IR 05000298/2006005

IR 05000298-06-005; 09/24/06 - 12/31/06; Cooper Nuclear Station. Licensed Operator Requal, Postmaintenance Testing, Refuel Outages, Surv. Testing, Access Controls to Rad. Significant Areas, Identification & Resolution of Problems, Event Fol

ML070360639
Person / Time
Site:	Cooper
Issue date:	02/02/2007
From:	Hay M NRC/RGN-IV/DRP/RPB-C
To:	Minahan S Nebraska Public Power District (NPPD)
References
IR-06-005
Download: ML070360639 (61)

Text

February 2, 2007

SUBJECT:

COOPER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000298/2006005

Dear Mr. Edington:

On December 31, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Cooper Nuclear Station. The enclosed integrated inspection report documents the inspection findings which were discussed on January 9, 2006, with you and other members of your staff.

This inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, nine findings were evaluated under the risk significance determination process as having very low safety significance (Green). Eight of these findings were determined to be violations of NRC requirements. However, because these violations were of very low safety significance and the issues were entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with Section VI.A.1 of the NRCs Enforcement Policy. These noncited violations are described in the subject inspection report. If you contest the violations or significance of the violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Cooper Nuclear Station facility.

In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, its enclosure, and your response will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Nebraska Public Power District

- 2 -

Should you have any questions concerning this inspection, we will be pleased to discuss them with you.

Sincerely,

/RA/

Michael C. Hay, Chief Project Branch C Division of Reactor Projects Docket: 50-298 License: DPR-46

Enclosure:

NRC Inspection Report 05000298/2006005 w/attachment: Supplemental Information

REGION IV==

Docket:

50-298 License:

DPR-46 Report:

05000298/2006005 Licensee:

Nebraska Public Power District Facility:

Cooper Nuclear Station Location:

P.O. Box 98 Brownville, Nebraska Dates:

September 24 through December 31, 2006 Inspectors:

S. Schwind, Senior Resident Inspector N. Taylor, Resident Inspector J. Drake, Operations Engineer G. Guerra, Health Physicist, Plant Support Branch R. Kopriva, Senior Reactor Inspector, Engineering Branch 1 G. Pick, Senior Reactor Inspector, Engineering Branch 2 B. Tharakan, Health Physicist, Plant Support Branch W. Walker, Senior Project Engineer Accompanying Personnel:

D. Bollock, Project Engineer C. Huffman, Nuclear Safety Professional Development Program Approved By:

Michael C. Hay, Chief, Project Branch C, Division of Reactor Projects

Enclosure-2-

SUMMARY OF FINDINGS

IR 05000298/2006005; 09/24/2006 - 12/31/06; Cooper Nuclear Station. Licensed Operator

Requalification, Postmaintenance Testing, Refueling Outages, Surveillance Testing, Access Controls to Radiologically Significant Areas, Identification and Resolution of Problems, Event Followup, Other Activities.

The report covered a 3-month period of inspection by resident inspectors and Region-based inspectors. Eight Green, noncited violations and one Green Finding were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 3, dated July 2000.

Cornerstone: Mitigating Systems

Green.

The inspector identified a noncited violation of 10 CFR 55.21, Medical Examination, and 10 CFR 55.23, Certification. The inspector identified that the licensee failed to conduct all the medical testing required by American Nuclear Standards Institute/American Nuclear Society 3.4 -1983, Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants, as committed to by the facility licensee. Specifically, the licensee was not testing its operators for nose sensitivity (i.e., ability to detect odor of products of combustion and of tracer or market gases), Section 5.4.2, Nose. Once identified, the licensee implemented immediate corrective actions to medically test all operators prior to returning to on-shift duties.

This finding was more than minor because the inadequate medical examinations could result in potential consequences due to licensed operators who may not be medically qualified to perform licensed duties and could, therefore, potentially affect the health and safety of the public. The finding was also of very low safety significance because no actual consequences were noted due to adverse medical conditions. In addition, no adverse operational events were observed to have occurred due to inadequate medical conditions or missed medical tests. 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 procedure, American National Standards Institute 3.4-1983, were met. (Section 1R11.1)

Green.

