IR 05000305/2004007

IR 05000305-04-007; on 07/01/2004 - 09/30/2004; Kewaunee Nuclear Power Plant; Operability Determinations, Post Maintenance Testing, Event Followup, and Other Activities

ML043070363
Person / Time
Site:	Kewaunee
Issue date:	10/29/2004
From:	Kozak T Division Reactor Projects III
To:	Coutu T Nuclear Management Co
References
IR-04-007
Download: ML043070363 (75)

Text

ber 29, 2004

SUBJECT:

KEWAUNEE NUCLEAR POWER PLANT NRC INTEGRATED INSPECTION REPORT 05000305/2004007

Dear Mr. Coutu:

On September 30, 2004, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Kewaunee Nuclear Power Plant. The enclosed integrated inspection report documents the inspection findings which were discussed on September 29, 2004, with you and other members of your staff.

The 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, there were four NRC-identified and one self-revealed finding of very low safety significance (Green). These findings were determined to involve violations of NRC requirements. However, because these violations were of very low safety significance, non-willful and non-repetitive, and because the violations were entered in your corrective program, the NRC is treating these issues as Non-Cited Violations, in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest the subject or severity of a Non-Cited Violation, 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 III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector Office at the Kewaunee facility. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's 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).

Sincerely,

/RA/

Thomas J. Kozak, Team Leader Technical Support Section Division of Reactor Projects Docket No. 50-305 License No. DPR-43

Enclosure:

Inspection Report 05000305/2004007 w/Attachment: Supplemental Information

REGION III==

Docket No.: 50-305 License No.: DPR-43 Report No.: 05000305/2004007 Licensee: Nuclear Management Company, LLC Facility: Kewaunee Nuclear Power Plant Location: N 490 Highway 42 Kewaunee, WI 54216 Dates: July 1 through September 30, 2004 Inspectors: R. Krsek, Senior Resident Inspector P. Higgins, Resident Inspector M. Bielby, Senior Operations Engineer J. Cameron, Project Engineer L. Haeg, Nuclear Safety Professional/Reactor Engineer P. Lougheed, Senior Engineering Inspector B. Palagi, Senior Operations Engineer (Lead Inspector)

T. Ploski, Senior Emergency Preparedness Inspector F. Ramirez, Reactor Engineer D. Schrum, Reactor Engineer W. Slawinski, Senior Radiation Specialist H. Walker, Senior Engineering Inspector K. Walton, Operations Engineer R. Winter, Reactor Engineer Observers: S. Bakhsh, Nuclear Safety Professional/Radiation Specialist Approved By: T. Kozak, Team Leader Technical Support Section Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000305/2004007; 07/01/2004 - 09/30/2004; Kewaunee Nuclear Power Plant; Operability

Determinations, Post Maintenance Testing, Event Followup, and Other Activities.

This report covers a 3-month period of baseline resident inspection and announced baseline inspections of licensed operator requalification, maintenance effectiveness, emergency preparedness and the radiation protection program. The inspections were conducted by the resident and Region III inspectors. The inspectors also completed Temporary Instruction 2515/159, Review of Generic Letter (GL) 89-13: Service Water System Problems Affecting Safety-Related Equipment. The inspections identified four NRC-identified Green findings associated with four non-cited violations and one self-revealed Green finding associated with one non-cited violation. The significance of most findings is indicated by their color (Green,

White, Yellow, 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 NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

A. Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance was identified by the inspectors for a violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions.

During a review of the licensees list of safety-related equipment designated as degraded or nonconforming, the inspectors identified that the licensee failed to promptly correct three conditions adverse to quality. These conditions adverse to quality included noncompliance of both Residual Heat Removal pump seal coolers with system design requirements, which was previously identified by NRC inspectors in November 2002, but not promptly corrected by the licensee; and two sections of safety-related piping, one associated with the B Emergency Diesel Generator fuel oil supply and the other associated with the Component Cooling Water piping from the B Residual Heat Removal pump seal cooler and stuffing box, that were identified by the licensee in September and April 2003, respectively, as exceeding Updated Safety Analysis Report stress criteria but not promptly corrected by the licensee. The primary cause of this finding was related to the cross-cutting area of problem identification and resolution. The licensee failed to prioritize and promptly correct these conditions adverse to quality in accordance with the guidelines in the corrective action program. Once these conditions were identified, the licensee restored the following conditions to operable: the A RHR Pump Seal Cooler; the CCW piping expansion loop from the B RHR pump seal cooler; and the fuel oil supply piping to the B EDG. The licensee planned to restore the B RHR Pump Seal Cooler during the upcoming Fall 2004 Refueling Outage.

This issue was more than minor because it affected the Mitigating System cornerstone attribute of design control for initial design and plant modifications and affected the associated cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because it was not a design or qualification deficiency that has been confirmed to result in a loss of function per Generic Letter 91-18. This issue was a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions. (Section 1R15.1)

Green.

A finding of very low safety significance was self-revealed during the licensees review of high oil particulate in the Turbine Driven Auxiliary Feedwater Pump Turbine, which resulted in a violation of 10 CFR Part 50, Appendix B,

Criterion V, "Instructions, Procedures, and Drawings." The licensee determined that high oil particulate in the Turbine Driven Auxiliary Feedwater Pump Turbine was caused by damage to the journal bearing. Maintenance procedures did not specify appropriate acceptance criteria for oil sampling, did not specify an appropriate inspection frequency and criteria for the turbine bearings and bearing cavities, and allowed the reuse of bearings in different locations during maintenance of the Turbine, which were not acceptable maintenance practices.

The reuse of the upper inboard bearing in a different location contributed to the journal bearing damage. The licensee took immediate remedial corrective actions to replace the bearings, clean the housing and return the pump to service. In addition, the licensee revised its maintenance procedures to include appropriate instructions for turbine and pump maintenance activities.

This self-revealed finding was more than minor because, if left uncorrected, the issue would have become a more significant safety concern. In addition, it affected the Mitigating Systems attributes of equipment performance reliability and the Mitigating Systems cornerstone objective of ensuring the reliability of systems. The finding was of very low safety significance because it was not a design or qualification deficiency that has been confirmed to result in a loss of function per Generic Letter 91-18. This issue was a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, And Drawings. (Section 4OA3.1)

Green.

A finding of very low safety significance was identified by the inspectors for a violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions,

Procedures, And Drawings. This finding was associated with the licensees failure to implement an appropriate inspection and cleaning procedure containing quantitative or qualitative acceptance criteria for the 1A RHR pump pit Fan Coil Unit to ensure that cleaning was satisfactorily accomplished. Following discovery, the licensee entered the issue into its corrective action program and conducted an immediate operability assessment that determined the involved fan coil units were operable.

This issue was more than minor because it involved the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because it was not a design or qualification deficiency that has been confirmed to result in a loss of function per Generic Letter 91-18. This issue was a Non-Cited Violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, And Drawings.

(Section 4OA5.1b.1)

Green.

A finding of very low safety significance was identified by the inspectors for a violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control."

This finding was associated with the licensees failure to perform a design verification to demonstrate that the diesel generator lube oil cooler service water outlet valve actuators, installed under Design Change 3357, would not result in a failure of the valve stems under conditions in which the valve ball froze nor had the licensee provided sufficient justification to show that valve ball freezing was not credible. Following discovery, the licensee entered the issue into its corrective action program and performed an operability assessment which provided additional justification to demonstrate that the stem failure was considered not credible.

This issue was more than minor because it involved the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was of very low safety significance because it was not a design or qualification deficiency that has been confirmed to result in a loss of function per Generic Letter 91-18.

This issue was a Non-Cited Violation of 10 CFR Part 50, Appendix B,

Criterion III, "Design Control." (Section 4OA5.1b.2)

Cornerstone: Barrier Integrity

Green.

A finding of very low safety significance was identified by the inspectors for a violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions,

Procedures, And Drawings. The licensee conducted corrective maintenance to fix a deficient condition on the containment personnel hatch seal, a safety-related component, under the toolpouch maintenance process rather than with the use of a work request or a work order, contrary to procedural requirements.

The primary cause of this finding was related to the cross-cutting area of human performance. Licensee personnel failed to appropriately implement licensee procedures for conducting work on safety-related components. Once this was identified, the licensee performed an extent of condition evaluation on the work control process and identified that, since July 2002, approximately 14 percent of the work performed under toolpouch maintenance had been performed on safety-related components without a work order. The licensee also implemented a number of corrective actions to ensure work on safety-related equipment is conducted according to procedural requirements.

This issue was more than minor because it affected the Barrier Integrity Cornerstone attribute of reactor containment integrity, and, if left uncorrected, the finding could become a more significant safety concern. The finding was of very low safety significance because it did not represent an actual open pathway in the physical integrity of the reactor containment and none of the work conducted on safety-related equipment without a work order resulted in an operability concern. This issue was a Non-Cited Violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, And Drawings.

(Section 1R19.1)

B. Licensee-Identified Violation Violations of very low safety significance, which 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 the licensees corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

The plant operated at or near full power for most of the inspection period except for brief periods when operators reduced power to facilitate routine tests. In addition, operators reduced reactor power to 99 percent from August 3 through August 12, 2004, to address apparent steam flow anomalies.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the following two systems, completing two inspection procedure samples, to verify that the systems were correctly aligned to perform their design function:

C Emergency Diesel Generator (EDG) Train B and the associated Train B 4160-Volt Distribution System, while the opposite EDG Train was out of service; and C EDG Train A and the associated Train A 4160-Volt Distribution System, while the opposite EDG Train was out of service.

In preparation for the walkdowns, the inspectors reviewed the system lineup checklists, normal operating procedures, abnormal and emergency operating procedures, and system drawings to verify the correct system lineup. During the walkdowns, the inspectors also examined valve positions and electrical power availability to verify that valve and electrical breaker positions were consistent and in accordance with the licensees procedures and design documentation. The inspectors also observed the material condition of the equipment. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Semiannual Walkdown

a. Inspection Scope

The inspectors completely walked down the auxiliary feedwater (AFW) system, completing one inspection procedure sample. At the time of the inspection, the AFW system was aligned for emergency standby readiness. The inspection included a review of licensee procedures for normal, abnormal and emergency system operations.

Other documents reviewed included design drawings, piping & instrument drawings, the degraded equipment log, operations night orders, and system lineup checklists.

The inspectors reviewed open and recently closed maintenance work requests for the AFW system to assess whether the identified work had the potential to adversely affect system operability. In addition, the inspectors reviewed in-process engineering design change requests associated with the AFW system and discussed the current status with licensee personnel.

Finally, the inspectors walkdown of the AFW system included all accessible system piping and valving associated with all three AFW pumps, electrical power supplies, steam supply for the turbine driven AFW pump, local and dedicated control panel switches and controls, and monitoring and alarm systems. The inspectors verified that support systems and devices were functional and properly aligned to perform the respective safety functions. During the walkdown, the inspectors reviewed correct valve and switch positions; appropriate equipment labeling; availability of electrical power; availability of support systems; and verification of outstanding corrective work orders to ensure system or component functions were not adversely impacted.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors performed fire protection walkdowns of the following six plant areas, completing six inspection procedure samples:

• Fire Zone TU-22, Turbine Building-Operating Floor and Mezzanine;

• Fire Zone AX-23B, Auxiliary Building;

• Fire Zone AX-24, Fuel Handling Rooms, All Elevations;

• Fire Zone AX-33, Condensate and Makeup Water Tank Rooms;

• Fire Zone TU-90 and TU-91, EDG 1-A and Diesel Generator 1-A Day Tank Room; and

• Fire Zone TU-95, Dedicated Shutdown Panel and Bus 51 and 52 Room.

