that may have been affected. The inspectors

either witnessed or reviewed test data to verify that acceptance criteria were met, plant

impacts were evaluated, test equipment was calibrated, procedures were followed,

jumpers were properly controlled, the test data results were complete and accurate, the

test equipment was removed, the system was properly re-aligned, and deficiencies

during testing were documented. The inspectors also reviewed the

UFS [[]]

AR to

determine if the licensee identified and corrected problems related to postmaintenance

testing. *October 25, 2006:

WO 4528348 for a modification to allow the reactor watercleanup system to be cross-connected to the fuel pool cooling system*November 5, 2006:

WO 4514076 for replacement of the voltage regulator on

EDG 2*November 10, 2006:

WO 4457184 to install a new high point vent on the highpressure coolant injection (

HPCI ) systemThe inspectors completed four samples. b.FindingsIntroduction: A self-revealing, Green

NCV of

TS 5.4.1.a was identified regarding thelicensee's failure to follow procedures for maintenance affecting the performance of

safety-related equipment.Description: On November 11, 2006, EDG 2 was started to support postwork testingfollowing the replacement of its voltage regulator during the refueling outage.

WO 4514076 included instructions for the instrumentation & control (I&C) technicians to

connect an oscillograph recorder to the EDG output to record the voltage seen at the

voltage regulator.The EDG was secured shortly after being started due to an unrelated condition. Thetechnicians noted that the data taken by the recorder was not as expected. In an

attempt to validate the performance of the recorder, a technician connected a variac to

the recorder, without disconnecting it from the system, and applied a 60 volt test signal

Enclosure-19-to the recorder. The technician immediately realized that he had energized the voltageregulator through the recorder, secured power to the variac, and disconnected the

recorder from the system. The technician then tested the recorder with the variac off-

line and subsequently reinstalled the recorder in the system. The technician did not

notify other personnel of this error or initiate a condition report at the time.During the subsequent start of the

EDG , the output voltage of the machine exceeded5000 volts and

EDG 2 tripped and locked out on overvoltage. During the posttrip

troubleshooting, it was determined that the cause of the overvoltage condition was a

blown fuse that deenergized one of three phases of electrical power from the voltage

regulator's potential transformer. The licensee determined that the cause of the blown

fuse was the introduction of the variac into the circuit, feeding 60-volt electrical power to

the secondary windings of the potential transformer. This introduced a stepped-up

voltage on the primary windings and resulted in a blown fuse on one of the three phases

of the potential transformer. As a result, the EDG voltage regulator saw the sum of only

two phases of output voltage (versus the three normally seen) and continued to raise

voltage until an overvoltage trip was received.The inspectors reviewed the work instructions provided in WO 4514076. The scope ofthese instructions did not include any contingencies for troubleshooting unanticipated

problems with the recorder. The inspector determined that the procedural steps in the

WO were adequate for the anticipated activities, but that the I&C technicians had

deviated from the WO instructions and introduced an unanticipated piece of test

equipment to the voltage regulator circuit.Analysis: The performance deficiency associated with this finding involved thelicensee's failure to follow work instructions for maintenance affecting the performance

of safety-related equipment. The finding is more than minor because it is associated

with the human performance attribute of the mitigating systems cornerstone and affects

the cornerstone objective to ensure the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences (i.e., core

damage). Using the Manual Chapter 0609, Appendix G, "Shutdown Operations

Significance Determination Process," Phase 1 checklist, the finding is determined to

have very low safety significance because one operable diesel generator was still

capable of supplying power to the Class 1E electrical power distribution subsystems.This finding has a crosscutting aspect in the area of human performance in that thelicensee's work practices did not ensure that personnel do not proceed in the face of

uncertainty or unexpected circumstances.Enforcement:

TS 5.4.1.a requires that written procedures be established, implemented,and maintained covering the activities specified in Regulatory Guide (

RG) 1.33,

Revision 2, Appendix A, dated February 1978. RG 1.33, Appendix A, Section 9 (a),

requires that maintenance that can affect the performance of safety-related equipment

should be performed in accordance with written procedures. WO 4514076 provided

instructions to

I&C technicians to connect a digital recorder to the

EDG 2 voltage

regulator. Contrary to the instructions in the WO, the technicians connected additional

test equipment, resulting in damage to the EDG. Because the finding is of very low

Enclosure-20-safety significance and has been entered into the licensee's

VI.A of the Enforcement Policy:

CR-CNS-2006-08999, this violation is being treated as an NCV consistent with

Section

NCV 05000528/2006005-02, "Failure to Follow

Work Instructions."1R20Refueling Outages (7111.20) a.Inspection ScopeThe inspectors reviewed the following risk significant refueling items or outage activitiesto verify defense in depth commensurate with the outage risk control plan and

compliance with the TSs: (1) the risk control plan; (2) reactor coolant system

instrumentation; (3) electrical power; (4) decay heat removal; (5) spent fuel pool cooling;

(6) inventory control; (7) reactivity control; (8) containment closure; (9) refueling

activities; (10) heatup and cooldown activities; (11) restart activities; and (12) licensee

identification and implementation of appropriate corrective actions associated with

refueling and outage activities. The inspectors also conducted detailed inspection of the

drywell and torus for cleanliness and reactor coolant leaks.The inspectors completed one sample. b.FindingsIntroduction: The inspectors identified a Green NCV regarding the failure to promptlyidentify and correct a condition adverse to quality regarding an unanalyzed condition in

the torus.Details: During a torus closeout walkdown on November 15, 2006, the inspectorsidentified an unrestrained trolley/hoist and chain hanging from a monorail beam inside

the torus. The monorail beam is located in the top of the torus and runs the length of

the torus directly above each of the torus-to-drywell vacuum breakers. In the as-found

configuration, the trolley/hoist was free to travel around the monorail and the chains

were hanging low enough to impact the vacuum breakers. The trolley/hoist was not

fitted with any braking mechanism to keep it from moving down the monorail during a

dynamic event in the torus (such as the lift of the safety relief valves or a design basis

seismic event).The inspectors questioned licensee personnel that were present during the closeout tourabout the acceptability of leaving the trolley/hoist hanging in the torus for the next

operating cycle, after which the chain was wrapped around a handrail inside the torus, in

an attempt to restrict its potential for movement. Immediately after exiting the torus the

inspector questioned licensee management about the acceptability of this condition in

the torus. During the next shift, the licensee completed the final closeout of the torus

without making any attempt to evaluate the acceptability of the trolley/hoist.The following day the inspectors learned that the torus had been sealed and againquestioned licensee management regarding the condition; however, the licensee was

unable to demonstrate the acceptability of the trolley/hoist. They identified that the

Enclosure-21-trolley/hoist and chain had probably been in the torus for at least five operating cycleswithout being evaluated for potential impact on safety-related equipment. The licensee

subsequently re-opened the torus and removed the trolley/hoist and chain.In a subsequent evaluation documented in Condition Report

10 CFR Part 50, Appendix B, Criterion

CNS-2006-09338, thelicensee determined that, although the chain and trolley/hoist could have become a

missile during postulated events in the torus, they were not of sufficient size or mass to

interfere with the function of safety-related equipment. In addition, the licensee

demonstrated that, while the hanging chain could have damaged the air operators for

the torus-to-drywell vacuum breakers, their safety function would not have been affected

since the air operators are used only for testing and are not necessary during an

accident.Analysis: The performance deficiency associated with this finding involved the failure topromptly identify and correct a condition adverse to quality. Specifically, an unanalyzed

trolley/hoist and associated length of chain hung from a monorail beam inside the torus

for at least five operating cycles until discovered by the inspectors. After being made

aware of the condition by the inspectors, the licensee did not evaluate the condition or

take any corrective action prior to performing a final closeout of the torus. The finding is

more than minor because it is associated with the Barrier Integrity cornerstone attribute

of design control and it affects the associated cornerstone objective to provide

reasonable assurance that physical design barriers protect the public from radionuclide

releases caused by accidents or events. Using the NRC Manual Chapter 0609,

"Significance Determination Process," Phase 1 worksheet, the finding is determined to

have very low safety significance because it did not represent an actual open pathway in

the physical integrity of reactor containment.This finding has a crosscutting aspect in the area of problem identification andresolution in that the licensee did not implement their CAP with a low threshold for

identifying this issue. Specifically, the trolley/hoist existed in a location frequently

accessed during refueling outages but was not identified for at least five operating

cycles.Enforcement:

XVI, requires that measures shallbe established to assure that conditions adverse to quality, such as failures,

malfunctions, deficiencies, deviations, defective material and equipment, and

nonconformance, are promptly identified and corrected. Contrary to this, an unanalyzed

trolley/hoist and chain was installed inside the torus for at least five operating cycles

without being discovered by the licensee. Once informed of the condition by the

inspectors, the licensee did not take prompt corrective actions prior to sealing the torus.

Because this violation was of very low safety significance and was entered in the

UFSAR , procedure requirements, and

CNS-2006-09338, this violation is being treated as an NCV,

consistent with Section

VI.A of the

NRC Enforcement Policy: NCV 05000298/2006005-

03, "Failure to Promptly Identify and Correct an Unanalyzed Condition in the Torus."