A self-revealing, noncited violation of Technical Specification 5.4.1.a was identified regarding the licensee's failure to follow procedures for maintenance affecting the performance of safety-related equipment. Work Order 4514076 provided instructions to instrumentation and control technicians to connect a digital recorder to the Emergency Diesel Generator 2 voltage regulator. Contrary to the instructions in the work order, the technicians connected additional test equipment, resulting in damage to Emergency Diesel Generator 2. The licensee entered this into their corrective action program as Condition Report CR-CNS-2006-08999.

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. Using the NRC Manual Chapter 0609,

Appendix GProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>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 of human performance given that the licensees 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 was identified for the licensees 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 CR-CNS-2006-07490.

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. 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 10 CFR Part 50, Appendix B,

Criterion XVI, was identified regarding the licensees 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 CR-CNS-2006-08821.

The finding affected the Mitigating Systems cornerstone and is more than minor because, 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 4OA2.1)

Green.

A self-revealing, noncited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, was identified regarding the licensees 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 CR-CNS-2006-08226.

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 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 to identify this issue in a timely manner. (Section 4OA2.1)

Green.

A self-revealing finding was identified regarding the failure to install heat trace on 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 CR-CNS-2006-09006.

The 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 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

A

Green.

The NRC identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, involving the licensees 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 the past five operating cycles without being evaluated for its potential impact on safety-related equipment. The licensee documented the condition in Condition Report CR-CNS-2006-09338.

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 breach of containment. This finding has a crosscutting aspect in the area of problem 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.a regarding 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 CR-CNS-2006-07255.

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 the licensee did 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 Technical Specification 5.4.1.a involving the licensees procedure for reactor pressure vessel refueling preparation was not adequate. The licensees 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 disconnect from the reactor pressure vessel vent. The loss of this connection released activation products onto the refuel floor and created an airborne radioactivity area, which alarmed the continuous air monitor and contaminated five workers. The licensees 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 Radiation Safety cornerstone attribute of Program and Process, and it affects the cornerstone objective to ensure the adequate protection of a workers 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 human performance 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)

Licensee Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and correction action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period at essentially full reactor power in coastdown to Refueling 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 15 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.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather

a. Inspection Scope

The inspectors completed a review of the licensee's readiness for seasonal susceptibilities 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 and Restoration, Revision 5

• General Operating Procedure 2.1.14, Seasonal Weather Preparations, Revision 8 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

Partial System Walkdowns

a. Inspection Scope

The inspectors:

(1) walked down portions of the two risk important systems listed below and 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 the station startup service transformer

• December 11, 2006: Service Water (SW) Loop A while Loop B was inoperable for planned maintenance Documents 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 90 The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors walked down the six plant areas listed below to assess the material condition 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 for degraded or inoperable fire protection features and that the compensatory measures were commensurate with the significance of the deficiency; and

(7) reviewed the CAP to determine if the licensee identified and corrected fire protection problems.

C September 29, 2006: Fire Zone 3A, 4160V Bus 1F Room C

September 29, 2006: Fire Zone 3b, 4160V Bus 1G Room C

November 1, 2006: Fire Zone 20A, Service Water Pump Room C

November 11, 2006: Fire Zone 5A, Reactor Building 976 East C

December 8, 2006: Fire Zone 14A, EDG 1 Room C

December 8, 2006: Fire Zone 14B, EDG 2 Room Documents reviewed by the inspectors included:

C CNS Fire Hazards Analysis Report, June 20, 2002 The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R07 Biennial Heat Sink Performance

a. Inspection Scope

The inspectors reviewed design documents (e.g., calculations and performance specifications), 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, the inspectors 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 water system, 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 following requirements:

(1) macrofouling controls,

(2) biotic fouling controls, and

(3) performance tests for pumps and valves.

If available, the inspectors reviewed additional nondestructive examination (NDE) results for the selected heat exchangers that demonstrated structural integrity.