During the walkdowns, the inspectors focused on the availability, accessibility, and condition of fire fighting equipment; the control of transient combustibles and ignition sources; and the materiel condition of installed fire barriers. The inspectors selected fire areas for inspection based on the overall contribution to internal fire risk, and the potential to impact equipment that could initiate a plant transient. The inspectors verified that fire response equipment was in the designated location and available for immediate use without obstruction; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and that passive features such as fire doors, dampers, and penetration seals were in satisfactory condition. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors performed an internal flooding inspection in the EDG 1-A room, completing one inspection procedure sample. The inspectors evaluated internal flooding hazards in the room and evaluated flood protection features, such as room doors, door gaps, and room drains, to determine if the features were in satisfactory physical condition, unobstructed, and capable of providing an adequate flood barrier.

The inspectors also reviewed design basis documents and risk analyses to determine plant vulnerabilities and protective features relating to potential flooding sources for this room. Documents reviewed during this inspection are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

.1 Facility Operating History

a. Inspection Scope

The inspectors reviewed the plants operating history from January 2003 through June 2004 to assess whether the Licensed Operator Requalification Training (LORT)program had identified and addressed operator performance deficiencies at the plant.

b. Findings

No findings of significance were identified.

.2 Licensee Requalification Examinations

a. Inspection Scope

The inspectors performed a biennial inspection of the licensees LORT program. The inspectors reviewed the annual requalification operating test and biennial written examination material to evaluate general quality, construction, and difficulty level. The operating examination material reviewed consisted of seven operating tests, each containing two dynamic simulator scenarios and five job performance measures (JPMs).

The biennial written examinations reviewed consisted of two senior reactor operator (SRO) and two reactor operator (RO) examinations. The inspectors reviewed the methodology for developing the examinations, including the LORT program 2-year sample plan, probabilistic risk assessment insights, previously identified operator performance deficiencies, and plant modifications. The inspectors also reviewed the licensees program and assessed the level of examination material duplication during the current year annual examinations as compared to the previous years annual examinations.

b. Findings

No findings of significance were identified.

.3 Licensee Administration of Requalification Examinations

a. Inspection Scope

The inspectors observed the administration of the requalification operating test to assess the licensees effectiveness in conducting the test and to assess the facility evaluators ability to determine adequate performance using objective, measurable performance standards. The inspectors evaluated the performance of one shift crew in parallel with the facility evaluators during two dynamic simulator scenarios. In addition, the inspectors observed licensee evaluators administer several JPMs to various licensed crew members. The inspectors observed the training staff personnel administer the operating test, including pre-examination briefings, observations of operator performance, and individual and crew evaluations after dynamic scenarios.

The inspectors evaluated the ability of the simulator to support the examinations.

A specific evaluation of simulator performance was conducted and documented under Section 1R11.8, Conformance With Simulator Requirements Specified in 10 CFR 55.46, of this report. The inspectors also reviewed the licensees overall examination security program.

b. Findings

No findings of significance were identified.

.4 Examination Security

a. Inspection Scope

The inspectors observed and reviewed the licensees overall licensed operator requalification examination security program related to examination physical security (e.g., access restrictions and simulator considerations) and integrity (e.g., predictability and bias). The inspectors also reviewed the facility licensees examination security procedure, and the implementation of security and integrity measures (e.g., security agreements, sampling criteria, bank use, and test item repetition) throughout the examination process.

b. Findings

No findings of significance were identified.

.5 Licensee Training Feedback System

a. Inspection Scope

The inspectors assessed the methods and effectiveness of the licensees processes for revising and maintaining its LORT program up to date, including the use of feedback from plant events and industry experience information. The inspectors reviewed the licensees quality assurance oversight activities, including licensee training department self-assessment reports. The inspectors evaluated the licensees ability to assess the effectiveness of its LORT program and its ability to implement appropriate corrective actions.

b. Findings

No findings of significance were identified.

.6 Licensee Remedial Training Program

a. Inspection Scope

The inspectors assessed the adequacy and effectiveness of the remedial training conducted since the previous annual requalification examinations and the training planned for the current examination cycle to ensure that they addressed weaknesses in licensed operator or crew performance identified during training and plant operations.

The inspectors reviewed remedial training procedures and individual remedial training plans.

b. Findings

No findings of significance were identified.

.7 Conformance With Operator License Conditions

a. Inspection Scope

The inspectors reviewed the facility and individual operator licensees' conformance with the requirements of 10 CFR Part 55. The inspectors reviewed the facility licensees program for maintaining active operator licenses and to assess compliance with 10 CFR 55.53

(e) and (f). The inspectors reviewed the procedural guidance and the process for tracking on-shift hours for licensed operators and which control room positions were granted credit for maintaining active operator licenses. In addition, the inspectors reviewed the facility licensees LORT program to assess compliance with the requalification program requirements as described by 10 CFR 55.59 (c).

b. Findings

No findings of significance were identified.

.8 Conformance With Simulator Requirements Specified in 10 CFR 55.46

a. Inspection Scope

The inspectors assessed the adequacy of the licensees simulation facility (simulator) for use in operator licensing examinations and for satisfying experience requirements as prescribed in 10 CFR 55.46, Simulation Facilities. The inspectors also reviewed a sample of simulator performance test records (i.e., transient tests, scenario test and discrepancy resolution validation test), simulator discrepancy and modification records, and the process for ensuring continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The inspectors reviewed and evaluated the discrepancy process to ensure that simulator fidelity was maintained. Open simulator discrepancies were reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59 operator actions as well as on nuclear and thermal hydraulic operating characteristics. The inspectors interviewed members of the licensees simulator staff regarding the configuration control process and completed the NRC Inspection Procedure 71111.11, Appendix C, checklist to evaluate whether the licensees plant-referenced simulator operated adequately as required by 10 CFR 55.46

(c) and (d).

b. Findings

No findings of significance were identified.

.9 Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the pass/fail results of individual written tests administered in 2003, and the operating and simulator tests (required to be given per 10 CFR 55.59(a)(2)) administered by the licensee during calender year 2004. Calendar year 2004 was the first year of the current 2-year training program; therefore, no biennial comprehensive written examination was administered. This represents one inspection procedure sample. The overall written examination and operating test results were compared with the significance determination process in accordance with NRC Manual Chapter 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process.

b. Findings

No findings of significance were identified.

.10 Resident Inspector Quarterly Observation of Licensed Operator Requalification

a. Inspection Scope

The inspectors observed licensee training personnel evaluate an operating crew during an accident scenario and subsequently observed the operating crew critique their performance. The inspectors observed the crew and verified the following attributes of crew performance: communications, alarm response, emergency operating procedure usage, component operations and emergency plan classifications. The inspectors reviewed the scenario for operational validity and risk significance. The inspectors discussed scenario observations and crew evaluations with the licensee trainers. In addition, the inspectors reviewed the licensees baseline fidelity study to ensure that differences between the simulator and actual control room board configuration were maintained as close as possible. This constitutes one quarterly inspection procedure sample. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Maintenance Effectiveness Periodic Evaluation

a. Inspection Scope

To evaluate the effectiveness of the licensees (a)(1) and (a)(2) activities within the Maintenance Rule (10 CFR 50.65), the inspectors examined a number of Kewaunee (a)(1) Action Plans, Functional Failures Evaluations, Apparent Cause Evaluations (ACEs), Corrective Action Process (CAPs) Evaluations, and maintenance rule program documents. The inspectors examined the periodic evaluation reports completed for the time periods of January 1, 2002 through December 31, 2002, and January 1, 2003 through December 31, 2003. The inspectors reviewed these documents to verify that the threshold for identification of problems was at an appropriate level and the associated corrective actions were appropriate. The inspectors focused the inspection on the following four systems, completing four biennial inspection procedure samples:

• Component Cooling Water;

• Emergency Diesel Generator;

• Residual Heat Removal; and

• Auxiliary Feedwater.

The inspectors verified that the periodic evaluation was completed within the time restraints defined in 10 CFR 50.65 (i.e., once per refueling cycle, not to exceed 2 years).

The inspectors also ensured that the licensee reviewed its goals, monitored Structures, Systems, and Components (SSCs) performance, reviewed industry operating experience, and made appropriate adjustments to the maintenance rule program as a result of the above activities.

The inspectors verified that the licensee balanced reliability and unavailability during the previous refueling cycle, including a review of safety significant SSCs.

The inspectors verified that (a)(1) goals were met, that corrective action was appropriate to correct the defective condition, including the use of industry operating experience, and that (a)(1) activities and related goals were adjusted as needed.

The inspector verified that the licensee had established (a)(2) performance criteria, examined any SSCs that failed to meet their performance criteria, and reviewed any SSCs that were subject to repeated maintenance preventable functional failures, including a verification that failed SSCs were considered for (a)(1).

In addition, the inspectors reviewed maintenance rule self-assessments that addressed the maintenance rule program implementation.

b. Findings

No findings of significance were identified.

.2 Additional Evaluations Reviewed

a. Inspection Scope

The inspectors reviewed the licensees implementation of the Maintenance Rule (10 CFR 50.65) for the systems listed below, completing three inspection procedure samples:

• System 02 - Service Water;

• System 25 - Control Room Air Conditioning; and

• System 38 - Direct Current Supply and Distribution.

The inspectors verified that the licensee identified, entered, and scoped component and equipment failures within the maintenance rule requirements. The inspectors also verified that the systems and equipment were properly categorized and classified as (a)(1) or (a)(2) in accordance with 10 CFR 50.65. The inspectors reviewed a sample of station logs, maintenance work orders, maintenance rule evaluations, unavailability records, and a sample of condition reports to verify that the licensee identified issues related to the maintenance rule at an appropriate threshold and that corrective actions were appropriate. Additionally, the inspectors reviewed the licensees performance criteria to verify that the criteria adequately monitored equipment performance.

Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessment and Emergent Work Evaluation

a. Inspection Scope

The inspectors reviewed the licensees evaluation and assessment of plant risk, scheduling, and configuration control during the following planned and emergent work activities, completing four inspection procedure samples:

• Safety Monitor Risk Assessment for July 6 through 9, 2004;

• Safety Monitor Risk Assessment for July 26 through 30, 2004;

• Safety Monitor Risk Assessment for August 9 through 13, 2004; and

• Safety Monitor Risk Assessment for August 23 through 27, 2004.

In particular, the inspectors evaluated the licensees planning and management of maintenance and verified that shutdown and on-line risk was acceptable and monitored in accordance with the requirements of 10 CFR 50.65(a)(4). Additionally, the inspectors compared the assessed risk configuration against the actual plant conditions and any in-progress evolutions or external events to verify that the assessment was accurate, complete, and appropriate. The inspectors also reviewed licensee actions to address increased shutdown and on-line risk during these periods to verify that the actions were in accordance with approved administrative procedures. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R14 Personnel Performance During Non-Routine Plant Evolutions

.1 Operator Response to Increasing A Reactor Coolant Pump Motor Lower Bearing

Temperature Indication

a. Inspection Scope

On July 19, 2004, the inspectors observed the licensees response to the Reactor Coolant Pump A motor lower radial bearing temperature increase. The inspectors observed operator procedure use and adherence, communications, control of equipment, and response to the alarm. In addition, the inspectors observed the licensees overall response to the increased temperature indication, including planning for the licensees troubleshooting process. This observation constituted one inspection procedure sample.

b. Findings

No findings of significance were identified.