Enclosure-22-1R22 Surveillance Testing (71111.22) a.Inspection ScopeThe inspectors reviewed the

TSs to ensure thatthe four surveillance activities listed below demonstrated that the SSCs tested were

capable of performing their intended safety functions. The inspectors either witnessed

or reviewed test data to verify that the following significant surveillance test attributes

were adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;

(3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead

controls; (7) test data; (8) testing frequency and method demonstrated TS operability;

(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of

AS [[]]

ME

Code requirements; (12) engineering evaluations, root causes, and bases for returning

tested SSCs not meeting the test acceptance criteria were correct; (13) reference

setting data; and (14) annunciators and alarms setpoints. The inspectors also verified

that the licensee identified and implemented any needed corrective actions associated

with the surveillance testing.*October 17, 2006: Surveillance Procedure 6.2RHR.201, "RHR Power OperatedValve Operability Test (IST)(DIV 2)," Revision 19*October 25, 2006: Surveillance Procedure

6.PC. 513, "Main Steam Local LeakRate Tests," Revision 13*November 9, 2006: Surveillance Procedure 6.2

DG. 302, "Undervoltage LogicFunctional, Load Shedding, and Sequential Loading Test (DIV 2)," Revision 33*November 14, 2006: Surveillance Procedure

6.MISC. 501, "

ECCS LeakageWalkdown," Revision 5The inspectors completed four samples. b.FindingsIntroduction: A Green, self-revealing

NCV was identified regarding inadequatemaintenance procedures for work on safety-related motor-operated valves (

MOV s).Description: On October 17, 2006, the Division 2 low pressure coolant injection (LPCI)inboard injection valve,

2 RHR pumps. Based onthe failed surveillance test, the licensee declared Division 2 of

MOV-MO25B, failed to open during a quarterly surveillance

test. This is a normally shut containment isolation valve that has an active safety

function to open in order to provide a flow path for Division 2 of the

LP [[]]

CI system. It is

also required to establish shutdown cooling using the Division

LPCI inoperable and

performed troubleshooting, which revealed that the drive train in the Limitorque valve

actuator had failed. The helical pinion gear which transfers torque from the drive motor

to the drive train had fallen off the motor shaft, which allowed the motor shaft to spin

Enclosure-23-freely without moving the valve. The licensee implemented immediate corrective actionsto replace the pinion gear in this valve actuator and to retest the valve, both of which

were completed satisfactorily on October 18, 2006.The pinion gear is normally held in place by a shaft key and key-way arrangement thatprevents radial movement and by a set-screw through the gear which lands in a dimple

on the motor shaft to prevent axial movement. The actuator for

MOV-25B is a

Limitorque size SB-3. Limitorque Maintenance Update 89-1 was issued in 1989 to

provide guidance on motor pinion installation, which included methods for locking the

set-screw and staking the pinion key to prevent axial or radial movement of the gear.

MOV-MO25B was last overhauled in 1995 using Maintenance Procedure

7.2.50.16, "Limitorque SB-3 Valve Operator Maintenance," Revision 1, in 1995, which

reflected these recommendations.The licensee documented this condition in Condition Report

AT orus SuctionNotFunctionalPinion key broken due toincorrect material

CNS-2006-07490 andperformed a root cause analysis. As part of their evaluation, the licensee conducted

extent of condition inspections on a total of 35 safety-related MOV actuators of similar

size. While only one valve (RHR-MOV-MO25B) had failed due to this condition, 10 of

the MOVs showed various levels of degradation on their as-found inspections and were

considered unsatisfactory, while an additional 10 MOVs showed discrepant conditions

that required corrective actions. The following table summarizes the as-found

conditions for these inspections:ValveFunctionInspectionAs-Found ConditionCS-MOV-MO7BCore Spray (CS)

RHR-MOV-MO27ARHR Loop AInjection Outboard

IsolationNotFunctionalPinion and key migrated9/16" off motor shaft. Set-

screw was looseRHR-MOV-31BDrywell Spray AInboard IsolationUnsatKey migrated 1/16" out ofkey-way, set-screw not

landed in dimpleHPCI-MOV-MO15High PressureCoolant Injection

Steam Supply

Inboard IsolationUnsatKey migrated 1/4" out ofkey-way, pinion migrated

1/8" off motor shaft, set-

screw not tightCS-MOV-MO12BCS Pump BInjectionUnsatKey migrated 1/2" out of key-way, set-screw high in lock-

wire groove (not landed in

dimple)RHR-MOV-MO39ARHR Torus CoolingLoop A Outboard

ThrottleUnsatKey migrated 1/2" out of key-way, set-screw not landed

in dimple.

ValveFunctionInspectionAs-Found ConditionEnclosure-24-RR-MOV-MO53AReactorRecirculation

Pump A DischargeUnsatKey migrated 3/8" out ofkey-way, pinion showed

axial movementRR-MOV-MO53BReactorRecirculation

Pump B DischargeUnsatKey migrated 3/8" out ofkey-way, pinion migrated

1/16" off motor shaftRHR-MOV-MO27BRHR Loop BInjection Outboard

IsolationUnsatPinion migrated 1/2" offmotor shaft, set-screw not

landed in dimpleRHR-MOV-MO34BRHR Torus CoolingLoop B Inboard

ThrottleUnsatPinion migrated 1/2" offmotor shaft, set-screw not

landed in dimpleAfter completing these inspections, the licensee concluded that the root cause for theseconditions was a mismatch between the criticality of the task to install MOV motor pinion

gears and the level of detail in the maintenance procedures. This led to various

discrepancies in the installation of the pinion gears, such as the failure to land the pinion

set screw in the motor shaft dimple, and resulted in unacceptable migration of the pinion

gears on the motor shafts. The lack of acceptance criteria for verification of critical

steps and the lack of specific training on pinion gear installation were listed as

contributing causes. The failure of the pinion key in Valve

CS -

MOV-MO7B was

appropriately treated as a separate condition by the licensee and was verified to be an

isolated incident. The inspectors reviewed the licensee's root cause analysis, the applicable maintenanceprocedures, and industry operating experience regarding similar MOV failures. Based

on their review, the inspectors concluded that, while the licensee's maintenance

procedures contained all the recommendation from the vendors' maintenance bulletins,

they were not always adequate to ensure the actuator drive train was correctly

assembled. For example, the maintenance procedure contained the applicable steps

for aligning the pinion gear and drilling the set-screw dimple in the motor shaft, but a

procedure note allowed this step to be skipped if a dimple had previously been drilled in

the shaft. This is an acceptable practice unless the pinion gear is replaced with a new

part that may not align sufficiently with the existing dimple to allow the set-screw to

secure the gear to the shaft. The inspectors found that on at least three of the valves

the set-screw misalignment with the dimple was likely due to the use of new parts that

did not align adequately.Corrective actions for this condition included improvements to the maintenanceprocedures, additional training to personnel performing valve actuator maintenance, and

reworking of the degraded actuators to ensure adequate alignment and securing of the

pinion gear assembly.

Enclosure-25-The inspectors also concluded that the licensee's MOV program was not effective inidentifying degraded conditions such as those described above. Generic Letter 96-05,

"Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated

Valves," issued on September 18, 1996, requested that licensees establish a program to

verify on a periodic basis that safety-related MOVs continue to be capable of performing

their safety functions. In response, the licensee ultimately committed to implement an

MOV program, formulated by a consortium of licensed utilities, which consists primarily

of periodic diagnostic valve testing, to determine the need for preventive or corrective

maintenance. The licensee did not include periodic intrusive actuator inspections as a

part of this program. Most of the valves that were determined to be unsatisfactory had

no intrusive work on the actuator in more than 10 years. A total of 21 safety-related

MOVs had some type of discrepant condition that was not detected by diagnostic

testing. The only means available to detect these conditions prior to valve failure was by

intrusive inspections.Analysis: The performance deficiency associated with this finding involved thelicensee's failure to provide adequate instructions for performing safety-related MOV

maintenance. The finding is more than minor because it is associated with the

Mitigating Systems cornerstone attribute of equipment performance and affects the

associated cornerstone objective to ensure the availability, reliability, and capability of

systems that respond to initiating events. Specifically, the performance deficiency

resulted in the failure of Valve

MOV -MO25B, which rendered Division 2 of the

LP [[]]

CI system inoperable. While other degraded conditions resulted from this

performance deficiency, Division 2 of

LP [[]]

CI was the only system adversely affected prior

to implementing corrective actions. The Phase 1 worksheet in NRC Manual

Chapter 0609, "Significance Determination Process," was used to conclude that a

Phase 2 analysis was required because the finding represented an actual loss of safety

function of a single train of

LP [[]]

CI for greater than its Technical Specification allowed

outage time. The inspectors performed a Phase 2 analysis using Appendix A,

"Technical Basis For At Power Significance Determination Process," of NRC Manual

Chapter 0609, "Significance Determination Process," and the Phase 2 worksheet for

Cooper Nuclear Station. The inspectors assumed that Division 2 of

LP [[]]

CI was

unavailable for 92 days. Additionally, a credit of 1 was used for operator recovery of a

failed train since Valve

TS 5.4.1.a requires that written procedures be established, implemented,and maintained covering the activities specified in

MOV-MO25B could have been manually opened to

establish an injection flow path. While not specifically described in a procedure, this

action would be readily accomplished based on a simple diagnosis. These assumptions

resulted in a finding of very low safety significance with the dominant sequence being

low pressure injection with a stuck-open relief valve. These results were validated by a

senior reactor analyst who concluded that they were conservative by a factor of 4 since

the Phase 2 worksheet calculates the annual core damage frequency for exposure

times greater than 30 days, whereas this condition only existed for a quarter of that time

(92 days).Enforcement:

RG 1.33, Revision 2, Appendix A,

dated February 1978. RG 1.33, Appendix A, Section 9(a), requires that maintenance

affecting the performance of safety-related equipment should be performed in

Enclosure-26-accordance with written procedures. Contrary to this, Maintenance Procedure7.2.50.16, "Limitorque SB-3 Valve Operator Maintenance," Revision 1, did not contain

adequate instructions to ensure that the motor pinion gear was correctly aligned and

secured to the motor shaft in the actuator for Valve

MOV-MO25B when it was

refurbished in 1995. As a result, the pinion gear migrated off the end of the motor shaft,

resulting in a failure of the valve to operate on October 17, 2006. Because the finding is

of very low safety significance and has been entered into the licensee's CAP as

Condition Report

NCV consistent with Section

CNS-2006-07490, this violation is being treated as an

VI.A of the Enforcement Policy:

NCV 05000298/2006005-04,

"Inadequate Maintenance Procedure Results in Safety-Related Valve Failure."Cornerstone: Emergency Preparedness1EP6 Drill Evaluation (71114.06) a.Inspection ScopeThe inspectors observed an emergency preparedness drill conducted on December 20,2006. The observations were made in the control room simulator and the emergency

operations facility and concentrated on the training evolution to identify any weaknesses

and deficiencies in classification, notification, and protective action recommendation. In

addition, the inspectors compared the identified weaknesses and deficiencies against

licensee identified findings to determine whether the licensee is properly identifying

deficiencies. Documents reviewed by the inspectors included:*Emergency Plan for Cooper Nuclear Station, Revision 51*Emergency Plan Implementing Procedures for Cooper Nuclear Station

Emergency Preparedness Drill Scenario for December 20, 2006The inspectors completed one sample. b.FindingsNo findings of significance were identified.2.