The inspectors selected heat exchangers that ranked high in the plant-specific risk assessment 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 exchanger Division II reactor equipment cooling (REC) heat exchanger Turbine equipment cooling heat exchangers The inspector completed three of the required two to three samples.

b. Findings

No findings of significance were identified.

==1R08 Inservice Inspection Activities

==

.1 Performance of NDE Activities

a. Inspection Scope

Procedure 71111.08 requires the review of five NDE activities of at least two or three different 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 examinations were performed in accordance with American Society of Mechanical Engineers (ASME)

Code requirements.

During the review of each examination, the inspector verified that appropriate NDE procedures 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 personnel observed performing examinations or identified during review of completed examination packages.

The inspection procedure requires review of one or two examinations from the previous outage with recordable indications that were accepted for continued service to ensure that the disposition was done in accordance with the ASME 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 end of 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 repairs or 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 fourth 10-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 licensees compliance to the relief request response.

The inspector completed the minimum one sample for this inspection.

b. Findings

No findings of significance were identified.

.2 Identification and Resolution of Problems

a. Inspection Scope

The inspector reviewed selected inservice inspection related condition reports issued during the current and past refueling outages. The review served to verify that the licensees 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. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

.1 Quarterly Requalification Activities

a. Inspection Scope

The inspectors observed testing and training of senior reactor operators and reactor operators in the simulator on October 2, 2006, to verify adequacy of the training, to assess operator performance, and to assess the evaluator's critique. The inspectors observed a simulator scenario involving a failure of the main turbine hydraulic control system. Documents reviewed by the inspectors included:

C Lesson Plan SKL051-51-49, Loss of Main Generator Cooling and Failure of the Digital-Electrohydraulic Control System The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Licensed Operator Requalification

Biennial Inspection

a. Inspection Scope

The inspectors:

(1) evaluated examination security measures and procedures for compliance with 10 CFR 55.49;

(2) evaluated the licensees 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, two instructors/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 which involved 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 licensees 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 NUREG 1021, "Operator Licensing Examination Standards for Power Reactors," Revision 9, and NRC Manual Chapter 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 ANSI/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 NUREG 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. Findings

Introduction:

The inspector identified a Green, noncited violation (NCV) of 10 CFR 55.21, Medical Examination, and 10 CFR 55.23, Certification, involving the failure to conduct all the medical testing required by ANSI/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 programmatic deficiency had existed at the Cooper Nuclear Station, whereby the licensees medical physician was not adequately testing all licensed operators (both initial and renewal licensees) in accordance with 10 CFR 55.21 and 55.23 with respect to ANSI/ANS 3.4-1983. Specifically, certain medical conditions identified by the inspector in the licensed operators medical records led to the identification that a medical test required to be conducted in accordance with ANSI/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 the licensee. 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.

C The medical physicians who performed these medical evaluations were given additional training on the requirements of ANSI/ANS 3.4-1983.

C The contracts between the medical facility and the utility were altered to specifically require a review against the ANSI standard.

C The administrative procedure governing the medical reporting process was revised, including the development of a comprehensive medical checklist.

C The Cooper Nuclear Station medical records were audited to identify any additional problems with medical conditions that were not reported to the NRC.

C The licensee implemented immediate corrective action to conduct the missed test on all operators before they were allowed back on-shift.

The missed medical test was conducted using a scratch and sniff card to verify that licensed 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 the guidance 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, ANSI 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 CFR Part 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 ANSI/ANS 3.4-1983 as the way they would meet Part 55.46 (d)(1). ANSI/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 the public health and safety. The specific health requirements and disqualifying conditions are described in Section 5.3, Disqualifying Conditions, and Section 5.4, Specific Minimum Capacities Required for Medical Qualifications, of the ANSI standard. However, on August 9, 2006, prompted by the inspectors assessment regarding the inadequacy of the facility licensees medical examinations, the licensee conducted reviews of all medical examinations and records and found that certain tests in accordance with ANSI/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 ANSI/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 of 10 CFR 55.21 and 55.23. Because of the very low safety significance, this violation is being treated as an NCV (05000298/2006005-01) consistent with Section VI.A.1 of the NRC Enforcement Policy. This issue was in the licensees corrective action program as CR-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.