.2 Operator Response to Anomalous Increase in Steam Flow from the Steam Generators

a. Inspection Scope

On August 3, 2004, the inspectors observed the operators decrease reactor power to approximately 99 percent, in response to the discovery of a slight increase in steam flow while feedwater flow remained constant. The inspectors also observed the licensees troubleshooting activities and investigation to determine the cause of the increase in steam flow from August 3 through August 12, 2004, when the cause was discovered and reactor power returned to 100 percent. This observation constituted one inspection sample.

b. Findings

No findings of significance were identified.

.3 Freeze Seal Installation for Residual Heat Removal Pump Seal Cooler Replacement

a. Inspection Scope

On September 2, 2004, the inspectors observed operations department pre-job briefs and contingency planning for the installation of a freeze seal on the A Residual Heat Removal Pump seal cooler piping. The inspectors also observed portions of the freeze seal application and communications with control room operators during the freeze seal evolution. The installation of the freeze seal for maintenance activities was a first time evolution for the licensee. This observation constituted one inspection procedure sample.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Review of Degraded and NonConforming Issues

a. Inspection Scope

The inspectors reviewed the licensees current list of corrective action program issues that were characterized as degraded or nonconforming, in accordance with NRC Generic Letter 91-18, Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability.

The inspectors reviewed design basis information, the Updated Safety Analysis Report (USAR), Technical Specification (TS) requirements, System Integrity Program, and licensee procedures to verify the technical adequacy of the operability evaluation.

In addition, the inspectors verified that compensatory measures were implemented as required. The inspectors verified that system operability was properly justified in accordance with NRC Generic Letter 91-18, and that the system remained available, such that no unrecognized increase in risk occurred. Finally, the inspectors reviewed work order and corrective action program history associated with the degraded and nonconforming conditions adverse to quality to determine whether or not the issues were corrected in a prompt manner. This activity constituted one inspection procedure sample. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

Introduction:

A finding of very low safety significance (Green) was identified by the inspectors for a violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions. During a review of the licensees list of safety-related equipment designated as degraded or nonconforming, the inspectors identified that the licensee failed to promptly correct three conditions adverse to quality.

Description:

In September 2004, the inspectors reviewed the individual items on the licensees list of degraded and nonconforming plant equipment. The items were designated degraded or nonconforming because the conditions adverse to quality did not meet the system design requirements or other criteria specified in the USAR.

During this review the inspectors noted that approximately 22 items were on the degraded and nonconforming list, 4 of which were on the list for a year or longer. The inspectors reviewed design drawings and work order documentation associated with these items, and interviewed corrective action program personnel and engineering management. The inspectors noted that the corrective actions required to resolve 3 items were not extensive and could have been achieved during power operations.

The inspectors also noted that General Nuclear Procedure GNP-11.08.01, "Action Request Process, established priorities and guidelines which should be met for the normal completion of evaluations for conditions adverse to quality within approximately 30 days and actions taken to correct the conditions within 90 to 120 days, also taking into account the expected level of effort commensurate with the priority of the issue.

The inspectors reviewed Condition Report CAP013592 and operability determination OBD000023, RHR Pump Seal Cooler Maximum Operating Pressure Less than Required, and noted that the condition report was written on November 6, 2002, for an NRC identified Green Finding (NCV 50-305/02-07-02) documented in NRC Inspection Report 50-305/2002007. The inspectors identified that the RHR pump seal coolers were not designed for the maximum allowable operating pressure of the RHR pump seal cooler. The corrective action history documented that the due date for completion of this corrective action was extended several times in the past 21 months. The inspectors noted that the coolers were initially scheduled to be replaced in the Spring 2003 Refueling Outage; however, licensee management decided prior to the outage to correct the condition online after completion of the outage. Following the refueling outage, additional extensions were requested due to procurement, scheduling and work control delays. The inspectors concluded that this condition adverse to quality was not promptly corrected.

The inspectors also reviewed Condition Reports CAP015776, CCW Operating Temperature Issue, and CAP018109, Modify Diesel Generator Pipe Support DGM-H21, which documented two pipe stress issues for the CCW and EDG piping systems which did not conform to USAR stress criteria. The inspectors noted that these pipe stress issues were identified as a result of the licensee implementing commitments from Generic Letter 79-14, Pipe Crack Study Group - Enclosing NUREG-0531 &

Notice, which the licensee identified in the Spring of 2003 had not yet been implemented. The inspectors further noted that Nuclear Engineering Procedure NEP-04.18, "Justification for Continued Operation of Safety Related Piping Systems, stated in part, that modifications will be made which will return the system to within USAR allowances by the next refueling outage or sooner, if operating conditions permit.

While reviewing the corrective action history for CAP015776, initiated in April 2003, the inspectors noted that there were five nonconforming items contained in this condition report and that initially the corrective actions were assigned a priority level which was not consistent with GNP-11.08.01. The inspectors also noted several due date extensions for the installation of a new CCW piping expansion loop from the B RHR pump seal cooler, which was the only nonconforming item in the condition report which required actual plant modifications. The inspectors concluded that this condition adverse to quality was not promptly corrected.

During the inspectors review of corrective action history of CAP018109, initiated in September 2003, the inspectors noted that the condition report was assigned an incorrect significance level in the licensees corrective action process. The condition report was assigned a significant level D, which was described in Procedure GNP-11-08-01, as a condition not adverse to quality that can be corrected with minimal, if any, evaluation, through routine work activities or closed to actions taken or trending.

The issue identified in CAP018109 was a condition adverse to quality in that a section of fuel oil piping to the B EDG, a safety-related component, exceeded the USAR stress criteria. The inspectors also noted extensions of the due date over the past 12 months due to scheduling and work delays. The inspectors concluded that this condition adverse to quality was not promptly corrected.

Analysis:

The inspectors determined that the failure to promptly correct conditions adverse to quality was a licensee performance deficiency warranting a significance evaluation. This issue was more than minor because it affected the Mitigating System cornerstone attribute of design control for initial design and plant modifications and affected the associated cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609, Appendix A, Phase 1 screening and determined that the finding was of very low safety significance because it was not a design or qualification deficiency that has been confirmed to result in a loss of function per Generic Letter 91-18. The primary cause of this finding was related to the cross-cutting area of problem identification and resolution, because the licensee failed to prioritize and promptly correct these conditions adverse to quality in accordance with the guidelines in the corrective action program.

Enforcement:

Title 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 deficiencies, deviations and equipment, and nonconformances are promptly corrected. Contrary to this, the inspectors identified that conditions adverse to quality related to safety-related piping on the EDG fuel oil piping and CCW system piping to the B RHR seal cooler, and the safety-related seal coolers on both RHR pumps were not promptly corrected. Therefore, the inspectors determined that this finding was a violation of 10 CFR Part 50, Appendix B, Criterion XVI. Because this violation was of very low safety significance (Green) and documented in the licensees corrective action program as Condition Reports CAP013592 and CAP015776, this finding is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy. (NCV 05000305/2004007-01)

At the end of the inspection period the licensee had completed corrective actions to restore the following items to operable status: the A RHR Pump Seal Cooler; the CCW piping expansion loop from the B RHR pump seal cooler; and the fuel oil supply piping to the B EDG. The licensee also rescheduled the corrective action to address the B RHR Pump Seal Cooler to the upcoming Fall 2004 Refueling Outage. In addition, the licensee developed and implemented corrective actions to address the increased number of corrective action program extensions which was also identified by the licensee in a self-assessment. The inspectors noted that the licensee planned to resolve all but 3 of the degraded or nonconforming conditions by January 2005, with plans in place to address the remaining issues and newly discovered issues in a timely manner.

.2 Additional Operability Evaluations Reviewed

a. Inspection Scope

The inspectors reviewed the operability evaluations associated with the following items entered into the licensees corrective action system, completing three inspection procedure samples:

• CAP015776, Component Cooling Water Operating Temperature Issue;

• OPR000071, Low Service Water Flow to Safety Injection Pump B Lube Oil Cooler; and

• OPR000072, QA-2 Equipment Causes a QA-1, Category 1 Air-Operated Valve to Fail in a Non-Safe Position.

The inspectors reviewed design basis information, the USAR, TS requirements, and licensee procedures to verify the technical adequacy of the operability evaluations. In addition, the inspectors verified that compensatory measures were implemented, as required. The inspectors verified that system operability was properly justified and that the systems remained available, such that no unrecognized increase in risk occurred.

Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds

a. Inspection Scope

The inspectors reviewed previously identified operator workarounds, equipment deficiency logs, and control room deficiencies to verify that the cumulative effects did not create significant adverse consequences regarding the reliability, availability and operation of accident mitigating systems. The inspectors also assessed these cumulative effects on the ability of operators to implement abnormal and emergency response procedures in a correct and timely manner.

The inspectors reviewed the planned actions to address operator workarounds to verify that the priorities to resolve the deficiencies were appropriate when considering the potential impact on plant risk and safety. In addition, the inspectors reviewed emergent risk significant operator workarounds to determine whether the functional capability of a system or human reliability of an initiating event was affected. Finally, the inspectors reviewed condition reports regarding operator workarounds to verify that the corrective actions were prioritized, appropriate, and commensurate with the safety significance of the issue, completing one inspection procedure sample. Documents reviewed during this inspection are listed in the Attachment. This activity constituted one inspection procedure sample for the cumulative effects of operator workarounds.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

.1 Failure to Follow Procedures Governing Work On Safety-Related Equipment

a. Inspection Scope

The inspectors reviewed the post-maintenance testing activities associated with the Personnel Airlock Door and Shaft Seal Inspection and Repair. The inspectors verified that the testing was adequate for the scope of the maintenance work performed. The inspectors reviewed the acceptance criteria of the tests to ensure that the criteria was clear and that testing demonstrated operational readiness consistent with the design and licensing basis documents. The inspectors also reviewed the completed test data to ensure the test acceptance criteria were met for the post maintenance testing.

This activity constituted one inspection procedure sample. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

Introduction:

A finding of very low safety significance (Green) was identified by the inspectors for a violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, And Drawings. The licensee conducted corrective maintenance to fix a deficient condition on the containment personnel hatch seal, a safety-related component, under the tool pouch maintenance process rather than with the use of a work request or a work order, contrary to procedural requirements.

Description:

Following a routine containment entry on August 23, 2004, the licensee tested the personnel airlock inner and outer door seals in accordance with TS requirements. The inner door seal was successfully tested; however, the outer door seal failed to meet the test acceptance criteria. Work Request 04-2361 was written to repair the outer door seal, and a work order was processed to replace the outer door seals on the containment personnel hatch, a QA-1 safety-related component.

Maintenance mechanics subsequently identified that the seals on the outer door were not properly lubricated, and after consultation with a mechanical front line supervisor, concluded the work could be performed under tool pouch maintenance, without a work order, after reviewing Procedures GNP-08.02.14, Work Request Initiation, Screening, and Processing, and GNP-08.02.13, Fix It Now (FIN) Team and Minor Maintenance.

The mechanic subsequently cleaned, inspected and lubricated the outer door seal with the appropriate grease and the equipment was post maintenance tested and returned to service. The inspectors identified the work was performed without a work order, contrary to the requirements in Plant Procedures GNP-08.02.14 and GNP-08.02.13, which did not allow work to be performed on QA-1 safety-related equipment without a work order.