RADIAT [[]]

ION [[]]

SAFETY Cornerstone: Occupational Radiation Safety (

OS)2OS1Access Control to Radiologically Significant Areas (71121.01) a.Inspection ScopeThis area was inspected to assess licensee performance in implementing physical andadministrative controls for airborne radioactivity areas, radiation areas, high radiation

areas, and worker adherence to these controls. The inspectors used the requirements

in

10 CFR Part 20 and the licensee's procedures required by

TS as criteria for

determining compliance. During the inspection, the inspectors interviewed the radiation

Enclosure-27-protection manager, radiation protection supervisors, and radiation workers. Theinspectors performed independent radiation dose rate measurements and reviewed the

following items:Performance indicator (PI) events and associated documentation packages reported bythe licensee in the Occupational Radiation Safety cornerstone Controls (surveys, posting, and barricades) of three radiation, high radiation, or airborneradioactivity areasRadiation work permits, procedures, engineering controls, and air sampler locations

Conformity of electronic personal dosimeter alarm setpoints with survey indications andplant policy; workers' knowledge of required actions when their electronic personnel

dosimeter noticeably malfunctions or alarmsBarrier integrity and performance of engineering controls in airborne radioactivity areas

Adequacy of the licensee's internal dose assessment for any actual internal exposuregreater than 50 millirem Committed Effective Dose EquivalentPhysical and programmatic controls for highly activated or contaminated materials(nonfuel) stored within spent fuel and other storage pools Self-assessments and audits related to the access control program since the lastinspection; there were no licensee event reports (LERs) and special reportsCorrective action documents related to access controls

Licensee actions in cases of repetitive deficiencies or significant individual deficiencies Radiation work permit briefings and worker instructions

Adequacy of radiological controls such as, required surveys, radiation protection jobcoverage, and contamination controls during job performance Dosimetry placement in high radiation work areas with significant dose rate gradients

Changes in licensee procedural controls of high dose rate - high radiation areas andvery high radiation areasControls for special areas that have the potential to become very high radiation areasduring certain plant operationsPosting and locking of entrances to all accessible high dose rate - high radiation areasand very high radiation areas

Enclosure-28-Radiation worker and radiation protection technician performance with respect toradiation protection work requirements The inspectors completed 21 of the required 21 samples. b.FindingsInadequate Procedure for Reactor Pressure Vessel (RPV) Refueling PreparationIntroduction: The inspectors reviewed a self-revealing

NCV of Technical Specification5.4.1.a that occurred because the licensee's procedure for

RPV refueling preparation

was not adequate, resulting in an unplanned airborne radioactivity area. The violation

had very low safety significance.Description: On October 22, 2006, the high efficiency particulate air (HEPA) filter hosebetween the

RPV vent duct and the

HEPA filtration unit came apart, creating an

airborne radioactivity area on the refuel floor which alarmed the continuous air monitor

and contaminated five workers. The licensee's refueling procedure allowed the control

room supervisor or shift manager to make changes to the sequence of disassembling

the reactor head in preparation for refueling, but it did not contain any precautions or

limitations to consider the impact of sequence changes on ancillary systems, such as

the

HE [[]]

PA hose connection to the reactor head vent. Consequently, when the licensee

raised the RPV water level at an earlier stage in the reactor head disassembly process,

the increased temperature and pressure applied to the

HE [[]]

PA hose caused it to

disconnect from the RPV vent. The licensee's immediate corrective actions were to

evacuate personnel from the refuel floor and begin decontamination of the workers and

the areas involved. The highest Committed Effective Dose Equivalent received by any

of the workers was 8.3 millirem.Analysis: The failure to have an adequate procedure for refueling was determined to bea performance deficiency. The finding was greater than minor because it was

associated with the Occupational Radiation Safety cornerstone attribute of Program and

Process and affected the cornerstone objective to ensure the adequate protection of a

worker's health and safety from exposure to radiation from radioactive materials

because it resulted in unintended internal doses. Because the finding involved

unplanned, unintended dose resulting from conditions that were contrary to NRC

regulations, the finding was evaluated using the Occupational Radiation Safety SDP.

The finding was determined to be of very low safety significance because: (1) it was not

an as low as is reasonably achievable (ALARA) finding, (2) there was no personnel

overexposure, (3) there was no substantial potential for personnel overexposure, and

(4) the finding did not compromise the licensee's ability to assess dose. Additionally,

this finding had a crosscutting aspect in the area of human performance associated withthe component of work control because the licensee failed to coordinate work activities

by incorporating actions to address the impact of the work on different job activities and

communicate, coordinate, and cooperate with each other during activities in which

interdepartmental coordination is necessary to assure appropriate plant and human

performance.

Enclosure-29-Enforcement: TS 5.4.1.a requires written procedures be established, implemented, andmaintained covering the activities in Regulatory Guide 1.33, Revision 2, Appendix A.

Section 2(K) of RG 1.33 requires procedures for preparation for refueling. General

Operating Procedure 2.1.20.3, titled "RPV Refueling Preparation," states in Section 2.5

that the sequence listed in this procedure may be altered at the discretion of the control

room supervisor or shift manager to suit existing plant conditions and time requirements.

On October 22, 2006, the licensee used this procedure to disassemble the reactor head.

However, this procedure was not adequate because it did not provide any precautions

and limitations for modifying the sequence of the procedure or consideration of impacts

to ancillary systems, thus resulting in uptakes of radioactive material by five workers.

This violation was entered into licensees' CAP as Condition Report 2006-7727.

Because this finding is of very low safety significance and was entered into the

licensee's

CAP , it is being treated as an

NCV , consistent with Section

VI.A. 1 of the

NRC

Enforcement Policy: NCV 05000298/2006005-05, Technical Specification 5.4.1.a,

"Inadequate Procedure For Reactor Pressure Vessel Refueling Preparation."2OS2ALARA Planning and Controls (71121.02) a.Inspection ScopeThe inspectors assessed licensee performance with respect to maintaining individualand collective radiation exposures

ALA [[]]

RA. The inspectors used the requirements in

CFR Part 20 and the licensee's procedures required by

TS as criteria for determining

compliance. The inspectors interviewed licensee personnel and reviewed:Current 3-year rolling average collective exposure

Five outage maintenance work activities scheduled during the inspection period andassociated work activity exposure estimates which were likely to result in the highest

personnel collective exposuresSite-specific trends in collective exposures, plant historical data, and source-termmeasurementsSite-specific

ALA [[]]

RA procedures

ALA [[]]

RA work activity evaluations, exposure estimates, and exposure mitigationrequirementsUse of engineering controls to achieve dose reductions and dose reduction benefitsafforded by shieldingRecords detailing the historical trends and current status of tracked plant source termsand contingency plans for expected changes in the source term due to changes in plant

fuel performance issues or changes in plant primary chemistry

Enclosure-30-Radiation worker and radiation protection technician performance during work activitiesin radiation areas, airborne radioactivity areas, or high radiation areas Self-assessments, audits, and special reports related to the

ALARA [[program since thelast inspectionEffectiveness of self-assessment activities with respect to identifying and addressingrepetitive deficiencies or significant individual deficiencies The inspectors completed 10 of the required 15 samples. b.FindingsNo findings of significance were identified.4.]]

OTHER [[]]

ACTIVI [[]]

TIES4OA1PI Verification (71151) a.Inspection ScopeOccupational Radiation Safety CornerstoneOccupational Exposure Control EffectivenessThe inspectors reviewed licensee documents from August 1, 2005, throughSeptember 30, 2006. The review included corrective action documentation that

identified occurrences in locked high radiation areas (as defined in the licensee's TS),

very high radiation areas (as defined in 10 CFR 20.1003), and unplanned personnel

exposures (as defined in Nuclear Energy Institute (NEI) 99-02). Additional records

reviewed included

ALA [[]]

RA records and whole-body counts of selected individual

exposures. The inspectors interviewed licensee personnel that were accountable for

collecting and evaluating the PI data. In addition, the inspectors toured plant areas to

verify that high radiation, locked high radiation, and very high radiation areas wereproperly controlled.

PI definitions and guidance contained in

NEI 99-02, "Regulatory

Assessment Indicator Guideline," Revision 4, were used to verify the basis in reporting

for each data element.The inspectors completed one sample.

Public Radiation Safety CornerstoneRadiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences The inspectors reviewed licensee documents from August 1, 2005, throughSeptember 30, 2006. Licensee records reviewed included corrective action

documentation that identified occurrences for liquid or gaseous effluent releases that

Enclosure-31-exceeded

PI thresholds and those reported to the

NRC. The inspectors interviewedlicensee personnel that were accountable for collecting and evaluating the

PI data.