==1R12 Maintenance Rule (711111.12Q)

a. Inspection Scope

==

The inspectors reviewed the maintenance effectiveness performance issues listed below to:

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

C Condition Report CR-CNS-2006-07365, Reactor Recirculation Motor Generator Undemanded Speed Change C

Condition Report CR-CNS-2006-05981, Torus Drain Valve to Sump B (RW-AOV-768AV) Stuck Shut C

Condition Report CR-CNS-2006-08190, RHR Loop B Injection Valve (RHR-MOV-MO25B) Failed to Open The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

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.

C September 29, 2006: Work Order (WO) 4451770 for planned maintenance on the station startup service transformer C

October 23, 2006: WO 4511138 for replacement of Switchyard Breaker 3306 (Booneville 345 KV Breaker)

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

For the following equipment performance issue, the inspectors:

(1) reviewed plant status 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 UFSAR 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 TSs;

(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.

C Condition Report CR-CNS-2006-07083, EDG Tachometers Improperly Grounded The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors selected four postmaintenance tests associated with the maintenance activities listed below for risk significant systems or components. For each item, the inspectors:

(1) reviewed the applicable licensing basis and/or design basis documents to 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 UFSAR to determine if the licensee identified and corrected problems related to postmaintenance testing.

• October 25, 2006: WO 4296299 for replacement of the Division 1 250 volt battery

• November 1, 2006: WO 4528348 for a modification to allow the reactor water cleanup 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 high pressure coolant injection (HPCI) system The inspectors completed four samples.

b. Findings

Introduction:

A self-revealing, Green NCV of TS 5.4.1.a was identified regarding the licensee'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 testing following 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. The technicians 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 to the recorder. The technician immediately realized that he had energized the voltage regulator 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 exceeded 5000 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 regulators 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 of these 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 the licensee'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 the licensees 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 safety significance and has been entered into the licensee's CAP as Condition Report CR-CNS-2006-08999, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000528/2006005-02, "Failure to Follow Work Instructions."

==1R20 Refueling Outages (7111.20)

a. Inspection Scope

==

The inspectors reviewed the following risk significant refueling items or outage activities to 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. Findings

Introduction:

The inspectors identified a Green NCV regarding the failure to promptly identify 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 inspectors identified 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 tour about 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 again questioned licensee management regarding the condition; however, the licensee was unable to demonstrate the acceptability of the trolley/hoist. They identified that the trolley/hoist and chain had probably been in the torus for at least five operating cycles without 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 CR-CNS-2006-09338, the licensee 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 to promptly 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 and resolution 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:

10 CFR Part 50, Appendix B, Criterion XVI, requires that measures shall be 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 CAP as Condition Report CR-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.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that the 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 ASME 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 Operated Valve Operability Test (IST)(DIV 2), Revision 19

• October 25, 2006: Surveillance Procedure 6.PC.513, Main Steam Local Leak Rate Tests, Revision 13

• November 9, 2006: Surveillance Procedure 6.2DG.302, Undervoltage Logic Functional, Load Shedding, and Sequential Loading Test (DIV 2), Revision 33

• November 14, 2006: Surveillance Procedure 6.MISC.501, ECCS Leakage Walkdown, Revision 5 The inspectors completed four samples.

b. Findings

Introduction:

A Green, self-revealing NCV was identified regarding inadequate maintenance procedures for work on safety-related motor-operated valves (MOVs).

Description:

On October 17, 2006, the Division 2 low pressure coolant injection (LPCI)inboard injection valve, RHR-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 LPCI system. It is also required to establish shutdown cooling using the Division 2 RHR pumps. Based on the failed surveillance test, the licensee declared Division 2 of 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 freely without moving the valve. The licensee implemented immediate corrective actions to 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 that prevents 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 RHR-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.