The licensee subsequently performed an apparent cause evaluation and extent of condition assessment to determine how many work requests on QA-1 components existed had been resolved without converting to a work order under tool pouch maintenance. The assessment identified that, since July 2002, there were 778 completed tool pouch maintenance activities and 106 of these were for work on QA-1 safety-related components, approximately 14 percent. The licensee expanded the scope and reviewed work activities performed as minor maintenance which were required by Procedure GNP-08.02.13 to be converted from a work request to a work order. The review identified that 136 minor maintenance activities were not converted to work orders, as required. Thirteen of these minor maintenance activities were performed on QA-1 components without a work order, which was approximately 10 percent. Subsequently, the plant maintenance engineering supervisor and a Senior Reactor Operator reviewed the 119 activities performed on QA-1 safety-related components and did not identify any operability concerns with the components.

Analysis:

The inspectors determined that the failure to implement work control processes for conducting work on safety-related equipment to ensure that activities affecting quality were prescribed and accomplished by documented instructions or procedures of a type appropriate to the circumstances was considered a licensee performance deficiency warranting a significance evaluation. This issue was more than minor because it affected the Barrier Integrity Cornerstone attribute of reactor containment integrity, and, if left uncorrected, the finding could become a more significant safety concern. The inspectors evaluated the finding using IMC 0609, Appendix A, Phase 1 screening and determined that the finding was of very low safety significance because it did not represent an actual open pathway in the physical integrity of the reactor containment and none of the work conducted on safety-related equipment without a work order resulted in an operability concern. The inspectors determined that the primary cause of this finding was related to the cross-cutting area of human performance because licensee personnel failed to appropriately implement licensee procedures for conducting work on safety-related components.

Enforcement:

Title 10 CFR Part 50, Appendix B., Criterion V, Instructions, Procedures, And Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, or procedures, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, or procedures. Contrary to this, maintenance work on safety-related components, an activity affecting quality, was not prescribed or accomplished with documented instructions, procedures or drawings of a type appropriate to the circumstances. Specifically, since July 2002, the toolpouch maintenance process was inappropriately applied to work on safety-related components, which was contrary to the licensees work control procedures. The work subsequently conducted under tool pouch maintenance on safety-related components was accomplished without the use of documented instructions, or procedures of a type appropriate to the circumstances. The inspectors determined that this finding was a violation of 10 CFR Part 50 Appendix B, Criterion V. Because this violation was of very low safety significance (Green) and documented in the licensees corrective action program as Condition Report CAP22403 and Apparent Cause Evaluation ACE002753, this finding is being treated as an NCV, consistent with Section VI of the NRC Enforcement Policy. (NCV 05000305/2004007-02)

The licensee subsequently initiated several corrective actions to address these issues which included:

• The initiation of a temporary change to further clarify Procedures GNP-08.02.13 and GNP-08.02.14 to ensure work is not performed on QA-1 safety-related components without a work order;

• The revision of Procedure GNP-08.02.14 to ensure the quality level of the component is known prior to screening a work request;

• The briefing of individuals involved in the work request screening process on the requirements of the plant procedures; and

• The training of the maintenance organization on the procedure requirements for work requests, work request screening, and the different categories of maintenance including toolpouch and minor maintenance, with specific emphasis on the requirements for safety-related components.

.2 Additional Post Maintenance Testing Activities Reviewed

a. Inspection Scope

The inspectors reviewed the post-maintenance testing activities associated with the following scheduled and emergent work activities, completing six inspection procedure samples:

• AFW Pump Flow Control Valve AFW-2A following a design modification;

• PMP-36-04, Reactor Coolant - Pressurizer Heater Ampere Readings Electrical Maintenance (QA-2);

• PMP-08-30, Fire Protection - Carbon Dioxide System Inspection and Dry Test;

• PMP-23-02 ICS - Containment Spray Motor Operated Valve Electrical Maintenance (QA-1) - Valve ICS-2A;

• PMP-31-05 CC-QA-1 Component and Residual Heat Exch. Motor Operated Valve Maintenance - Valve CC-400A; and

• PCG-46D-05 CP- Ultrasonic Flow Measurement and Ultrasonic Temperature Measurement Signal Processing Unit Hard Drive Maintenance.

The inspectors verified that the testing was adequate for the scope of the maintenance work performed. The inspectors reviewed the acceptance criteria of the tests to ensure that the criteria was clear and that testing demonstrated operational readiness consistent with the design and licensing basis documents. Documents reviewed during this inspection are listed in the Attachment.

The inspectors attended pre-job briefings to verify that the impact of the testing was appropriately characterized. The inspectors also observed the performance of testing to verify the procedure was followed and that all testing prerequisites were satisfied.

Following the completion of each test, the inspectors walked down the affected equipment to verify removal of the test equipment and to ensure the equipment could perform the intended safety function following the test. The inspectors also reviewed the completed test data to ensure the test acceptance criteria were met for the post maintenance testing.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed and reviewed the surveillance testing results for the following surveillances, completing two inspection procedure samples:

• SP-42-312A, Diesel Generator A Availability Test; and

• SP-33-072, Safety Injection Accumulator Sample.

The inspectors verified that the equipment could perform the intended safety function and that the surveillance tests satisfied the TS requirements and the licensees procedures. The inspectors reviewed the surveillance tests to verify the tests were adequate to demonstrate operational readiness consistent with the design and licensing basis documents, and that the testing acceptance criteria were well documented and appropriate to the circumstances. Documents reviewed during this inspection are listed in the Attachment.

The inspectors observed portions of the tests to verify the following attributes:

performance of the tests in accordance with prescribed procedures; completion of test procedure prerequisites; and verification that the test data was complete, appropriately verified, and met the acceptance criteria of the test. Following the completion of the tests, when applicable, the inspectors walked down the affected equipment to verify test equipment removal and to confirm the equipment tested was in an operable condition.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the modification documentation and associated 10 CFR 50.59 evaluations for the following temporary plant modifications, completing two inspection procedure samples:

• TCR-03-33, Installation of Ethernet Board in Plant Process Computer System; and

• TCR-04-08, Gag HD-430B, Condensate Relief Valve for Condensate Heaters 11B and 12B.

The inspectors verified that the temporary modification did not adversely impact any safety-related equipment and that the modification was controlled in accordance with the licensees administrative procedures. The inspectors also verified that the modification did not affect system operability or availability. In addition, the inspectors reviewed condition reports to verify that temporary modification problems were entered into the corrective action program with the appropriate significance characterization.

b. Findings

No findings of significance were identified.

1EP2 Alert and Notification System (ANS) Testing

a. Inspection Scope

The inspector reviewed the relevant Emergency Plan Maintenance Procedure (EPMP)and discussed with Emergency Preparedness (EP) staff the operation, maintenance, and periodic testing of the ANS in the Kewaunee County portion of the Kewaunee Nuclear Power Plant (KNPP) Emergency Planning Zone (EPZ) to determine whether ANS equipment was maintained and tested in accordance with commitments and procedural requirements between January 2003 and May 2004. The inspector also discussed concerns, which were identified by Nuclear Oversight (NOS) staff in 2003 and 2004, regarding assessments of several siren outages within the overlapping portion of the Kewaunee and Point Beach Nuclear Power Plant EPZs that were relevant to determining if an event report to NRC was procedurally warranted per the requirement of 10 CFR 50.72 (b)(3)(xiii). The inspector reviewed records of annual preventive maintenance activities performed in 2003, as well as July 2003 through March 2004 ANS operability test results. A sample of corrective action program documents were reviewed to determine whether the licensee effectively used the program to document and track ANS-related concerns. The inspector also discussed a potential change to the organization responsible for maintaining ANS equipment for KNPP and the Point Beach Plant. These activities represented one inspection procedure sample.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization (ERO) Augmentation Testing

a. Inspection Scope

The inspector reviewed records and discussed with EP staff the revisions of Emergency Plan Implementing Procedures (EPIP) and EPMP that were associated with the primary and alternate methods of initiating an ERO activation to augment the onshift ERO. The inspector reviewed records and discussed recent training on the revised equipment used for initiating an ERO activation. The inspector also discussed the roles of the recently implemented EP Duty Manager position. The inspector discussed provisions for maintaining the EROs call-out roster with the EP Instructor.

The inspector reviewed critique records and a sample of corrective action program records of unannounced, off-hours ERO augmentation drills, which were conducted between March 2003 and May 2004, to determine the adequacy of the licensees performance during the drills, the critiques, and associated corrective actions. The inspector also reviewed correspondence to ERO members that re-emphasized managements expectations regarding pager use and emergency response.

The inspector reviewed the EP training records of a random sample of 36 ERO members, who were assigned to key and support positions in the onsite and offsite ERO, to determine whether they were currently trained for their assigned response positions. The inspector also discussed a licensee Action Plan, which was scheduled to be implemented later in 2004, that was intended to improve the quality of EPIPs and ERO training. These activities represented one inspection procedure sample.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed the results of NOS audits of the EP program, which were performed between October 2002 and March 2004, to verify that these independent assessments met the requirements of 10 CFR 50.54(t) and to verify that concerns identified during these audits were addressed by EP staff. The inspector also reviewed a sample of critique reports and corrective action program documents associated with the 2003 exercise, as well as various EP drills conducted during 2003, to verify that the licensee fulfilled its drill commitments and to evaluate the licensees efforts to identify, track, and resolve concerns identified during these activities. The inspector discussed the licensees LEAN Team concept, which was intended to improve support to the EP staff by other functional groups in addressing EP-related corrective action program items more efficiently. The inspector observed a meeting of EP and other plant staff that involved assigning responsibilities for planned corrective actions resulting from the critique of a June 2004 EP drill. The inspector also reviewed and discussed records relevant to the plants offsite re-assembly area.

The inspector discussed the status of a sample of EP Program-related topics listed in the current schedule of the KNPP Site Excellence Plan. The inspector also discussed ongoing preparations for a working meeting that was intended to address emergency facilities, equipment, offsite support, and software matters relevant to the Kewaunee and Point Beach Nuclear Plants EP Programs. These activities represent one inspection sample.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed a licensed operator crew perform an emergency drill on the simulator on August, 31, 2004, completing one emergency planning simulator exercise inspection procedure sample. The inspectors observed activities in the control room simulator, attended the critique, and reviewed the completed drill documentation and critique report. The inspectors evaluated the drill performance and verified that deficiencies were entered into the corrective action program and drill failures were appropriately accounted for in the licensees drill and exercise performance indicator (PI)tracking. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Public Radiation Safety

2PS3 Radiological Environmental Monitoring Program (REMP) and Radioactive Material Control Program (71122.03)

.1 Inspection Planning - Reviews of Radiological Environmental Monitoring Reports and

Data

a. Inspection Scope

The inspectors reviewed the 2002 and 2003 Annual Radiological Environmental Monitoring Reports, selected results of radiological environmental monitoring analyses for the first half 2004, and the most recent licensee assessment results to verify that the REMP was implemented as required by the Offsite Dose Calculation Manual and the Radiological Environmental Monitoring Manual (REMM). The inspectors reviewed the environmental reports for changes to the REMM with respect to environmental monitoring, commitments in terms of sampling locations, monitoring and measurement frequencies, land use census, the sample analysis vendors inter-laboratory comparison program, and analysis of environmental sample data. The inspectors reviewed the REMM to identify the environmental monitoring stations and evaluated the locations of these stations and the types of samples collected from each to determine if they were consistent with NRC guidance in Regulatory Guide 1.21, Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous Effluents from Light Water Cooled Nuclear Power Plants, and in Regulatory Guide 4.8, Environmental TSs for Nuclear Power Plants. The inspectors reviewed the USAR for information regarding the environmental monitoring program and meteorological monitoring instrumentation to determine whether the program was developed consistent with its design basis. The inspectors also reviewed the scope of the licensees audit program to verify that it met the requirements of 10 CFR 20.1101(c) relative to the REMP and radioactive material control programs. These reviews represented one inspection procedure sample.

b. Findings

No findings of significance were identified.