PI

definitions and guidance contained in NEI 99-02, "Regulatory Assessment Indicator

Guideline," Revision 4, were used to verify the basis in reporting for each data element.The inspectors completed one sample.

Mitigating Systems CornerstoneThe

PI s for emergency ac power, high pressure injection, heat removal systems,

RHR,and cooling water systems were reviewed using Temporary Instruction 2515/169, as

documented in Section

4OA 5.2. The inspectors completed five samples. b.FindingsNo findings of significance were identified. 4

OA2 Identification and Resolution of Problems (71152) .1Selected Issue Follow-up Inspection a.Inspection ScopeIn addition to the routine review, the inspectors selected the issues listed below for amore in-depth review. The inspectors considered the following during the review of the

licensee's actions: (1) complete and accurate identification of the problem in a timely

manner; (2) evaluation and disposition of operability/reportability issues;

(3) consideration of extent of condition, generic implications, common cause, and

previous occurrences; (4) classification and prioritization of the resolution of the

problem; (5) identification of root and contributing causes of the problem;

(6) identification of corrective actions; and (7) completion of corrective actions in a timely

manner. Condition Report

CNS -2006-08226, Failure of Service Water DischargeStrainer

AC ondition Report

CR -CNS-2006-08821,

MOV -MO15 Torque SwitchFailure*Condition Report

CNS -2006-07255, Total core flow above 77.175

MLBM /

HR Enclosure-32- b.FindingsMOV Torque Switch FailureIntroduction: A self-revealing, Green

NCV was identified regarding the failure to correcta condition adverse to quality on safety-related

MOV s.Description: On November 8, 2006, during diagnostic testing of the

HPCI inboard steamisolation valve (

HPCI-MOV-MO15), the maximum allowable torque for the valve and

valve actuator were exceeded. Thrust in the closed direction was found to be

73,000 pounds versus the maximum allowable value of 56,000 pounds, and 67,000

pounds of thrust were required to re-open the valve as opposed to the allowable value of

45,000 pounds. An inspection of the motor actuator revealed that the torque switch roll

pin had failed while opening the valve in preparation for the diagnostic test.Valve

MOV-MO15 is equipped with a Limitorque SMB-1 motor actuator. This sizeof actuator is typical of most Limitorque designs in that it is equipped with a torque

switch that de-energizes the actuator motor when the drive train achieves a pre-set

torque value. In addition to preventing damage to the valve and actuator components,

the torque switch ensures reliable operation of the valve by limiting the pull-out torque

required to open the valve. The torque switch is coupled to the drive train by a rack and

pinion arrangement, with the rack being integral to the drive train and the pinion being a

gear on the end of the torque switch shaft. The pinion is secured to the shaft by a pin.

The original Limitorque design specified a hollow roll pin for this application; however, on

March 23, 1994, in a letter titled "Potential 10 CFR 21 Condition," Limitorque notified the

NRC that this hollow roll pin was susceptible to failure especially in valve applicationsrequiring high pull-out torque to unseat the valve. Limitorque made no specific

recommendations in this letter but they stated that the design had been changed to

specify a larger, solid pin of a material less susceptible to shear failure. Based on this

letter, the NRC issued Information Notice 94-49, "Failure of Torque Switch Roll Pins," on

July 6, 1994, to alert licensees to this potential failure mechanism. The licensee evaluated Information Notice 94-49 and the Limitorque letter forapplicability to Cooper Nuclear Station. Valve

MOV-MO15 is susceptible to

thermal binding, and opening the valve may require high pull-out torque; therefore, it

was susceptible to the failure mechanisms discussed in the Limitorque letter.

Nevertheless, the licensee concluded the following:This item is being closed, there are no recommendations and the MUG[Motor-operated Valve Users Group] report states that valves that are

going to be susceptible should have already exhibited failures. CNS

[Cooper Nuclear Station] has not had a failure of this type. Any action

required will be taken when an update to the Part 21 or IN 94-049 are

issued.

Enclosure-33-No updated information was ever issued and, since the licensee had not seen anyfailures in the past, they erroneously concluded that they would see no failures in the

future. No actions were taken to replace the susceptible torque switches with the

improved design.The licensee documented this failure in Condition Report

CNS -2006-08821 andconcluded that the Valve

MOV-MO15 actuator failure was due to their failure to

implement the Limitorque design change in 1995. Corrective actions included

replacement of the failed torque switch with the new design as well as completing an

evaluation to verify that no internal valve damage occurred due to the high torque

applied to the valve. Long-term corrective actions were established to replace the

torque switches in the remaining valve actuators that may be susceptible to this failure

mechanism.Analysis: The performance deficiency associated with this finding involved the failure tocorrect a condition adverse to quality on safety-related MOVs. Specifically, the licensee

failed to replace the torque switch in Valve

MOV-MO15 with an improved design

when they had information from the NRC and the vendor indicating that the existing

design was susceptible to failure. As a result, the torque switch in

10 CFR Part 50, Appendix B, Criterion

MOV-MO15

failed on November 8, 2006.

HP [[]]

CI was not required to be operable at the time since the

plant was in Mode 5, but this performance deficiency existed for more than 10 years and

included periods of time when

HP [[]]

CI was required to be operable. The finding is more

than minor because, if left uncorrected, it would become a more significant safety

concern. The finding affected the Mitigating Systems cornerstone. Using the NRC

Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, the

finding is determined to have very low safety significance because it did not result in the

actual loss of a safety function. Enforcement:

XVI, "Corrective Action," requires,in part, that measures be established to assure that conditions adverse to quality, such

as defective material and nonconformances, are promptly identified and corrected.

Contrary to this, the licensee was aware that the torque switch in Valve

MO 15 was subject to failure based on the information in the 10

MOV -

CFR Part 21 notification

from Limitorque, dated March 23, 1994, and Information Notice 94-49, yet they failed to

replace the switch with a less susceptible switch available from the vendor. Because

the finding is of very low safety significance and has been entered into the licensee's

CR -CNS-2006-08821, this violation is being treated as an

NCV consistent with Section

VI.A of the Enforcement Policy: NCV 05000298/2006005-

06, "Failure to Identify and Correct Nonconforming Conditions in Safety-Related Motor-

Operated Valves." Service Water Strainer FailureIntroduction: The inspectors reviewed a self-revealing, Green NCV regarding the failureto correct a condition adverse to quality. This deficiency resulted in failure of Service

Water Discharge Strainer A.

Enclosure-34-Description: On October 29, 2006, operators discovered that the backwash mechanismon Service Water Discharge Strainer A would not rotate when the strainer was placed

into the continuous backwash mode. A subsequent inspection of the strainer drive train

revealed that a flexible rubber sleeve between the motor gear and a reduction gear had

failed. The rubber sleeve is designed with splined surfaces which mate with the motor

gear and reduction gear. The spline on one end of the rubber sleeve had been stripped,

allowing the motor to spin freely. This was documented in Condition Report

CNS-

2006-08226, which was assigned Significance Category "C" or "broke-fix." A formal

cause determination was not conducted; however, during interviews, the licensee stated

that the failure was caused by damage to the rubber coupling due to improper

reassembly during past maintenance activities. Repeated attempts to align the sleeve

with the drive gears, coupled with age-related embrittlement, most likely weakened the

splines on the sleeve to the point where they failed.The inspectors reviewed Condition Report

NCV 05000298/2006002-02 documented in

CNS-2006-00789, which documented asimilar failure of Service Water Discharge Strainer A on February 1, 2006. This

condition was evaluated by an apparent cause determination that concluded that the

coupling had been improperly reassembled following preventive maintenance on

January 29, 2006. Corrective actions included reassembly of the coupling, which was

accomplished on February 1, 2006, under

WO 4485823. The

WO also required the

replacement of degraded components, as necessary, and indicated that the coupling

gears had been replaced but not the coupling sleeve. The sleeve was approximately

years old when it failed, so it would have been reasonable for the licensee to identify

and correct any age-related degradation during corrective maintenance performed only

months before the failure.Analysis: The performance deficiency associated with this finding involved the failure toidentify and correct a condition adverse to quality. Specifically, SW Discharge Strainer

A failed on October 29, 2006, apparently due to age-related degradation of components

in the motor coupling. This degradation was not identified during corrective

maintenance on February 1, 2006, which required the identification and replacement of

degraded components. The finding is more than minor because it is associated with the

Mitigating Systems cornerstone attribute of equipment performance and affects the

associated cornerstone objective to ensure the availability and reliability of systems that

respond to initiating events. The Phase 1 worksheet in NRC Manual Chapter 0609,

"Significance Determination Process," was used to conclude that a Phase 2 analysis

was required because the findings also increased the likelihood of a loss of service

water initiating event. The assumptions used to perform the Phase 2 and Phase 3

analyses associated with

NRC Integrated

inspection Report 05000298/2006002 bound the assumptions necessary to evaluate this

finding. NCV 05000298/2006002-02 was found to be of very low safety significance;

therefore, this finding is also of very low safety significance. The treatment of this

finding was validated by a senior reactor analyst.The cause of the finding is related to the corrective action component of the crosscuttingarea of problem identification and resolution in that the licensee failed to identify this

issue in a timely manner.