RHR-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 CR-CNS-2006-07490 and performed 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:

Valve Function Inspection As-Found Condition CS-MOV-MO7B Core Spray (CS) A Torus Suction Not Functional Pinion key broken due to incorrect material RHR-MOV-MO27A RHR Loop A Injection Outboard Isolation Not Functional Pinion and key migrated 9/16" off motor shaft. Set-screw was loose RHR-MOV-31B Drywell Spray A Inboard Isolation Unsat Key migrated 1/16" out of key-way, set-screw not landed in dimple HPCI-MOV-MO15 High Pressure Coolant Injection Steam Supply Inboard Isolation Unsat Key migrated 1/4" out of key-way, pinion migrated 1/8" off motor shaft, set-screw not tight CS-MOV-MO12B CS Pump B Injection Unsat Key migrated 1/2" out of key-way, set-screw high in lock-wire groove (not landed in dimple)

RHR-MOV-MO39A RHR Torus Cooling Loop A Outboard Throttle Unsat Key migrated 1/2" out of key-way, set-screw not landed in dimple.

Valve Function Inspection As-Found Condition RR-MOV-MO53A Reactor Recirculation Pump A Discharge Unsat Key migrated 3/8" out of key-way, pinion showed axial movement RR-MOV-MO53B Reactor Recirculation Pump B Discharge Unsat Key migrated 3/8" out of key-way, pinion migrated 1/16" off motor shaft RHR-MOV-MO27B RHR Loop B Injection Outboard Isolation Unsat Pinion migrated 1/2" off motor shaft, set-screw not landed in dimple RHR-MOV-MO34B RHR Torus Cooling Loop B Inboard Throttle Unsat Pinion migrated 1/2" off motor shaft, set-screw not landed in dimple After completing these inspections, the licensee concluded that the root cause for these conditions 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 licensees root cause analysis, the applicable maintenance procedures, and industry operating experience regarding similar MOV failures. Based on their review, the inspectors concluded that, while the licensees 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 maintenance procedures, 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.

The inspectors also concluded that the licensees MOV program was not effective in identifying 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 the licensees 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 RHR-MOV-MO25B, which rendered Division 2 of the LPCI system inoperable. While other degraded conditions resulted from this performance deficiency, Division 2 of LPCI 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 LPCI 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 LPCI was unavailable for 92 days. Additionally, a credit of 1 was used for operator recovery of a failed train since Valve RHR-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:

TS 5.4.1.a requires that written procedures be established, implemented, and maintained 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. Contrary to this, Maintenance Procedure 7.2.50.16, 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 RHR-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 licensees CAP as Condition Report CR-CNS-2006-07490, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000298/2006005-04, "Inadequate Maintenance Procedure Results in Safety-Related Valve Failure.

1EP6 Drill Evaluation

a. Inspection Scope

The 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, 2006 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety (OS)

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess licensee performance in implementing physical and administrative 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 licensees procedures required by TS as criteria for determining compliance. During the inspection, the inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors performed independent radiation dose rate measurements and reviewed the following items:

Performance indicator (PI) events and associated documentation packages reported by the licensee in the Occupational Radiation Safety cornerstone Controls (surveys, posting, and barricades) of three radiation, high radiation, or airborne radioactivity areas Radiation work permits, procedures, engineering controls, and air sampler locations Conformity of electronic personal dosimeter alarm setpoints with survey indications and plant policy; workers knowledge of required actions when their electronic personnel dosimeter noticeably malfunctions or alarms Barrier integrity and performance of engineering controls in airborne radioactivity areas Adequacy of the licensees internal dose assessment for any actual internal exposure greater than 50 millirem Committed Effective Dose Equivalent Physical 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 last inspection; there were no licensee event reports (LERs) and special reports Corrective 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 job coverage, 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 and very high radiation areas Controls for special areas that have the potential to become very high radiation areas during certain plant operations Posting and locking of entrances to all accessible high dose rate - high radiation areas and very high radiation areas Radiation worker and radiation protection technician performance with respect to radiation protection work requirements The inspectors completed 21 of the required 21 samples.

b. Findings

Inadequate Procedure for Reactor Pressure Vessel (RPV) Refueling Preparation

Introduction:

The inspectors reviewed a self-revealing NCV of Technical Specification 5.4.1.a that occurred because the licensees 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 hose between 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 licensees 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 HEPA 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 HEPA hose caused it to disconnect from the RPV vent. The licensees 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 be a 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 workers 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 licensees ability to assess dose. Additionally, this finding had a crosscutting aspect in the area of human performance 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.