.2 Onsite Inspection Activities

a. Inspection Scope

The inspectors walked down all five of the environmental air sampling indicator stations and approximately 30 percent of the thermoluminescence dosimeter (TLD)monitoring stations. The walkdown was performed to determine whether these environmental stations were located as described in the REMM, to assess equipment material condition and operability, and to verify that environmental station orientation relative to plant effluent release points, vegetation growth control, and equipment configuration allowed for the collection of representative samples.

The inspectors accompanied a REMP technician and observed the collection and change-out of air particulate and charcoal cartridges at each air sampling station, and observed the collection of a precipitation water sample and discussed milk sampling protocols to determine whether appropriate practices were used to ensure sample integrity and to verify that sampling techniques were in accordance with the licensees procedures.

The primary and backup meteorological towers were walked down by the inspectors to verify they were adequately sited and that instrumentation was installed consistent with Regulatory Guide 1.23, Meteorological Programs in Support of Nuclear Power Plants.

The inspectors discussed with instrument and control staff the recent meteorological equipment upgrades and system modifications, and verified through record review that the currently installed meteorological instruments were operable, calibrated, and maintained in accordance with guidance contained in the USAR, NRC Safety Guide 23, and licensee procedures. The inspectors compared real-time data collected at the meteorological tower versus the time-averaged data transmitted to the control room to verify data integrity.

The inspectors reviewed each event documented in the Annual Environmental Monitoring Reports which involved a missed sample, inoperable sampler, lost TLD, or anomalous measurement for the cause and corrective actions and conducted a review of the licensees assessment of any positive sample results (i.e., licensed radioactive material detected above the lower limits of detection.

The inspectors reviewed changes made to any environmental sample stations since the last inspection and/or significant changes made by the licensee to the REMM as dictated by the 2002 or 2003 land use census. The inspectors reviewed technical justifications for changed sampling locations, if applicable. The inspectors verified that the licensee performed the reviews required to ensure that the changes did not affect its ability to monitor the potential impact of radioactive effluent releases on the environment.

The inspectors reviewed calibration and maintenance records for 2003 through mid-2004, for all five of the environmental air samplers. The review focused on air flow meter calibration, and maintenance of air pump motor bearings, vanes and particulate air/charcoal cartridge related components. Additionally, the most recent (annual)calibration records of the flow meters (rotameters) used by the licensee to measure and validate air sample pump flow rates was reviewed to ensure traceability to the National Institute of Standards and Technology. As the licensee does not conduct analyses of REMP samples on-site and utilizes a vendor laboratory to provide analytical services, the inspectors did not review licensee calibration records for environmental sample radiation measurement instrumentation (i.e., count room equipment) or quality control charts.

The inspectors reviewed the results of a 2003 Nuclear Procurement Issues Committee audit of the REMP analytical vendor laboratory and also reviewed the vendors internal quality control program including the inter-laboratory comparison program, to verify the adequacy of the vendors program and the corrective actions for any identified deficiencies. The inspectors reviewed the lower limit of detection values achieved by the vendor laboratory for all REMP required sample media to verify that analytical detection capabilities met REMM requirements for each environmentally monitored pathway. The inspectors reviewed the last quality assurance audit results of the REMP to determine whether the licensee met its TS/ODCM requirements.

These reviews represented six inspection procedure samples.

b. Findings

No findings of significance were identified.

.3 Unrestricted Release of Material from the Radiologically Controlled Area (RCA)

a. Inspection Scope

The inspectors observed those locations where the licensee monitored potentially contaminated materials and individuals leaving the RCA, and evaluated the procedures and practices used for control, survey, and release of materials and workers from these areas. The inspectors questioned several radiation protection staff responsible for the performance of personnel surveying and releasing material for unrestricted use to assess their knowledge of procedures and protocols and to verify that release surveys are performed appropriately.

The inspectors assessed the radiation monitoring instrumentation used to conduct surveys for the unrestricted release of workers and of materials from the RCA to determine if they were appropriate for the radiation types present, were operationally checked with radiation sources consistent with the plants nuclide mix, and that source activities were sufficient to challenge the monitor alarm setpoints. The inspectors reviewed the licensees criteria for the survey and release of potentially contaminated material and workers to verify that there was guidance on how to respond to an alarm which indicates the potential presence of licensed radioactive material. The inspectors reviewed the licensees radiation survey equipment to ensure the radiation detection sensitivities were consistent with the NRC guidance for surface contamination contained in Circular 81-07, Control of Radioactively Contaminated Material, and Information Notice 85-92, Survey of Wastes Before Disposal from Nuclear Reactor Facilities, and with Health Physics Positions (position-221) in NUREG/CR-5569 for volumetrically contaminated material.

The inspectors discussed with the radiation protection manager (RPM) the plants radionuclide (isotopic) mix to determine if the licensee had identified its difficult-to-detect radionuclides (i.e., those that decay via electron capture) and recognized the potential impact of those nuclides on its unrestricted release survey program. The inspector also discussed with the RPM the licensees plans to reassess the plants nuclide mix on a regular basis so as to identify potential changes, and to document the results of the assessment including the impact on the unconditional release, air sampling and internal dose assessment programs.

The inspectors reviewed the licensees procedures and survey records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters (i.e., counting times and background radiation levels).

The inspectors verified that the licensee had not established a release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high radiation background area.

These reviews represented two inspection procedure samples.

b. Findings

No findings of significance were identified.

.4 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed the licensees self-assessments, audits, Licensee Event Reports, and Special Reports, as applicable, related to the radiological environmental monitoring and radioactive material control programs since the last inspection to determine if identified problems were entered into the corrective action program for resolution. The inspectors also verified that the licensee's self-assessment and/or audit program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

The inspectors also reviewed corrective action program documents related to the REMP and the radioactive material control programs generated since the previous inspection, interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk:

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

• Evaluation of safety significance/risk and priority for resolution;

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions; and

• Implementation/consideration of risk significant operational experience feedback.

These reviews represented one inspection procedure sample.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

.1 Reactor Safety Strategic Area - Initiating Event and Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors sampled the licensees submittals for the PIs listed below, which completed three inspection procedure samples:

• Unplanned Power Changes per 7,000 Critical Hours;

• Emergency AC Power Unavailability; and

• Heat Removal System Unavailability (AFW unavailability).

The inspectors used performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2, to verify the accuracy of the PI data. The inspectors reviewed corrective action documents, monthly operating reports, completed surveillance procedures, control room logs, and licensee event reports to independently verify the data that the licensee had collected and reported from January 2003 through March 2004. The inspectors also independently performed calculations for system unavailability when applicable. Documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Reactor Safety Strategic Area - Emergency Preparedness Cornerstone

a. Inspection Scope

The inspector reviewed the licensees records associated with the three EP PIs listed below. The inspector verified that the licensee accurately reported these indicators, with a self-identified, minor exception that was being corrected, in accordance with relevant procedures and Nuclear Energy Institute guidance endorsed by NRC. Specifically, the inspector reviewed licensee records associated with PI data reported to the NRC for the period July 2003 through March 2004. Reviewed records included: procedural guidance on assessing opportunities for the three PIs; assessments of PI opportunities during pre-designated Control Room Simulator training sessions, the 2003 biennial exercise, and pre-designated drills; revisions of the roster of personnel assigned to key ERO positions; and results of bimonthly ANS operability tests. These activities represented three inspection procedure samples. The following PIs were reviewed:

• ANS;

• ERO Drill Participation; and

• Drill and Exercise Performance.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Licensed Operator Requalification Biennial Sample Review

a. Inspection Scope

The inspectors reviewed the most recent licensee training department self-assessment report. The licensees self-assessment reviewed the licensed operator training program through September 2003. The self-assessment was reviewed to ensure that any issues identified during the self-assessment were appropriately evaluated, prioritized, and controlled.

b. Findings

There were no findings of significance.

.2 Routine Resident Inspector Review of Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that issues were entered into the licensees corrective action system at an appropriate threshold, that adequate attention was given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors also reviewed all condition reports written by licensee personnel during the inspection quarter. Minor issues entered into the licensees corrective action system as a result of inspectors observations are included in the list of documents in the Attachment, in the section entitled Condition Reports Initiated for NRC-Identified Issues.

b. Findings

No findings of significance were identified.

.3 Problem Identification and Resolution Annual Inspection Sample

Turbine Driven Auxiliary Feedwater Pump Turbine Bearing Oil Sample Indicates Cutting Wear and Journal Bearing Found Damaged Introduction The inspectors selected Condition Reports CAP021539, Turbine Driven Auxiliary Feedwater Pump Turbine Oil Samples Contained Contaminants, and CAP21599, NRC Resident Inspector Concerns on the TDAFW Pump Operability, with corresponding Root Cause Evaluation RCE652, Turbine Driven Auxiliary Feedwater Pump Turbine Bearing Oil Sample Indicates Cutting Wear and Journal Bearing Found Damaged, for an annual sample review of the licensees problem identification and resolution program.

This constitutes one annual review inspection procedure sample. Documents reviewed during this inspection are listed in the Attachment.

a.

Effectiveness of Problem Identification

(1) Inspection Scope The inspectors reviewed Condition Reports CAP021539 and CAP21599, with Root Cause Evaluation RCE652 to verify that the licensee's identification of the problems were complete, accurate, timely, and that the consideration of the extent of condition review, generic implications, common cause, and previous occurrences was adequate.

(2) Findings No findings of significance were identified.

b.

Prioritization and Evaluation of Issues

(1) Inspection Scope The inspectors reviewed Condition Reports CAP021539 and CAP21599, with Root Cause Evaluation RCE652. The inspectors considered the licensees evaluation and disposition of performance issues, evaluation and disposition of operability issues, and application of risk insights for prioritization of issues.

(2) Findings No findings of significance were identified.

c.

Effectiveness of Corrective Actions

(1) Inspection Scope The inspectors reviewed the corrective actions identified in Condition Reports CAP021539 and CAP21599, with Root Cause Evaluation RCE652 for applicability to the identified deficiencies. The inspectors also reviewed the planned corrective actions to determine if the planned actions were appropriately focused to correct the identified problems and extent of condition issues.

(2) Findings No findings of significance were identified.

4OA3 Event Followup

.1 (Closed) Unresolved Item (URI) 50-305/2004004-02: Review of Final Analysis

Concerning High Oil Particulate discovered in the Turbine Driven AFW Pump Turbine.

Introduction:

A Green finding was self-revealed when the licensee reviewed the circumstances surrounding high oil particulate in the Turbine Driven Auxiliary Feedwater Pump Turbine. The finding involved the licensees failure to ensure that procedures associated with the maintenance of the Terry Turbine for the Turbine Driven AFW Pump were appropriate to the circumstances and included appropriate quantitative or qualitative acceptance criteria. A Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings." Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was associated with this finding.

Description:

On June 10, 2004, the licensee took an 18-month oil sample on the inboard and outboard bearings of the turbine for the turbine driven AFW pump for analysis. The initial analysis results, which were completed on June 11, indicated high wear products for both the inboard and outboard turbine bearings. The licensee subsequently declared the turbine-driven AFW pump inoperable and the oil samples were sent to a vendor for further analysis on June 11. In addition, the licensee formed a troubleshooting team to develop a troubleshooting plan and the next course of action.