Enclosure-35-Enforcement:

10 CFR Part 50, Appendix B, Criterion

XVI, "Corrective Action," requires,in part, that measures be established to assure that conditions adverse to quality are

promptly identified and corrected. Contrary to this, the licensee failed to identify a

condition adverse to quality regarding degradation of the motor coupling in Service

Water Discharge Strainer A. Specifically, corrective maintenance was performed on the

motor coupling on February 1, 2006, which required the replacement of degraded

components as necessary. This maintenance activity failed to identify hardening and

embrittlement of a rubber sleeve in the coupling, resulting in failure 8 months later on

October 29, 2006. Because the finding is of very low safety significance and has been

entered into the licensee's

NCV consistent with Section

CR-CNS-2006-08226, this violation

is being treated as an

VI.A of the Enforcement Policy:

NCV 05000298/2006005-07, "Failure to Identify and Correct Degraded Condition on

Service Water Strainer." Operation of Reactor Above Total Core Flow LimitIntroduction: The inspectors identified a Green

NCV of

TS 5.4.1.a regarding thelicensee's failure to follow procedures for power operation and process monitoring.

Specifically, the licensee operated the reactor above the total core flow limit, contrary to

requirements of General Operating Procedure 2.1.10, "Station Power Changes." Description: On October 8, 2006, the licensee initiated Condition Report

PMIS typer whenever total core flow exceeds the

CNS-2006-07255 to document a plant monitoring information system (PMIS) warning alarm for total

core flow above 77.175 million pounds-mass per hour (MLBH). This alarm appears on

the

UFSAR-allowed limit of

77.175 (MLBH), which represents 105 percent of rated core flow. At the time the alarm

was received, the plant was operating near 105 percent of rated core flow to maximize

core thermal power during the coastdown to Refueling Outage

RE 23.The inspectors questioned the licensee's response to the alarm and the acceptability ofoperating so close to the

UFSAR core flow limit. As a result of the licensee's response

to the question and the inspectors' direct observation of core flow spikes exceeding

77.1

ML [[]]

BH in the control room, the inspectors asked the licensee to provide the actual

measured core flow data for the previous month.When the licensee analyzed the measured data, they determined that over the previousmonth the plant had been operating above 105 percent rated core flow approximately

percent of the time. The licensee identified that this represented an unanalyzed

condition and that the plant had been operated outside of the established power-to-flow

map in violation of General Operating Procedure 2.1.10, "Station Power Changes,"

Revision 69. Step 2.11 of Procedure 2.1.10 directed that the "Reactor should be

operated within constraints of Power-To-Flow Map." Attachment 1 to Procedure 2.1.10

is the current power-to-flow map and shows the maximum allowable core flow to be

105 percent (77.175

ML [[]]

BH). The licensee reduced core flow until all measured spikes

were below the limit and implemented a night order to maintain core flow below

105 percent of rated flow using all available instrumentation. Condition Report

TS 5.4.1.a requires that written procedures be established, implemented,and maintained covering the activities specified in

CNS-

2006-07255 was updated to reflect the procedural violation.

Enclosure-36-In order to analyze this condition, the licensee contacted the nuclear steam systemsupply vendor. The vendor provided the licensee a set of conditions during which the

plant could be operated with spikes above the 105 percent rated core flow limit but with

time-averaged core flow below the limit. The licensee determined that, for the time

period in question, these conditions were satisfied and that no damage to core internal

components had occurred.Analysis: The performance deficiency associated with this finding involved thelicensee's failure to follow the requirements of General Operating Procedure 2.1.10,

"Station Power Changes." The finding is more than minor because it is associated with

the Barrier Integrity cornerstone attribute of human performance (procedural adherence)

and it affects the associated cornerstone objective to provide reasonable assurance that

physical design barriers, such as fuel cladding, protect the public from radionuclide

releases caused by accidents or events. Using the NRC Manual Chapter 0609,

"Significance Determination Process," Phase 1 worksheet, the finding is determined to

have very low safety significance because it only had the potential to affect the fuel

cladding barrier.This finding has a crosscutting aspect in the area of human performance in that thelicensee did not effectively communicate expectations regarding work practices to

operators for the control of key parameters such as total core flow. Enforcement:

RG 1.33, Revision 2, Appendix A,

dated February 1978. RG 1.33, Appendix A, Section 2 (g), requires that procedures be

established and followed for power operation and process monitoring. General

Operating Procedure 2.1.0, "Station Power Changes," Revision 69, provided specific

limits for core flow on a power-to-flow map. Contrary to this procedural requirement, the

plant was operated at greater than 105 percent of rated core flow for a significant

portion of September and October 2006. Because the finding is of very low safety

significance and has been entered into the licensee's

VI.A of the Enforcement Policy:

CNS-2006-07255, this violation is being treated as an NCV consistent with

Section

NCV 05000528/2006005-08, "Operation of

Reactor Above Total Core Flow Limit.".2Semiannual Trend Review a.Inspection ScopeThe inspectors completed a semiannual trend review of repetitive or closely relatedissues that were documented in corrective action documents, corrective maintenance

documents, and the control room logs to identify trends that might indicate the existence

of more safety significant issues. The inspectors' review covered the 12-month period

between November 2005 and November 2006. When warranted, some of the samples

expanded beyond those dates to fully assess the issue. The inspectors reviewed the

following issues:

Enclosure-37-*Personnel contamination events*Fire door degradation

Sump pump failures

Drawing discrepancies

Crane and hoist failuresThe inspectors compared their results with the results contained in the licensee's routinetrend reports. Corrective actions associated with a sample of the issues identified in the

licensee's trend report were reviewed for adequacy. Documents reviewed by the

inspectors are listed in the attachment. b.FindingsNo findings of significance were identified..3Radiological Protection Problem Identification and Resolution a.Inspection ScopeThe inspectors evaluated the effectiveness of the licensee's problem identification andresolution process with respect to the following inspection areas:Access Control to Radiologically Significant Areas (Section

2OS 1)

ALARA Planning and Controls (Section 2OS2) b.FindingsNo findings of significance were identified. .4Heat Sink Performance Problem Identification and Resolution a.Inspection ScopeThe inspectors evaluated several condition reports, including root cause and apparentcause analyses, related to the performance of the service water system and the ultimate

heat sink. The inspectors evaluated corrective actions related to the following specific

items:*Control of Asiatic clams and zebra mussels*Loss of the zurn strainers The inspectors performed this evaluation by review of the corrective action programdocuments, review of records, and interviews with licensee personnel. b.FindingsNo findings of significance were identified.

Enclosure-38-4OA3Event Follow-up (71153) .1Fire in Reactor Building a.Inspection ScopeThe inspectors responded to the plant on November 11, 2006, due to the declaration ofa Notice of Unusual Event (NOUE) in response to a small fire in the reactor building.

The inspectors verified that the licensee was taking the appropriate actions in

accordance with their emergency plan and station firefighting procedures. Following the

event, the inspectors toured the area to assess the damage and potential impacts on

other plant equipment. The followup inspection also reviewed the cause of the fire and

the licensee's corrective actions. b.FindingsIntroduction: A Green, self-revealing finding was identified regarding the inadequatedesign and installation of heat tracing on the standby liquid control (SLC) system, which

resulted in a small fire in the reactor building.Details: At 5:16 a.m. on November 11, 2006, control room operators received a reportof sparks and small flames coming from a heat trace junction box on the SLC system.

This portion of the SLC system is located on the 976 foot elevation in the reactor

building. The control room entered Emergency Procedure 5.4FIRE, "General Fire

Procedure," Revision 14, and activated the station fire brigade. The reactor building

station operator also reported to the scene and discharged a dry chemical fire

extinguisher onto the junction box, which extinguished the flames. The station operator

reported his actions to the control room and the fact that the junction box was still

arcing. As directed by the control room, the operator opened two breakers on Lighting

Panel MPR1, which de-energized the heat trace and stopped the arcing. Shortly

afterward, the fire brigade arrived on the scene, conducted a thorough search of the

area to verify that the fire had not spread to adjacent areas, and declared the fire out at

5:33 a.m. The control room appropriately declared an

NO [[]]

UE at 5:30 a.m. due to a fire

in the protected area lasting longer than 10 minutes. The

NO [[]]

UE was exited at 5:58 a.m.

Damage was limited to approximately 10 inches of the exposed heat trace cable that

burned.During the event followup inspection, the inspectors questioned why the breaker for theheat trace had not tripped due to the fault, which caused the arcing and sparking. The

heat trace for this portion of the system is supplied by a 20 amp breaker from a 120 volt

ac lighting panel. In response, the licensee referred the inspectors to a section of the

heat trace vendor manual which stated:If the heating cable is improperly installed or physically damaged . . .sustained arcing or fire could result. If arcing does occur, the fault current

may be too low to trip conventional circuit breakers.

Enclosure-39-Raychem, the U.S. National Electrical Code, and the Canadian ElectricalCode require both ground-fault protection of equipment and a grounded

metallic covering (usually braid) on all heating cables.This section of heat trace was installed in 1994 and had no ground-fault protection.

The licensee documented this event in Condition Report

SLC system.Enforcement: Since the

CNS-2006-09006 andperformed a root cause analysis. The licensee concluded that the fire had been caused

by the failure to install the heat trace in accordance with the vendors' recommendations.

In addition to the use a of ground-fault protected circuit, the vendor recommended

periodic measurement of heat trace insulation resistance to detect age-related

degradation of the insulation. The licensee did not routinely perform this type of

monitoring. Corrective actions included replacement of the damaged heat trace and

installation of a ground-fault interrupter on the circuit. In addition, maintenance

procedures were revised to periodically check heat trace insulation resistance values.