Enforcement:

TS 5.4.1.a requires written procedures be established, implemented, and maintained 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 licensees 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.

2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspectors assessed licensee performance with respect to maintaining individual and collective radiation exposures ALARA. The inspectors used the requirements in 10 CFR Part 20 and the licensees 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 and associated work activity exposure estimates which were likely to result in the highest personnel collective exposures Site-specific trends in collective exposures, plant historical data, and source-term measurements Site-specific ALARA procedures ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements Use of engineering controls to achieve dose reductions and dose reduction benefits afforded by shielding Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas Self-assessments, audits, and special reports related to the ALARA program since the last inspection Effectiveness of self-assessment activities with respect to identifying and addressing repetitive deficiencies or significant individual deficiencies The inspectors completed 10 of the required 15 samples.

b. Findings

No findings of significance were identified.

4OA1 PI Verification

a. Inspection Scope

Occupational Radiation Safety Cornerstone Occupational Exposure Control Effectiveness The inspectors reviewed licensee documents from August 1, 2005, through September 30, 2006. The review included corrective action documentation that identified occurrences in locked high radiation areas (as defined in the licensees 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 ALARA 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 were properly 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 Cornerstone Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences The inspectors reviewed licensee documents from August 1, 2005, through September 30, 2006. Licensee records reviewed included corrective action documentation that identified occurrences for liquid or gaseous effluent releases that exceeded PI thresholds and those reported to the NRC. The inspectors interviewed licensee 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 Cornerstone The PIs 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 4OA5.2.

The inspectors completed five samples.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Selected Issue Follow-up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the issues listed below for a more 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.

C Condition Report CR-CNS-2006-08226, Failure of Service Water Discharge Strainer A C

Condition Report CR-CNS-2006-08821, HPCI-MOV-MO15 Torque Switch Failure

• Condition Report CR-CNS-2006-07255, Total core flow above 77.175 MLBM/HR

b. Findings

MOV Torque Switch Failure

Introduction:

A self-revealing, Green NCV was identified regarding the failure to correct a condition adverse to quality on safety-related MOVs.

Description:

On November 8, 2006, during diagnostic testing of the HPCI inboard steam isolation 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 HPCI-MOV-MO15 is equipped with a Limitorque SMB-1 motor actuator. This size of 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 applications requiring 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 for applicability to Cooper Nuclear Station. Valve HPCI-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.

No updated information was ever issued and, since the licensee had not seen any failures 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 CR-CNS-2006-08821 and concluded that the Valve HPCI-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 to correct a condition adverse to quality on safety-related MOVs. Specifically, the licensee failed to replace the torque switch in Valve HPCI-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 HPCI-MOV-MO15 failed on November 8, 2006. HPCI 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 HPCI 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:

10 CFR Part 50, Appendix B, Criterion 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 HPCI-MOV-MO15 was subject to failure based on the information in the 10 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 licensees CAP as Condition Report 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 Failure

Introduction:

The inspectors reviewed a self-revealing, Green NCV regarding the failure to correct a condition adverse to quality. This deficiency resulted in failure of Service Water Discharge Strainer A.

Description:

On October 29, 2006, operators discovered that the backwash mechanism on 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 CR-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 CR-CNS-2006-00789, which documented a similar 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 10 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 8 months before the failure.

Analysis:

The performance deficiency associated with this finding involved the failure to identify 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 NCV 05000298/2006002-02 documented in 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 crosscutting area of problem identification and resolution in that the licensee failed to identify this issue in a timely manner.

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 licensees CAP as Condition Report CR-CNS-2006-08226, this violation is being treated as an NCV consistent with Section 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 Limit

Introduction:

The inspectors identified a Green NCV of TS 5.4.1.a regarding 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.