The vendors analysis determined that high concentrations of steel, severe cutting wear particles, and small rubbing wear particles were present in the oil. On June 12, the licensee removed the inboard and outboard bearing covers and inspected the turbine bearings. The inboard upper and lower journal bearings exhibited evidence of normal wear and the journal had some very light scoring. The outboard upper and lower journal bearing were found to be partially wiped, especially near the turbine end of the bearing.

Visual inspections identified that the bearing housing surfaces in contact with the oil were had a silver-colored coating, which was later confirmed as an aluminum phenolic coating from the original manufacturing. The inspections revealed that areas of this coating were missing, and that small particles of the coating were in the bottom of the bearing housing. The licensee replaced the journal bearings with new bearings and cleaned the bearing housings to remove any additional loose coating. The licensee then performed an uncoupled overspeed trip test utilizing Procedure PMP 05B-07 and obtained additional oil samples. These oil samples indicated unacceptable chemistry and high wear products. The unacceptable chemistry was attributed to the use of isopropyl alcohol as a cleaning solvent and the high wear was attributed to incomplete cleaning of debris from the cavities. The licensee then performed flushes of the of the inboard and outboard bearing housings until acceptable oil sample results were obtained of all oil parameters before proceeding. The licensee then performed and satisfactorily completed the minimum flow TS Test for the Turbine Driven AFW Pump, SP 05B-333. Additional oil samples taken following the test showed acceptable results.

Finally, the quarterly full flow TS Test for the Turbine Driven AFW Pump, SP-5B-284, was later performed, which demonstrated all pump and turbine parameters as normal, including the oil samples taken as part of the test.

In NRC Inspection Report 50-305/2004004, Section 1R15.2, the inspectors documented that 3 weeks following the event the licensee began the Root Cause Evaluation and the inspectors identified to the licensee that Electric Power Research Institute technical manual for Terry Turbine maintenance for AFW applications indicated that the coatings inside the bearing housings were to be inspected for degradation on a routine, 18-month maintenance overhaul and inspection, due to known coating degradation issues in Terry Turbines. The inspectors also noted that the manual provided acceptance criteria for oil sample results and discussed a routine oil sample frequency of 3 months.

The licensee completed the root cause evaluation on September 27, 2004, which the inspectors reviewed and evaluated. The licensee concluded that:

• the root cause of the bearing damage and high oil particulate was the failure to ensure that available industry guidance and operating experience was incorporated into the licensees maintenance practices and procedures for Terry Turbines;

• the likely cause of bearing wear observed was from the reuse of the bearing in a different location than originally installed on the turbine;

• the current maintenance procedures for the rebuild of the turbine did not prohibit the reuse of bearings in a new location, and the extent of condition revealed that maintenance procedures for the AFW pumps, safety injection pumps and emergency diesel generators also did not contain adequate guidance to ensure bearings were not interchanged;

• preventive maintenance activities for the Terry Turbine did not incorporate the appropriate guidance and frequency for opening, cleaning and inspecting the Terry Turbine bearings and bearing cavities, which would have addressed the issue of the degraded aluminum coating;

• the frequency for oil sampling on the Terry Turbine was not adequate, based on industry experience, and the licensees oil sampling methods and acceptance required enhancement; and

• had further investigation been performed of an October 2001 Terry Turbine oil sample, which also had anomalous analysis results, this issue would most likely have been identified previously.

The licensee also performed a past operability analysis which involved the turbine vendor, bearing vendor, recognized industry experts on Terry Turbines, and metallurgical failure analysis of the journal bearings. The inspectors, in conjunction with a technical matter expert from the Office of Nuclear Reactor Regulation, verified the licensees analysis and conclusion that, with the as-found condition of the bearings, the Turbine Driven AFW Pump would have been able to perform the intended safety function for the required mission time.

Analysis:

The inspectors determined that the failure to ensure that procedures associated with the corrective and preventive maintenance of the Terry Turbine for the Turbine Driven AFW Pump were appropriate to the circumstances and included appropriate acceptance criteria was a licensee performance deficiency warranting a significance evaluation. This self-revealed finding was more than minor because, if left uncorrected, the issue would have become a more significant safety concern. In addition, it affected the Mitigating Systems attributes of equipment performance reliability and the Mitigating Systems cornerstone objective of ensuring the reliability of systems. The inspectors evaluated the finding using IMC 0609, Appendix A, Phase 1 screening, and determined that, based on the past operability analysis performed by the licensee, the finding was of very low safety significance because it was not a design or qualification deficiency that has been confirmed to result in a loss of function per Generic Letter 91-18. Therefore, the finding was determined to be of very low safety significance (Green).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions or procedures, of a type appropriate to the circumstances and shall include appropriate acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to this requirement, the licensee failed to ensure that procedures associated with the maintenance of the Terry Turbine for the Turbine Driven AFW Pump were appropriate to the circumstances and included appropriate quantitative or qualitative acceptance criteria. Specifically, the licensees maintenance procedures allowed the reuse of bearings in different locations, which was not an acceptable maintenance practice; preventive maintenance procedures did not specify appropriate acceptance criteria for oil sampling; and licensee preventive maintenance procedures did not specify the appropriate frequency and criteria for inspecting the turbine bearings and bearing cavities. Therefore, the inspectors determined that this finding was a violation of 10 CFR Part 50, Appendix B, Criterion V.

Because this violation was of very low safety significance (Green) and was documented in the licensees corrective action program as Condition Reports CAP21539 and CAP21599, and Root Cause Evaluation RCE00652, it is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy. (NCV 05000305/2004007-03)

The licensee took immediate remedial corrective actions to replace the bearings, clean the housing and return the pump to service. In addition, the licensee developed the following corrective actions to prevent recurrence and address the extent of condition issues:

• Revised the preventive maintenance activities for oil sampling of the turbine from 18 months to quarterly;

• Revised the oil sampling procedure to change the oil sampling method to ensure a representative oil sample is taken;

• Revised the procedures for inspection and overhaul of the Terry Turbine to incorporate industry guidance and prevent the reuse of bearings in different locations, filter oil added to the turbine, and perform an axial end play measurement before coupling;

• Created a preventive maintenance activity to open, clean and inspect the turbine bearings and bearing cavity each refueling cycle;

• Reviewed Electric Power Research Institute Nuclear Maintenance Application Center topical reports that provided guidance applicable to plant equipment and revised current licensee maintenance practices, where required;

• Implemented a process to ensure that new topical reports are reviewed and incorporated at the plant;

• Developed procedural guidance establishing acceptance criteria for oil sample analysis results; and

• Reviewed and revised procedures for inspection and rebuilding of the safety injection pumps, AFW pumps and emergency diesel generators to contain adequate guidance to ensure that bearings are not interchanged between locations, even if the bearings appear identical.

4OA4 Cross Cutting Aspects of Findings

.1 A finding described in Section 1R15.1 of this report had, as the primary cause, a

problem identification and resolution deficiency, in that, the licensee failed to take prompt corrective actions to address conditions adverse to quality affecting safety-related equipment on the licensees degraded and nonconforming list.

.2 A finding described in Section 1R19.1 of this report had, as the primary cause, a human

performance deficiency, in that, licensee personnel failed to appropriately implement procedure requirements for work performed on safety related equipment.

4OA5 Other Activities

.1 Temporary Instruction (TI) 2515/159: Review of Generic Letter (GL) 89-13: Service

Water System Problems Affecting Safety-Related Equipment

a. Inspection Scope

On July 29, 2004, as part of a Davis-Besse Lessons-Learned Task Force Recommendation [3.1.2(5)] commitment, the NRC issued a Temporary Instruction (TI)to review the licensee's continued actions in response to Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment."

From August 16 through 20, 2004, three inspectors from the regional office performed an inspection at the Kewaunee Nuclear Power Plant to assess the licensees continued actions in response to Generic Letter 89-13. The inspectors reviewed licensee documents, as listed in the Attachment, interviewed license personnel, and performed a detailed walkdown of the service water system. The objective of this inspection was to review the licensees activities in response to NRC generic communications through focus on Generic Letter 89-13.

As part of this inspection, the inspectors completed the scope of the following baseline inspections:

71111.04S, Equipment Alignment: The inspectors completed one entire system walkdown required by this baseline inspection procedure. Under the activities required to complete Inspection Requirement 03.04 of the TI, a detailed walkdown of the service water system was conducted. The inspectors used the inspection guidance in both 71111.04 and TI 2515/159, Attachment A, to conduct the walkdown. This activity comprised one semi-annual inspection procedure sample.

71111.07B, Heat Sink Performance: The inspectors completed the biennial portion of this baseline inspection procedure in its entirety. Under the activities required to complete Inspection Requirement 03.02 of the TI, three heat exchangers were reviewed. These heat exchangers were the 1A RHR pump pit fan coil unit (FCU), the 1B component cooling water CCW pump room FCU, and the diesel generator lube oil coolers. These activities comprised three biennial inspection procedure samples.

71111.12, Maintenance Effectiveness: The inspectors completed two annual maintenance performance issues reviews required by this baseline inspection procedure. Under the activities required to complete Inspection Requirements 03.01 and 03.05 of the TI, the inspectors reviewed a sample of station logs, maintenance work orders, maintenance rule evaluations, unavailability records, and a sample of condition reports to verify that the licensee identified issues related to the maintenance rule at an appropriate threshold and that corrective actions were appropriate. The inspectors verified that the licensee identified, entered, and scoped component and equipment failures within the maintenance rule requirements. Issues that were evaluated specifically for this area were safety injection (SI) pump stuffing box silting and the discovery of zebra mussel shells in the 1A control rod drive motor FCU. These activities comprised two inspection procedure samples.

71111.17, Permanent Plant Modifications: The inspectors completed a portion of the biennial aspect of this baseline inspection procedure. Under the activities required to complete Inspection Requirement 03.04 of the TI, the inspectors reviewed three permanent plant modifications, in order to ensure that the modifications had not altered the design basis or introduced any single failure vulnerabilities. As part of the review of these modifications, the inspectors also reviewed associated screenings or evaluations performed pursuant to 10 CFR 50.59 and post-modification testing. These activities comprised three biennial inspection procedure samples.

71111.22, Surveillance Testing: The inspectors reviewed one surveillance test. Under the activities required to complete Inspection Requirements 03.02 and 03.04 of the TI, the inspectors reviewed a surveillance procedure for the EDG lube oil heat exchangers to verify that the equipment could perform its intended safety function and that the surveillance test satisfied the TS requirements. The inspectors also reviewed the surveillance test to verify the test was adequate to demonstrate operational readiness consistent with the design and licensing basis documents, and that the testing acceptance criteria were well documented and appropriate to the circumstances. The activity comprised one inspection procedure sample.

71152, Identification and Resolution of Problems: The inspectors completed one semi-annual review of identified problems. Under the activities required to complete Inspection Requirement 03.05 of the TI, the inspectors reviewed maintenance records and corrective action backlog lists to identify trends of equipment problems that might indicate the existence of a more significant safety issue. This activity comprised one semi-annual inspection procedure sample.

1. Inadequate Inspection and Cleaning Procedure

Introduction:

The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, having very low safety significance (Green). This finding was associated with the licensees failure to implement an appropriate inspection and cleaning procedure containing quantitative or qualitative acceptance criteria for the 1A RHR pump pit FCU to ensure that cleaning was satisfactorily accomplished.