The licensee found similar conditions on other heat trace circuits throughout the plant

and has established corrective actions to address those conditions as well.Analysis: The performance deficiency associated with this finding involved thelicensee's failure to install heat trace in accordance with vendor recommendations,

which resulted in a fire in the

SLC heat trace. The

SLC heat trace is not safety-related,

but it is required to support operability of the SLC system; therefore, this finding is more

than minor because it is associated with the Mitigating Systems cornerstone attribute of

design control and affects the associated cornerstone objective to ensure the

availability, reliability, and capability of the SLC system, which is required to respond to

initiating events, such as anticipated transients without scrams. Using the NRC Manual

Chapter 0609, "Significance Determination Process," Phase 1 worksheet, the finding is

determined to have very low safety significance because it did not result in a loss of

safety function for the

SLC heat trace is not safety-related, no violation of

NRC requirements was identified. This finding is identified as

FIN 05000298/2006005-09,

"Failure to Implement Vendor Recommendations Results in a Fire." .2(Closed)

LER 05000298/2006-005:

RHR Loop B Injection Valve Failure due to IncorrectPinion Gear Installation in Motor OperatorOn October 17, 2006, during surveillance testing, the

RHR Loop B injection valve,

RHR-MOV-MO25B, failed to open remotely from the control room. After troubleshooting the

valve, the licensee concluded that it failed to operate because the motor pinion gear in

the Limitorque motor actuator had migrated off the motor shaft. The licensee also

concluded that this most likely occurred during the last successful valve stroke in July

2006, which rendered Loop B inoperable for 92 days. The TS-allowed outage time for

one emergency core cooling train is 7 days. The root cause and corrective action

associated with this condition are discussed further in Section 1R22. The enforcement

aspects of this issue are discussed in Sections 1R22 and 4OA7. This item is closed.

Enclosure-40-4OA5Other Activities (71153).1(Closed) Temporary Instruction 2515/169: Mitigating Systems PerformanceIndex (MSPI) Verification a.Inspection ScopeThe inspectors sampled licensee data to verify that the licensee correctly implementedthe

MS [[]]

PI guidance for reporting unavailability and unreliability of the monitored safety

systems. The monitored systems included the emergency alternating current (EAC)

power system,

HPCI , heat removal system reactor core isolation cooling (

RCIC), RHR,

and cooling water systems (SW). The inspectors reviewed operating logs, limiting

condition of operation logs, maintenance records, condition reports, surveillance test

data, and the maintenance rule database to verify that the licensee properly accounted

for planned unavailability, unplanned unavailability, and equipment failures. The

inspectors identified a number of errors in the baseline unavailability figures and the

reported data for the second quarter of 2006. The licensee reperformed the affected

MSPI calculations and verified that no

PI threshold changes resulted from these errors.

The results of the inspectors' efforts are documented below. Documents reviewed by the inspectors are listed in the attachment. b.Findings

1.F or the sample selected, did the licensee accurately document the baselineplanned unavailability hours for the

MSPI systems?Not in all cases. The inspectors validated the baseline planned unavailabilityhours for each of the five monitored systems and identified one error in the

reported baseline planned unavailability data.For the

EAC power indicator, the inspectors determined that the licensee madean incorrect change to the

MSPI Basis Document on June 27, 2006, to add

several hundred hours of previously unrecognized unavailability. This change

was made due to the discovery of a latent design deficiency discovered in April

2006. In a corrective action response to Condition Report

CNS-2006-03093,

the licensee evaluated that the diesel generator voltage regulators would not

have been capable of supplying essential safeguard features electrical loads if a

loss of offsite power/loss of coolant accident occurred while the diesel generator

was in parallel with the grid for testing. As a result, the licensee considered the

diesel generators to have been unavailable during parallel operations and

documented an additional 211 hours0.00244 days 0.0586 hours 3.488757e-4 weeks 8.02855e-5 months of planned unavailability against each EDG

from the introduction of the condition in 1998 through April 21, 2006. During the

inspection, the inspectors discovered that the loss of offsite power/loss of coolant

accident function is not a monitored function in

MS [[]]

PI, and as such these hours

should not have contributed to the baseline planned unavailability. The licensee

Enclosure-41-plans to correct this discrepancy during a revision to the

MS [[]]

PI Basis Documentin the next quarter. The licensee has documented this discrepancy in Condition

Report

2.F or the sample selected, did the licensee accurately document the actualunavailability hours for the

CNS -2006-10488.

MSPI systems?Not in all cases. The inspectors identified the following examples of inaccurateaccounting of system unavailability:*In the

MSPI Basis Document, the licensee excluded Surveillance Procedure6.

HPCI. 102, "HPCI Test Mode Surveillance Operation From the

ASD -

HPCI

Panel," from unavailability monitoring based on the availability of an operator to

restore control room control of the system upon demand. The inspectors

determined that this was not in accordance with the guidance in NEI 99-02,

"Regulatory Assessment Performance Indicator Guideline." On page F-6 of

NEI 99-02, Revision 4, guidelines are provided for considering a monitored

function available during testing. One of those criteria is that restoration actions

taken by operators "must be uncomplicated (a single action or a few simple

actions)." The intent of this paragraph is to allow licensees to take credit for

restoration actions that are virtually certain to be successful (i.e., probability

nearly equal to 1) during accident conditions. Based on a review of the

procedure and observation of the test by the inspectors, the inspectors

determined that this criteria was not satisfied. The licensee reviewed the

procedure and came to the conclusion that the treatment of

HP [[]]

CI as available

during the performance of

6.HP [[]]

CI.102 on April 26, 2006, was inappropriate and

that the second quarter

2006 MSPI -

HPCI unavailability figures under-reported

actual

HPCI unavailability. In addition, the

MSPI-HPCI baseline unavailability

numbers will also require reassessment to include the performance of this test

each cycle. The licensee documented this discrepancy in

CNS-2006-10488.*On May 3, 2006, the licensee performed Surveillance Procedure 6.1DG.104,"Diesel Operability Test With Isolation Switches in Isolate (Div 1)." During the

performance of this test, the station entered an unanticipated orange on-line risk

window due to the unforseen unavailability of both Diesel Generator 1 and the

Emergency Station Service Transformer. Despite the Orange risk window

recognized by operations, the inspectors identified that the system engineer did

not recognize this test as an EAC unavailability window during document review

in preparation for submitting the second quarter

2006 MS [[]]

PI data. The licensee

recognized this human error and documented the discrepancy in Condition

Report

CNS -2006-10354.*The inspectors identified that some unavailability hours for the

SW system wereincorrectly applied to the wrong

MSPI function. As a result, the

MSPI -

SW

unavailability index was under-reported. The licensee documented this

discrepancy in Condition Report

SW changed from 5.4E-8 to 1.1E-7 andthat the total

CNS-2006-10336. As a result of the error,

the licensee submitted a PI correction data file and determined that the

Enclosure-42-unavailability index contribution to

MSPI -

MSPI -

SW changed from 9E-9 to 4.7E-8. The licensee documented

this discrepancy in Condition Report

3.F or the sample selected, did the licensee accurately document the actualunreliability information for each

CNS -2006-10488.

MSPI monitored component?Not in all cases. The inspectors identified several examples of errors in thecalculated unreliability index.*The inspectors identified a mathematical error in the

MSPI Basis Document forthe

RCIC system. Section 1.4.F on page 24 of the Basis Document

demonstrates estimated demand and run hour figures for the monitored

components in the

RC [[]]

IC system. The table documented an estimated demand

frequency of 1.3 demands per quarter for the

RC [[]]

IC turbine. The text at the top

of the page estimated that the

RC [[]]

IC turbine runs for approximately 30 minutes

for each test (this number was validated by the inspector by reviewing operating

logs). The documented estimate for quarterly run hours was incorrectly

calculated as 1.3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months per quarter (versus 1.3 x .5 hour5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months = 0.65 hours7.523148e-4 days 0.0181 hours 1.074735e-4 weeks 2.47325e-5 months per

quarter). This demand estimate is an input into the calculation of the unreliability

index component of

MS [[]]

PI. The licensee documented this discrepancy in

Condition Report

NEI 99-02). Paragraph F2.2.1 on page F-19 of

CNS-2006-10488.*In the tabulation of baseline demands and run hours for SW systemcomponents, the licensee used estimated figures based on historical averages

(as allowed by

NEI 99-02

requires that estimated demand information be updated when it differs from

actual demand data by greater than 25 percent. Based upon a review of 6

months of operating data, the inspectors identified that the estimated test

demands for the SW pumps was 25 percent greater than the actual number of

test demands. The inspectors noted that the licensee had written a notification

to create a repetitive task to evaluate the validity of the demand estimates, but

the task had yet to be defined or performed. These demand estimates are an

input to the calculation of the unreliability index component of

MS [[]]

PI. The

licensee has documented this discrepancy in Condition Report

4.D id the inspector identify significant errors in the reported data, which resulted ina change to the indicated index color? Describe the actual condition andcorrective actions taken by the licensee, including the date when the revised

CNS-2006-

10488.

PIinformation was submitted to the NRC.No discrepancies were identified in the reported data which resulted in a changeto the indicated color.

Enclosure-43-

5.D [[id the inspector identify significant discrepancies in the Basis Document whichresulted in: (1) a change to the system boundary; (2) an addition of a monitoredcomponent; or (3) a change in the reported index color? Describe the actualcondition and corrective actions taken by the licensee, including the date of whenthe Basis Document was revised.No such issues were identified.4]]

OA6Management MeetingsOn October 17, 2006, the inspectors conducted a telephonic exit to discuss the resultsof the heat sink inspection with Mr. J. Roberts, Director, Nuclear Safety and Assurance,

and other members of the licensee staff. The inspectors returned proprietary

information examined during the inspection to the licensee. Licensee management

acknowledged the inspection results.On November 3, 2006, the inspectors presented the occupational radiation safetyinspection results to Mr. S. Minahan, General Manager of Plant Operations, and other

members of the licensee's staff who acknowledged the findings. The inspectors

confirmed that proprietary information was not provided or examined during the

inspection.Additionally, on November 14, 2006, after NRC management reviews, the healthphysics inspectors re-exited the issues identified during the inspection with Mr. D. Oshlo,

Radiation Protection Manager, and other members of the licensee's staff who

acknowledged the findings.On December 12, 2006, the inspector conducted an exit meeting to present theinspection results regarding inservice inspection activities to Mr. S. Minahan, General

Manager of Plant Operations, and other members of his staff who acknowledged the

findings. The inspector confirmed that the proprietary information reviewed was

returned to the licensee prior to the end of the inspection.On January 3, 2007, the inspector presented the inspection results from the biennialoperator requalification inspection to Mr. S. Minahan, General Manager of Plant

Operations, and other members of licensee management. The licensee acknowledged

the findings that were presented. The inspector confirmed with the licensee that no

proprietary information was received by the inspector during the inspection.On January 9, 2007, the NRC resident inspectors presented the results of the inspectionactivities to Mr. S. Minahan and other members of his staff who acknowledged the

findings. The inspectors confirmed that proprietary information was not disclosed in this

inspection report.