Description:

On October 8, 2006, the licensee initiated Condition Report CR-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 PMIS typer whenever total core flow exceeds 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 RE23.

The inspectors questioned the licensees response to the alarm and the acceptability of operating so close to the UFSAR core flow limit. As a result of the licensees response to the question and the inspectors direct observation of core flow spikes exceeding 77.1 MLBH 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 previous month the plant had been operating above 105 percent rated core flow approximately 10 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 MLBH). 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 CR-CNS-2006-07255 was updated to reflect the procedural violation.

In order to analyze this condition, the licensee contacted the nuclear steam system supply 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 the licensee'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 the licensee did not effectively communicate expectations regarding work practices to operators for the control of key parameters such as total core flow.

Enforcement:

TS 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities specified in 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 CAP as Condition Report CR-CNS-2006-07255, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000528/2006005-08, "Operation of Reactor Above Total Core Flow Limit."

.2 Semiannual Trend Review

a. Inspection Scope

The inspectors completed a semiannual trend review of repetitive or closely related issues 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:

• Personnel contamination events

• Fire door degradation

• Sump pump failures

• Drawing discrepancies

• Crane and hoist failures The inspectors compared their results with the results contained in the licensee's routine trend 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. Findings

No findings of significance were identified.

.3 Radiological Protection Problem Identification and Resolution

a. Inspection Scope

The inspectors evaluated the effectiveness of the licensees problem identification and resolution process with respect to the following inspection areas:

Access Control to Radiologically Significant Areas (Section 2OS1)

ALARA Planning and Controls (Section 2OS2)

b. Findings

No findings of significance were identified.

.4 Heat Sink Performance Problem Identification and Resolution

a. Inspection Scope

The inspectors evaluated several condition reports, including root cause and apparent cause 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 program documents, review of records, and interviews with licensee personnel.

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 Fire in Reactor Building

a. Inspection Scope

The inspectors responded to the plant on November 11, 2006, due to the declaration of a 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 licensees corrective actions.

b. Findings

Introduction:

A Green, self-revealing finding was identified regarding the inadequate design 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 report of 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 NOUE at 5:30 a.m. due to a fire in the protected area lasting longer than 10 minutes. The NOUE 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 the heat 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.

Raychem, the U.S. National Electrical Code, and the Canadian Electrical Code 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 CR-CNS-2006-09006 and performed 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 the licensees 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 system.

Enforcement:

Since 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 Incorrect Pinion Gear Installation in Motor Operator On 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.

4OA5 Other Activities

.1 (Closed) Temporary Instruction 2515/169:

Mitigating Systems Performance Index (MSPI) Verification

a. Inspection Scope

The inspectors sampled licensee data to verify that the licensee correctly implemented the MSPI 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.

1. For the sample selected, did the licensee accurately document the baseline

planned unavailability hours for the MSPI systems?

Not in all cases. The inspectors validated the baseline planned unavailability hours 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 made an 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 CR-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 <br />0.0586 hours <br />3.488757e-4 weeks <br />8.02855e-5 months <br /> 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 MSPI, and as such these hours should not have contributed to the baseline planned unavailability. The licensee plans to correct this discrepancy during a revision to the MSPI Basis Document in the next quarter. The licensee has documented this discrepancy in Condition Report CR-CNS-2006-10488.

2. For the sample selected, did the licensee accurately document the actual

unavailability hours for the MSPI systems?

Not in all cases. The inspectors identified the following examples of inaccurate accounting of system unavailability:

• In the MSPI Basis Document, the licensee excluded Surveillance Procedure 6.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 HPCI as available during the performance of 6.HPCI.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 CR-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 MSPI data. The licensee recognized this human error and documented the discrepancy in Condition Report CR-CNS-2006-10354.

• The inspectors identified that some unavailability hours for the SW system were incorrectly 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 CR-CNS-2006-10336. As a result of the error, the licensee submitted a PI correction data file and determined that the unavailability index contribution to MSPI-SW changed from 5.4E-8 to 1.1E-7 and that the total MSPI-SW changed from 9E-9 to 4.7E-8. The licensee documented this discrepancy in Condition Report CR-CNS-2006-10488.