Description:

As documented in the licensees Generic Letter 89-13 Program Document (NID-01.01), the licensee committed to testing the 1B RHR pump pit FCU by monitoring flow and temperatures (service water side of heat exchanger); however, the 1A RHR pump pit FCU was not monitored. This exclusion was submitted to the NRC in the supplemental response to the NRC and was accepted. Instead, the licensee performed an annual air side and service water side flushing of the FCU using Preventative Maintenance Procedure (PMP) 17-02, QA-1 & QA-2 Fan Coil Units, Inspection and Cleaning. The PMP-17-02 instituted fin side (air side) cleaning and tube side (service water side) flushing of the 1A train FCU. Upon review of PMP-17-02, the inspectors determined that the procedure was not appropriate to the circumstances and did not contain either quantitative or qualitative acceptance criteria to ensure that the flushing was satisfactorily accomplished. Specifically, the inspectors noted that Step 4.2.11 of the procedure required the licensee to introduce a water hammer into the system to resuspend the silt accumulation and flush it from the system. The procedure was inappropriate to the circumstances in that it did not contain instructions to ensure that the pressure pulse introduced did not exceed the pressure rating of the heat exchangers. The procedure also did not contain either qualitative or quantitative acceptance criteria to assure that all the air was removed from the system rather than accumulating in the service water system. Following identification of this issue, the licensee wrote a condition report and performed a prompt operability determination.

The inspectors noted that this procedure was also used for other heat exchangers connected to the safety-related portion of the service water system.

Analysis:

The inspectors determined that the failure to have a procedure adequate to the circumstances or with qualitative or quantitative acceptance criteria when performing flushing of the 1A RHR pump pit FCU was a performance deficiency warranting a significance evaluation. The inspectors evaluated the finding using NRC IMC 0612, Power Reactor Inspection Reports, and determined that the finding was more than minor because it involved the procedure quality attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors evaluated the finding using IMC 0609, Significance Determination Process, since the finding was associated with the availability and reliability of a train of a mitigating system. As the licensee had determined that the 1A RHR pump pit FCU remained operable, the inspectors determined that this issue screened out of Phase 1 of the SDP. Therefore, this finding was considered to be of very low safety significance (Green).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and that the instructions, procedures, or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, as of August 20, 2004, Procedure PMP 17.02 was inappropriate to the circumstances as it did not contain information to ensure that the pressure pulse introduced in Step 4.2.11 would not damage the 1A RHR pump pit FCU. Furthermore, Procedure PMP 17.02 did not contain either qualitative or quantitative acceptance criteria to ensure that all air was removed from the system following the activity. Therefore, the inspectors determined that this finding was a violation of 10 CFR Part 50, Appendix B, Criterion III.

Because this violation was determined to be of very low safety significance, and because the licensee entered the violation into its corrective action program as CAP022293 and CAP022299, this violation is being treated as a NCV consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000306/2004007-04).

2. Inadequate Design Control Process

Introduction:

The inspectors identified a Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, having very low safety significance (Green).

This finding was associated with the licensees failure to verify or check the adequacy of the design when installing a new air actuator on the service water valves on the outlet of the diesel generator lube oil coolers.

Description:

Under Design Change (DCR) 3357, the licensee installed new air-operated actuators on the service water outlet valves [SW-301A/B]. These valves are normally closed and open upon a diesel generator start signal. Upon review of the modification package and 10 CFR 50.59 screening, the inspectors noted that the design description stated that the new actuator would have the capability of over-torquing the valve causing a stem failure. The design description further noted that this failure would occur if something were to restrict the valves movement somewhere in its range of motion. The design description concluded that, were this failure to occur, it would be considered a single active failure. No further information was provided in the design description.

The attached safety review also discussed the possible failure of the actuator to break the stem. The safety review concluded that the failure would only be possible if foreign material caused the valve to bind. The review stated that, as each train was supplied by a separate service water header, a common mode failure was not considered credible, and that any binding would constitute a single failure, regardless of stem integrity.

The inspectors determined that the licensee had not fully evaluated this failure mode.

The inspectors noted that similar actuators were installed on both the service water outlet valves to both diesel generator lube oil coolers. The inspectors also noted that both service water headers were normally fed from a single header and that foreign material had previously been found in both headers and that it was possible for this foreign material to wedge between the valve ball and body, causing the ball to freeze with subsequent overtorquing. The inspectors reviewed several corrective action system inputs in which the licensee identified deposits of shells, mud and silt in the service water system. Although the licensee's foreign materials exclusion program addressed worker-introduced foreign material into the service water system, this design change did not consider the adverse effects from foreign materials introduced by the service water system itself including shells, mud and sediment.

The inspectors also noted that the licensee had not fully explored all methods for the valve ball to become frozen before considering the failure as non-credible. Finally, the inspectors determined that the licensee did not have any design verification, such as calculations, which showed that the actuator would not overtorque the valve during valve closure, resulting in stem breakage. The inspectors noted that numerous instances of valve actuators being improperly sized were documented in NRC correspondence, albeit, generally in regard to motor-operated valves rather than air-operated valves.

The licensee entered this issue into its corrective action system as CAP022312 and performed an operability assessment under OPR000075. This operability assessment focused on the valves vulnerability to foreign material introduced by the service water system and provided a qualitative assessment to support the conclusion that the valves were operable.

Analysis:

The inspectors determined that the failure to have design verification to demonstrate that the new valve actuator would not result in a stem failure was a performance deficiency. The inspectors evaluated the finding using NRC IMC 0612, Power Reactor Inspection Reports, and determined that the finding was more than minor because it involved the design control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors evaluated the finding using IMC 0609, Appendix A, Phase 1 screening, and determined that, based on the past operability analysis performed by the licensee, the finding was of very low safety significance because it was not a design or qualification deficiency that has been confirmed to result in a loss of function per Generic Letter 91-18. Therefore, this finding was considered to be of very low safety significance (Green).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program, which includes suitable qualification testing of a prototype unit under the most adverse design conditions. Contrary to the above, as of August 20, 2004, the licensee had not performed any design verification to show that the actuator installed under Design Change 3357 would not result in a failure of the valve stem under conditions where the valve ball froze nor had the licensee provided sufficient justification to show that valve ball freezing was not credible. Therefore, the inspectors determined that this finding was a violation of 10 CFR Part 50, Appendix B, Criterion III. Following discovery, the licensee performed an operability assessment which provided more information why the stem failure was considered not credible. Because this violation was determined to be of very low safety significance, and because the licensee entered the violation into its corrective action program as CAP022312, this violation is being treated as a NCV consistent with Section VI.A of the USNRC Enforcement Policy (NCV 05000306/2004007-05).

3. TI Analysis

In accordance with TI 2515/159 reporting requirements, the inspectors provided the required data to the NRC headquarters staff for further analysis. A summary of the responses to the questions of the TI is provided below.

i.

Determine the effectiveness of Generic Letter 89-13 in communicating information.

Generic Letter 89-13 was clear in communicating information about service water system problems, both in the initial Letter and the supplement. The licensee took the actions to which it officially committed in its response. Overall, the licensee's process for handling generic communications ended once an evaluation was made or a procedure issued.

Many of the licensee's current programs were driven by recent site or fleet experiences, rather than through continued follow-through on the Generic Letter. Additionally, concerns identified during the baseline heat sink inspection and the safety system performance and design capability inspection provided a continuing awareness of service water issues beyond the initial issuance of the Generic Letter. The licensee's 89-13 program document, prepared in June 2004, contained a requirement to ensure continued compliance with the Generic Letter requirements.

ii.

Describe the licensee actions that are being implemented for the five recommended actions of Generic Letter 89-13.

The Generic Letter had five recommendations; the licensee made commitments for on-going programs for three of them.

• The first recommendation was to implement and maintain an ongoing program of surveillance and control techniques to significantly reduce the incidence of flow blockage problems as a result of biofouling. The licensees commitment in regard to this recommendation was to "aggressively pursue installation of a chlorination system".

The licensees actions in this area were maintaining the commitment. The licensee had implemented a chlorination system; however, there were still occasions where flow blockage problems occurred due to biofouling, most recently in January 2004. Although the licensee had procedural requirements to run the chlorination system for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> daily, they primarily relied upon a once a year continuous chlorination, because of continuing problems with the chlorination system. In addition, in an approved response to a corrective action document, the licensee stated that they did not have any design or licensing basis commitments which required them to have the chlorination system operable.

In regard to the effectiveness of the system to preventing biofouling, the licensee had performed a corrective action evaluation which determined the maximum expected size of a zebra mussel growing in the system between the annual continuous chlorination injections, due to a large mussel shell being found on a heat exchanger tube sheet.

Based on this, they considered the annual kill to be effective. However, approximately a month later, the licensee found mussel shells that were above this maximum size in another cooler. Additionally, use of a "bio-box" showed only about 50 percent "kill effectiveness" in one safety related train of service water. At the time of the inspection, the licensee was pursuing an improved chlorination system, as shown by their Top 10" equipment improvement list.

• The second recommendation was to conduct a test program to verify the heat transfer capability of all safety-related heat exchangers cooled by service water.

The licensee committed to install instrumentation and performance monitor, with exception of the 1A RHR pump pit FCU. The licensee informed the NRC, in their supplemental response, that this fan would not be monitored because it was similar to the opposite train FCU.

The licensee was generally meeting its Generic Letter 89-13 commitments for the EDG lube oil coolers, which were a water-to-oil heat exchanger. The only water-to-water heat exchanger was the component cooling water heat exchanger. In 2002, the licensee changed from a performance monitoring program to an inspect and clean program for these heat exchangers. Additionally, following the identification of lake grass in the safety injection pump lube oil coolers in January 2004, the licensee was implementing a new inspection method for the safety injection pump lube oil coolers; the acceptance criteria for monitoring performance of these heat exchangers appeared acceptable.

In 2003, an NRC inspector identified an issue with the accuracy of the instrumentation used in performance testing of the FCUs. As a result, the licensee switched, at least temporarily, to an inspect and clean program for these heat exchangers. The inspectors questioned the appropriateness of the licensees Generic Letter 89-13 commitment to monitor the 1B train FCU and assume that acceptable performance was indicative of acceptable performance of the 1A train FCU, given that the 1B FCU was cleaned in March 2004, while the 1A FCU was only flushed using an inadequate procedure. The inadequate procedure issue is more fully discussed in Section 4OA5.1.b.1. The licensee entered this concern into their corrective action program.

Additionally, the inspectors determined that the 1B CCW FCU was installed to meet an 10 CFR Part 50, Appendix R requirement, and that the 1B CCW pump room safety-related cooling was supplied by the auxiliary building mezzanine FCU. As this FCU did not perform a safety-related function, it appeared reasonable that it was not performance monitored under the GL 89-13 commitment.

Overall, the licensees current program for performing maintenance in lieu of testing for safety-related heat exchangers appeared to be acceptable to identify degraded conditions.

• The third recommendation was to establish a routine inspection and maintenance program to ensure that corrosion, erosion, protective coating failure, silting, and biofouling could not degrade the performance of the safety-related systems supplied by service water. The licensee committed to performing periodic inspections.

The periodic inspections continued to be performed, although the pipe inspections primarily addressed corrosion and silting aspects. In these areas, the licensee has identified piping sections where silt has been deposited and also where sufficient corrosion has occurred such that pipe replacements are necessary. Pipe cleaning and/or pipe replacements have been scheduled and completed such that overall system reliability has been maintained.

The inspectors identified some sections of piping downstream of flow control orifices which were not in the program, although turbulence downstream of orifices has resulted in piping erosion and pin holes at other plants. This was brought to the licensee's attention, but was considered minor because the piping was relatively new, such that erosion was not expected to have occurred. The licensee entered this issue into its corrective action program.