Enclosure-44-4OA7Licensee-Identified ViolationsThe following violations of very low significance (Green) were identified by the licenseeand are violations of

NRC requirements which meet the criteria of Section

VI of the

NRC Enforcement Policy for being dispositioned as

NCV s.TS 5.4.1.a requires procedures for activities covered by

RG 1.33. The licensee'sprocedure for low power range monitor (

LPRM) removal and installation, Nuclear

Performance Procedure 10.29, step 2, refers to the vendor's procedure for

bending the

LP [[]]

RM prior to storage in the spent fuel pool. Vendor Procedure

83A5614, Section 7, step 1, states to lower the elevator with a hand winch until it

contacts the hardstop or the cable goes slack (lowest possible position). During

the night shift of October 27, 2006, the elevator of the bender was not left in the

lowest possible position. A crew change occurred, and the fact that the bender

was not in the lowest possible position was not turned over to the arriving crew.

Contrary to the procedure, the arriving crew commenced bending the

LP [[]]

RM,

which resulted in one leg of the

LP [[]]

RM being shorter than the other and the

irradiated detectors being closer to the surface of the water than expected.

Consequently, when the

LP [[]]

RM was moved through the transfer canal to the

spent fuel pool and raised to clear the lip of the transfer canal, the dose rates at

the surface of the water rose from 100 millirem per hour to 1,700 millirem per

hour. Radiation Protection personnel covering the job identified the increase in

dose rates and requested that the

LP [[]]

RM be lowered in the water. At the same

time, four electronic dosimeter alarms were received. The workers placed the

LP [[]]

RM in a safe condition by completing the evolution and then exited the area.

Using the Occupational Radiation Safety SDP, the inspectors determined that

the finding was of very low safety significance because it was not an

ALA [[]]

RA

finding, there was no overexposure or substantial potential for an overexposure,

and the ability to assess dose was not compromised. The licensee documented

this event in Condition Report

TS 3.5.1 allows one train of emergency core cooling to be inoperable for up to7 days. Contrary to this,

CNS -2006-08134.

RHR Loop B was inoperable for 92 days due to a failure

of the motor actuator on the Loop B injection valve (RHR-MOV-MO25B). This

was identified by the licensee during quarterly inservice testing of the valve and

was entered into the corrective action program as Condition Report

CNS-

2006-07490. The licensee completed corrective maintenance on the motor

actuator on October 18, 2006, and successfully re-tested the valve. This finding

was of very low safety significance as discussed in Section 1R22.*TS 5.4.1.a requires that written procedures be established, implemented, andmaintained covering the activities specified in RG 1.33, Revision 2, Appendix A,

dated February 1978. RG 1.33, Appendix A, Section 9(a), requires that

maintenance affecting the performance of safety-related equipment should be

performed in accordance with written procedures. Maintenance Procedure

7.2.50.13, "Limitorque SB-0 Valve Operator Maintenance," Revision 0, required

the use of a 4140 stainless steel motor pinion key. Contrary to this, during an

overhaul of the motor actuator for Valve

CS -

MOV-MO7B in 1993, a key was

Enclosure-45-fabricated onsite from material other than 4140 stainless steel. An inspection ofthe actuator on November 11, 2006, showed that this key had failed. The valve

remained functional despite this failure and there was no adverse impact to the

core spray system. The licensee documented this as Condition Report

ATION AttachmentA-1SUPPLEMENTAL

CNS-

2006-08917 and replaced the failed key with one made of 4140 stainless steel.ATTACHMENT:

SUPPLE [[]]

MENTAL [[]]

INFORM [[]]

INFORM [[]]

ATIONK EY

POINTS [[]]

OF [[]]

CONTAC [[]]

TLicensee PersonnelT. Bahensky, System EngineerR. Beilke, Chemistry Manager

D. Buman, Systems Engineering Division Manager (Acting)

K. Chambliss, Operations Manager

R. Dyer, Heat Exchanger Program Engineer

J. Dykstra, Electrical Engineering Program Supervisor

R. Edington, Chief Nuclear Officer

T. Erickson, System Engineer

R. Estrada, Corrective Actions Manager

J. Flaherty, Licensing

P. Fleming, Licensing Manager

J. Florence, Simulator Supervisor

S. Freeborg, Response Team Lead

K. Gardner, Supervisor, Radiation Protection

J. Gren, System Engineer

G. Hadley, System Engineer

T. Hottovy, Director of Engineering (Acting)

T. Huff, Maintenance Rule Coordinator

G. Kline, Director, Engineering

J. Larson, Supervisor, Quality Assurance

M. McCormack, Electrical Systems/I&C Engineering Supervisor

E. McCutchen, Senior Licensing Engineer, Regulatory Affairs

M. Metzger, System Engineer

S. Minahan, General Manager of Plant Operations

A. Mitchell, Manager, Design Engineering

R. Noon, Root Cause Team Leader, Corrective Actions

D. Oshlo, Manager, Radiation Protection

J. Roberts, Director, Nuclear Safety and Assurance

A. Sarver, Balance of Plant Engineering Supervisor

T. Shudak, Fire Protection Program Engineer

T. Stevens, Supervisor, Mechanical Engineering

C. Sunderman, Supervisor, Radiation Protection

K. Thomas, Mechanical Programs Supervisor

D. Van Der Kamp, Acting Manager, Licensing

J. Waid, Training Manager

NRCS. Schwind, Senior Resident InspectorN. Taylor, Resident Inspector

AttachmentA-2LIST

OF [[]]

ITEMS [[]]

OPENED ,

CLOSED ,

AND [[]]

DISCUS SEDOpened and Closed05000528/2006005-01

NCVM edical Certification and Monitoring of Personnel RequiringOperator Licenses for Nuclear Power Plants05000298/2006005-02

NCVFailure to Follow Work Instructions

05000298/2006005-03NCVFailure to Promptly Identify and Correct an UnanalyzedCondition in the Torus05000298/2006005-04

NCVI nadequate Maintenance Procedure Results in Safety-Related Valve Failure05000298/2006005-05

NCVInadequate Procedure For RPV Refueling Preparation

05000298/2006005-06NCVFailure to Identify and Correct Nonconforming Conditions inSafety-Related

MOV s05000528/2006005-07

NCVF ailure to Identify and Correct Degraded Condition on

SWS trainer05000298/2006005-08

NCVOperation of Reactor Above Total Core Flow Limit

05000298/2006005-09

FINF ailure to Implement Vendor Recommendations Results ina FireClosed05000298/2006-005

LERRHR Loop B Injection Valve Failure due to Incorrect PinionGear Installation in Motor OperatorLIST

OF [[]]

DOCUME NTS

REVIEW [[]]

EDSection 1R07: Biennial Heat Sink Inspection (71111.07B, 71152B)Procedures2.2.3.1, "Traveling Screen, Screen Wash, and Sparger System," Revision 583.10, "Erosion/Corrosion Program," Revision 11

3.30, "Macroscopic Biological Fouling Organism Sampling," Revision 5

3.34, "Heat Exchanger Program," Revision 8

6.1SW.101, "Service Water Surveillance Operation (DIV 1) (IST)," Revisions 18, 19, and 20

AttachmentA-36.2SW.101, "Service Water Surveillance Operation (DIV 2) (IST)," Revisions 18, 20, and

216.SW. 102, "Service Water System Post-

LOCA Flow Verification," Revision 15

6.SW. 202, "Service Water Power-Operated Valve Operability Test (

IST)," Revisions 13C2, 14,and 156.1SWBP.101, "RHR Service Water Booster Pump Flow Test and Valve Operability Test(DIV 1)," Revisions 10, 11, 12, and 146.2SWBP.101, "RHR Service Water Booster Pump Flow Test and Valve Operability Test(DIV 2)," Revisions 11, 12, and 136.1REC.101, "REC Surveillance Operation (IST) (DIV 1)," Revisions 7 and 8

6.2REC.101, "REC Surveillance Operation (IST) (DIV 2)," Revisions 7 and 8

6.REC. 201, "

REC Motor-Operated Valve Operability Test (IST)," Revisions 13C2, 14, and 15

7.2.42.1, "REC Heat Exchanger Maintenance," Revision 6

7.2.42.2, "RHR Heat Exchanger Maintenance," Revision 6

13.15.1, "Reactor Equipment Cooling Heat Exchanger Performance Analysis," Revision 24

13.17, "Residual Heat Removal Heat Exchanger Performance Testing," Revision 19

13.17.1, "Residual Heat Removal Heat Exchanger

DAS Based Performance Testing,"Revision 613.17.2, "Thermal Performance Test Procedure For Reactor Heat Removal Heat Exchangers,"Revision 0Drawings

CED -6016551-SK-01, "Replacement Guide Wall Elevation - Intermediate Stage," Revision 0