3. For the sample selected, did the licensee accurately document the actual

unreliability information for each MSPI monitored component?

Not in all cases. The inspectors identified several examples of errors in the calculated unreliability index.

• The inspectors identified a mathematical error in the MSPI Basis Document for the 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 RCIC system. The table documented an estimated demand frequency of 1.3 demands per quarter for the RCIC turbine. The text at the top of the page estimated that the RCIC 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 <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> per quarter (versus 1.3 x

.5 hour

= 0.65 hours7.523148e-4 days <br />0.0181 hours <br />1.074735e-4 weeks <br />2.47325e-5 months <br /> per quarter). This demand estimate is an input into the calculation of the unreliability index component of MSPI. The licensee documented this discrepancy in Condition Report CR-CNS-2006-10488.

• In the tabulation of baseline demands and run hours for SW system components, the licensee used estimated figures based on historical averages (as allowed by NEI 99-02). Paragraph F2.2.1 on page F-19 of 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 MSPI. The licensee has documented this discrepancy in Condition Report CR-CNS-2006-10488.

4. Did the inspector identify significant errors in the reported data, which resulted in

a change to the indicated index color? Describe the actual condition and corrective actions taken by the licensee, including the date when the revised PI information was submitted to the NRC.

No discrepancies were identified in the reported data which resulted in a change to the indicated color.

5. Did the inspector identify significant discrepancies in the Basis Document which

resulted in:

(1) a change to the system boundary;

(2) an addition of a monitored component; or

(3) a change in the reported index color? Describe the actual condition and corrective actions taken by the licensee, including the date of when the Basis Document was revised.

No such issues were identified.

4OA6 Management Meetings

On October 17, 2006, the inspectors conducted a telephonic exit to discuss the results of 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 safety inspection 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 health physics inspectors re-exited the issues identified during the inspection with Mr. D. Oshlo, Radiation Protection Manager, and other members of the licensees staff who acknowledged the findings.

On December 12, 2006, the inspector conducted an exit meeting to present the inspection 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 biennial operator 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 inspection activities 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.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy for being dispositioned as NCVs.

C TS 5.4.1.a requires procedures for activities covered by RG 1.33. The licensees procedure for low power range monitor (LPRM) removal and installation, Nuclear Performance Procedure 10.29, step 2, refers to the vendors procedure for bending the LPRM 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 LPRM, which resulted in one leg of the LPRM being shorter than the other and the irradiated detectors being closer to the surface of the water than expected.

Consequently, when the LPRM 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 LPRM be lowered in the water. At the same time, four electronic dosimeter alarms were received. The workers placed the LPRM 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 ALARA 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 CR-CNS-2006-08134.

C TS 3.5.1 allows one train of emergency core cooling to be inoperable for up to 7 days. Contrary to this, 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 CR-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, and maintained 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 fabricated onsite from material other than 4140 stainless steel. An inspection of the 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 CR-CNS-2006-08917 and replaced the failed key with one made of 4140 stainless steel.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Bahensky, System Engineer

R. 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

NRC

S. Schwind, Senior Resident Inspector

N. Taylor, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000528/2006005-01 NCV Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants

05000298/2006005-02 NCV Failure to Follow Work Instructions

05000298/2006005-03 NCV Failure to Promptly Identify and Correct an Unanalyzed Condition in the Torus

05000298/2006005-04 NCV Inadequate Maintenance Procedure Results in Safety-

Related Valve Failure

05000298/2006005-05 NCV Inadequate Procedure For RPV Refueling Preparation

05000298/2006005-06 NCV Failure to Identify and Correct Nonconforming Conditions in Safety-Related MOVs

05000528/2006005-07 NCV Failure to Identify and Correct Degraded Condition on SW Strainer

05000298/2006005-08 NCV Operation of Reactor Above Total Core Flow Limit

05000298/2006005-09 FIN Failure to Implement Vendor Recommendations Results in a Fire

Closed

05000298/2006-005 LER RHR Loop B Injection Valve Failure due to Incorrect Pinion Gear Installation in Motor Operator