The inspectors determined that there were protective coatings applied to at least one safety-related heat exchanger. No problems were identified in this area.

• The fourth recommendation was to confirm that the service water system would perform its intended function in accordance with the licensing basis for the plant.

The licensee made no ongoing commitments for this recommendation.

The licensee has completed periodic self-assessments, which have identified various minor issues. Additionally, in 2000, Region III inspectors performed a safety system design and performance capability inspection with service water as the chosen system.

Four Non-Cited Violations were identified during that inspection, all of which were of very low safety significance.

The licensee maintained the design basis of the service water system; however, an issue regarding a modification to the service water system which appeared to introduce a single failure vulnerability was identified and is discussed in Section 4OA5.1.b.2.

Test procedures were adequate to demonstrate acceptable pump performance. The inspectors verified that, under different scenarios, the service water system could remove the safety-related heat loads. The inspectors also reviewed the set points for alarms and actuations to ensure that they were consistent with the design basis and assumptions. Overall, the licensees analyses of service water system scenarios were sufficient.

• The fifth recommendation was to confirm that maintenance practices, operating and emergency procedures, and training that involves the service water system were adequate to ensure that safety-related equipment cooled by the service water system would function as intended and that operators of this equipment would perform effectively. Similar to recommendation four, the licensee made no ongoing commitments in response to this recommendation.

In reviewing the maintenance work orders, the inspectors noted some instances in which the description of the problem was vague or the description of the action taken did not fully describe the work that as performed to correct the problem. This made it difficult for an independent observer to verify that the problem was corrected. However, overall, maintenance of the service water system was satisfactory. No issues were identified during the walkdown which indicated ongoing maintenance problems.

The inspectors identified an issue in regard to control and update of vendor manuals.

The licensee had identified, during a 2002 self-assessment, that vendor manuals were not being properly controlled and updated. The inspectors selected and requested four vendor manuals applicable to the service water system for review from the listing of vendor manuals in the plant library. Two of the four vendor manuals were properly filed in the library and were immediately available for review. Another vendor manual was located in the vendor manual library files under a different vendor name but with the given file number. However, the licensee was not able to locate a controlled copy of the vendor manual for an indicating lamp, although an uncontrolled copy was discovered in an engineers desk. Additionally, information regarding a selected component (the turbine building Service water header isolation valves) could not be located in the vendor manual which was supposed to contain the information. The inspectors also noted that the licensee had a backlog of over 200 vendor manual changes to incorporate, although not all of these related to service water components.

The licensee controlled the service water system based upon service water system pressure. If an annunciator indicated that Service water pressure was low, then operators manually started another Service water pump to increase the pressure and provide additional water. Throttle control valves were not used in the system and flow balancing of the Service water system was not considered necessary. Service water temperatures and flow were not monitored and recorded in operator logs.

Operating procedures were adequate to ensure control of the service water system, and the operators were appropriately trained. The inspectors identified a minor issue where one piece of equipment, necessary for operators to perform an abnormal procedural action, was not tracked to ensure that it would be available for the operators when required. The licensee entered this issue into its corrective action program.

iii.

Determine the effectiveness of programmatic maintenance of the actions in response to Generic Letter 89-13.

The licensee has maintained the actions to which its committed in its response to the Generic Letter. The overall program level has remained steady, with neither overall improvement nor reduction of commitments. However, the primary motivator for continued licensee actions appears to have been the continuing problems occurring in the service water system, followed by licensee response to NRC issues identified during baseline or special inspections.

iv.

As applicable, describe noteworthy service water system operational history that supports inspection results.

The most recent event involving the service water system was the discovery, in January 2004, that the SI lube oil coolers were clogged with lake grass. This event is described in special inspection report 05000305/2004003.

In March 2004, the licensee discovered excessive silting (over 85 percent of the pipe flow area) blocking the 1B SI stuffing box. Resolution of this issue has been delayed to the October 2004 outage due to a concern regarding safety injection unavailability time.

In April 2004, the licensee discovered zebra mussels in the 1A control rod drive motor FCU. The mussels were larger than the maximum size calculated to occur with effective annual chlorination.

v.

Provide an assessment of the effectiveness of licensees program procedure(s)on related service water system operating experience.

In regard to service water issues, the licensee appeared to have a healthy program for evaluating operating experience. Several of the operating experience documents showed a strong, questioning attitude towards ensuring that the issue either did not apply to Kewaunee, or that appropriate corrective actions were taken. In addition, the procedure for monitoring pipe erosion/corrosion and silting contained a requirement to perform a semi-annual review of all operating experience on the service water and fire protection systems to ensure that problems at other plants were captured at Kewaunee.

4OA6 Meetings

.1 Exit Meeting

On September 29, 2004, the resident inspectors presented the inspection results to Mr. T. Coutu and other members of licensee management, who acknowledged the findings. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meeting

Interim exit meetings were conducted for:

• Maintenance Effectiveness Periodic Evaluation with K. Davison, on April 24, 2004

• Emergency preparedness program and performance indicators inspection meeting with Mr. K. Hoops on July 2, 2004;

• Licensed Operator Requalification Training Program Inspection 71111.11B with Mr. K. Davison on July 16, 2004;

• Biennial Operator Requalification Program Inspection 71111.11B with Mr. D. Fitzwater on July 30, 2004, via telephone;

• Public radiation safety inspection for radiological environmental monitoring with Mr. K. Davison on August 6, 2004; and Service Water with Mr. T. Coutu on August 20, 2004.

• Temporary Inspection (TI 2515/159) on Generic Letter 89-13: Service Water with Mr. T. Coutu on August 20, 2004.

4OA7 Licensee-Identified Violations

The following violations of very low significance were identified by the licensee and are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Manual, NUREG-1600, for being dispositioned as a Non-Cited Violation.

1. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Drawings and Procedures,

requires, in part, that activities affecting quality shall be prescribed by documented instructions or procedures appropriate to the circumstances. In addition, instructions or procedures shall include appropriate acceptance criteria for determining that important activities have been satisfactorily accomplished. On July 8, 2004, while performing TS Surveillance Test SP-33-098A, Train A Safety Injection Pump and Valve Test - IST, Step 6.4.5, to verify open Valve RHR-299A, Valve RHR-299A failed to open. The licensee identified this failure in Condition Report CAP021806, RHR-299A Failed to Open During SP-33-098A, and performed an apparent cause evaluation. The licensee identified that while an auxiliary contact in the valve control circuit was closed, the auxiliary contact had a high resistance condition, which prevented the contact from operating properly. The licensees review of the 36-month preventive maintenance for Motor Operated Valves prescribed in Procedure GMP-239, Limitorque MOV Motor, Starter and Actuator Maintenance (QA-1), was last performed on Valve RHR-299A, June 9, 2004, and contained verification that contacts moved freely; however, the licensee identified that a resistance check of the auxiliary contacts was not prescribed n the procedure. The inspectors verified the failure of this valve was of very low significance and no common mode failure existed for the opposite train residual heat removal valve. The licensee revised Procedure GMP-239 to include a resistance check of the auxiliary contacts.

2. Title 10 CFR Part 50.65 (a)(4) requires, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities. The licensee identified on July 19, 27, and August 20, 2004, increased plant risk due to non-adherence by licensee work groups to the work schedule on those dates. Although the increased risk was identified in the licensees unscheduled overlap risk, which was part of the licensees work week assessment of risk, the licensees work groups did not coordinate the start and stop times of maintenance activities such that the increase in risk incurred due to overlap was managed. In all three licensee identified instances, the work overlaps resulted in increased risk for 15 to 30 minutes on those days. The licensee initiated Condition Reports CAP022073 and CAP022375, Increase Plant Risk Due to Non-Adherence to Work Schedule, and performed an apparent cause evaluation. The licensee subsequently implemented corrective actions for these issues which appeared to be effective, as evidenced by a lack of similar conditions in September 2004.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Nuclear Management Company, LLC

T. Coutu, Site Vice President

K. Hoops, Site Director

K. Davison, Plant Manager

L. Armstrong, Engineering Director

S. Baker, Radiation Protection Manager

J. Bennett, EP Instructor

A. Bolyen, QA Supervisor

J. Coleman, EP Manager

J. Egdorf, EP Supervisor

D. Fitzwater, Operations Training Supervisor

W. Flint, Chemistry Manager

D. Franson, Service Water System Engineer

L. Gerner, Licensing Supervisor

E. Gilson, Security Manager

W. Goder, Operations Training General Supervisor

G. Harrington, Licensing

W. Hunt, Training Manager

J. Ladewig, Site Maintenance Rule Coordinator

D. Lohman, Operations Manager

K. Peveler, Manager, Engineering Programs

J. Pollock, Design Engineering Manager

B. Presl, NMC Security Consultant

S. Putman, Maintenance Manager

A. Rahn, Service water and FAC Inspection Program Engineer

R. Repshas, Site Services Manager

J. Riste, Licensing Supervisor

D. Scherwinski, Training Instructor

T. Schmidli, Radiation Protection General Supervisor, Field Operations

J. Stoeger, Operations Training Supervisor

D. Scherwinski, Training Instructor

P. Sunderland, EP Coordinator

NRC Personnel

J. Cameron, Project Engineer

J. Lamb, Project Manager

T. McMurtray, Acting Project Manager

S. Reynolds, Acting Director, Division of Reactor Projects

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000305/2004007-01 NCV Green. 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. Failure to Promptly Correct Conditions Adverse to Quality, Specifically Associated with Degraded and Nonconforming Conditions (Section 1R15.1)

05000305/2004007-02 NCV Green. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Failure to Implement Procedures for Work on Safety-Related Equipment (Section 1R19.1)

05000305/2004007-03 NCV Green. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Failure to Have Procedures Appropriate to the Circumstances for Preventive Maintenance of the Turbine Driven Auxiliary Feedwater Pump Turbine (Section 4OA3.1)

05000305/2004007-04 NCV Green. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Failure to Have Acceptance Criteria for Flushing of the 1A RHR Fan Coil Unit (Section 4OA5.1b.1)

05000305/2004007-05 NCV Green. 10 CFR 50, Appendix B, Criterion III, Design Control. Failure to Verify the Acceptability of a Single Failure Vulnerability Introduced During a System Modification (Section 4OA5.1b.2)

Closed

05000305/2004004-02 URI Review of Final Analysis Concerning High Oil Particulate discovered in the Turbine Driven Auxiliary Feedwater Pump Turbine (Section 1R15.2)

05000305/2004007-01 NCV Green. 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. Failure to Promptly Correct Conditions Adverse to Quality, Specifically Associated with Degraded and Nonconforming Conditions (Section 1R15.1)

05000305/2004007-02 NCV Green. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Failure to Implement Procedures for Work on Safety-Related Equipment (Section 1R19.1)

05000305/2004007-03 NCV Green. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Failure to Have Procedures Appropriate to the Circumstances for Preventive Maintenance of the Turbine Driven Auxiliary Feedwater Pump Turbine (Section 4OA3.1)

05000305/2004007-04 NCV Green. 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. Failure to Have Acceptance Criteria for Flushing of the 1A RHR Fan Coil Unit (Section 4OA5.1b.1)

05000305/2004007-05 NCV Green. 10 CFR 50, Appendix B, Criterion III, Design Control. Failure to Verify the Acceptability of a Single Failure Vulnerability Introduced During a System Modification (Section 4OA5.1b.2)

Discussed

None.