CNS -

MISC-65, "Turning Vanes at Intake Structure Guide Wall - Plan Layout and Details,"Revision N00Plan and Profile Drawings, "Nebraska Public Power District River Intake Structure River BottomElevation Data - Brownville, Nebraska," Sheets 1 - 4, dated July 12, 2006CalculationsNEDC 93-184, "RHR Heat Exchangers and Thermal Performance Tube Plugging Margin,"Revision 1

AttachmentA-4NEDC 94-021, "REC-HX-A and

REC -

HX-B Maximum Allowable Accident Case Fouling,"Revision 4Maintenance Instructions2471325409Work Orders44915234274402

4361453

4334505

4458080Corrective Action Documents2004-033772004-063922004-070222004-074092004-075682004-076882005-013322005-022922005-026852005-030832005-031982005-03212

2005-032132005-033822005-035492005-038592005-038742005-03883

2005-038552005-041562005-049562005-050412005-056502005-06176

2005-071522005-071882005-071892005-077422005-077722005-07810

2005-078302005-084112005-084132005-084372005-084862005-08490

2005-085762005-085932005-088522005-088542005-089362005-08945

2005-092982005-093012005-093302005-093712005-093732005-09397

2006-000202006-002002006-005102006-007672006-007912006-00926

2006-009402006-011672006-011722006-011842006-013492006-01384

2006-016462006-016952006-018722006-019152006-019162006-01939

2006-022032006-022692006-024862006-026342006-029152006-03206

2006-033012006-039992006-043422006-047752006-052992006-05327

2006-066MiscellaneousCooper Nuclear Station - Service Water Options AnalysisEPRI NP-7552, "Heat Exchanger Performance Monitoring Guidelines," December 1991

AttachmentA-5Updated Final Safety Analysis Report, Sections 6.0, "Reactor Equipment Cooling System,"and 8.0, "Service Water and

RHR Service Water Booster System" Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment,"July 18, 1989Generic Letter 89-13, Supplement 1, "Service Water System Problems Affecting Safety-RelatedEquipment," April 4, 1990Letter

LQA 8100180, "IE Bulletin 81-03, 'Flow Blockage of Cooling Water to Safety SystemComponents by Corbicula sp. and Mytilus sp.,'" dated May 29, 1981Letter

CN [[]]

SS907024, "Response to Generic Letter 89-13," dated January 29, 1990

Letter

NLS 9000459, "Generic Letter 89-13 Recommended Inspection Program,"dated October 15, 1990Letter

NSD920007, "Completion of Generic Letter 89-13 Actions," dated January 9, 1992

Letter

NLS 970215, "Reply to a Notice of Violation

NRC Inspection Report Nos. 97-07and 97-12," dated December 31, 1997Letter

NLS 980016, "Clarification of Commitments with Respect to

NRC Inspection ReportNos. 97-07 and 97-12," dated January 28, 1998Inspection Report 05000298/1997012, dated October 3, 1997

Condition Adverse Quality 97-0742

Condition Adverse Quality 97-1153

Resolve Condition Report 2001-0529

Significant Condition Adverse Quality 97-0742

Inspection Report 05000298/2005015, dated April 25, 2006

Final Report Corbicula (Asiatic Clams) Monitoring and Mitigation Service Water SystemEvaluation Nebraska Public Power District Cooper Nuclear Station, June 2006Structural Integrity Associates Report

SIR -98-094, "Effects of River Water Service on CooperPlant Systems - Final Report," Revision 0

IE Bulletin 81-03, "Flow Blockage of Cooling Water to Safety System Components by Corbiculasp. (Asiatic Clam) and Mytilus sp. (Mussel)," dated April 10, 1981Inservice tests for REC pumps, service water booster pumps and valves, and service waterpumps and valves from the 3rd Quarter 2004 throug the 2nd Quarter 2006

AttachmentA-6Erosion/Corrosion Summary Report Sections for Service Water for

COR002-19-02, "Ops Reactor Equipment Cooling," Revision 19

Lesson Plan COR002-27-02, "Ops Service Water," Revision 27

REC Heat Exchangers A and B Eddy Current Tests

Last three

RHR and

REC heat exchanger test results

Selected Service Water System, Reactor Equipment Cooling Water, and Heat ExchangerProgram monthly health reportsSelf-Assessment

SA -03-034, "Heat Exchanger Generic Letter 89-13 Program,"dated September 11, 2003Engineering Evaluation 03-003, "Reconstitute and define the basis of the Service Water PumpDischarge Strainers

SW-STNR-A, -B with respect to impact of debris size on any affected

SW components during Zurn Strainer bypass," Revisions 0 and 2Classification Evaluation Package 97-0001, "SW &

RHRSW Booster System Design CriteriaDocument (

DCD -3)" dated January 1,

1997TCC 4491055, "Installation of Safety Cages Around the

SW Pump Suctions During theCleaning of E-Bay" Vendor Manual 66-31-74, RHR Heat Exchangers

Vendor Manual 68-28-1, Turbine Building and Reactor Building Heat ExchangersSection 1R08: Inservice Inspection Activities (71111.08)ProceduresNumberTitleRevision54-ISI-837-08Ultrasonic Through Wall Sizing of Piping Welds854-ISI-835-10Ultrasonic Examination of Ferritic Piping Welds10

54-ISI-836-10Ultrasonic Examination of Austenitic Piping Welds10

54-ISI-270-44Wet or Dry Magnetic Particle Examination44

54-ISI-147-01Ultrasonic Examination of Thickness Measurement Using Pulse-Echo Techniques154-ISI-135-08Linearity and Beam Spread Measurements8

AttachmentA-754-ISI-136-04Procedure for the Ultrasonic Examination of Vessels Not Greaterthan 2.0 Inches in Thickness454-ISI-30-04Written Practice for the qualification and Certification of

NDEP ersonnel454-

ISI-363-03Remote Underwater In-Vessel Visual Inspection of ReactorPressure Vessel Internals, Components, and Associated

Repairs, in Boiling Water Reactors 354-ISI-366-10VT-1 and

VT -3 Visual Examinations107.2.5.7

CNS Operations Manual - Maintenance Procedure - "ASMECategory F-A Component Supports Examination and

Adjustments14Fourth 10-Year Interval Inservice Inspection Request for ReliefNumberTitleDate R1-15Examination of Peripheral Control Rod Drives02/23/06PR-04System Pressure Test of the Reactor Vessel HeadFlange Lead Detection Line 02/23/06PR-06Buried Portions of Service Water Piping02/23/06Visual ExaminationsReportComponentSummaryVT-F06-007HPCI-MP-SI,

HPCI Main Pump Support

FI. 40.B.004VT-F06-006HPCI-BP-SI,

HPCI Booster Pump Support

FI. 40.B.003

VT -F06-024

MSH -157A, Main Steam Sway StrutFI.20.A.0046

VT -F06-003

HPH -6, StanchionFI.20.A.0018

VT -F06-005

RFH -41, Rigid BraceFI.20.B.0017

VT -F06-004

HPH -6A, Rod HangerFI.20.A.0019

VT -F06-025

MSH-109, Main Steam Variable SpringFI.20.C.0028Surface ExaminationsReportComponentSummaryMT-F06-001HPID-CC-5, StanchionC3.20.002

AttachmentA-8PT-F06-001CRD-02-31-1,

CRD Housing and Flange WeldB14.10.02-31-1

PT -F06-002CRD-02-27-1, CRD Housing and Flange WeldB14.10.02-27-1

MT -F06-004

PSA -BKI-19, Constant SupportB10.20.0030

MT -F06-005

RHC -BKI-24, StanchionB10.20.0060Volumetric ExaminationsReportComponentSummaryUT-F06-095RHR-CA-1A,

CI. 20.0001UT-F06-096RHR-CA-1A,

CI. 20.0001UT-F06-097RHR-CA-1A,

CI. 20.0001UT-F06-098RHR-CA-1A,

CI. 20.0001UT-F06-122MSC-BJ-35X, Main Steam Elbow to PipeB9.11.0093.RIUT-F06-123MSC-BJ-35X, Main Steam Elbow to PipeB9.11.0093.RICondition ReportsCR-CNS-2005-02834CR-CNS-2005-02847

CNS -2005-05011CR-CNS-2005-08270CR-CNS-2005-08274

CNS -2006-01443CR-CNS-2006-02418CR-CNS-2006-04760

CNS -2006-07197

CNS -2006-07790

CNS -2006-07863

2OS 1: Access Controls to Radiologically Significant Areas (71121.01)Condition Reports

CNS -2006-08253Section

CR -CNS-2005-6632CR-CNS-2006-0297CR-CNS-2006-1066CR-CNS-2006-1439CR-CNS-2006-3741CR-CNS-2006-4003CR-CNS-2006-4057CR-CNS-2006-4067

CNS -2006-6111CR-CNS-2006-6972CR-CNS-2006-7727CR-CNS-2006-7765

CNS -2006-7795CR-CNS-2006-7820CR-CNS-2006-7829CR-CNS-2006-7985

IRM Dry Tube Removal andInstallation2383A5614Procedure for bending low power range monitors19

CNS-2006-8076CR-CNS-2006-8134CR-CNS-2006-8310

AttachmentA-9ProceduresNumberTitleRevision2.1.20.3RPV Refueling Preparation (Wet Lift of Dryer andSeparator)172.0.1.1Conduct of Infrequently Performed Tests orEvolutions410.29LPRM and

SRM /

RADOP 1Radiation Protection at

CNS 4

RAD [[]]

OP 3Area Posting and Access Control22

RADOP 5Airborne radioactivity Sampling17Section 2

OS 2:

ALARA Planning and Controls (71121.02)Condition Reports

CR -CNS-2006-0297CR-CNS-2006-1066CR-CNS-2006-1429CR-CNS-2006-1439CR-CNS-2006-3741CR-CNS-2006-4003CR-CNS-2006-4057CR-CNS-2006-4067