IR 05000255/2009003

IR 05000255-09-003 on 04/01/2009 - 06/30/2009 for Palisades Power Plant

ML092180936
Person / Time
Site:	Palisades
Issue date:	08/06/2009
From:	Jack Giessner Reactor Projects Region 3 Branch 4
To:	Schwarz C Entergy Nuclear Operations
References
EA-06-178 IR-09-003
Download: ML092180936 (53)

Text

UNITED STATES ust 6, 2009

SUBJECT:

PALISADES NUCLEAR PLANT INTEGRATED INSPECTION REPORT 05000255/2009003

Dear Mr. Schwarz:

On June 30, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palisades Nuclear Plant. The enclosed inspection report documents the inspection results, which were discussed on June 30, 2009, with yourself and other members of your staff.

This inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's 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 two findings of very low safety significance (Green)

were NRC identified. One of the findings did not involve a violation of NRC requirements.

Additionally, two licensee-identified violations which were determined to be of very low safety significance are listed in this report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC 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 a copy 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 Resident Inspector Office at the Palisades Nuclear Plant. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Palisades Nuclear Plant. The information that you provide will be considered in accordance with Inspection Manual Chapter 0305. 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), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

John B. Giessner, Chief Branch 4 Division of Reactor Projects Docket No. 50-255 License No. DPR-20 Enclosure: Inspection Report 05000255/2009003 w/Attachment: Supplemental Information cc w/encl: Senior Vice President Vice President Oversight Senior Manager, Nuclear Safety & Licensing Senior Vice President and COO Assistant General Counsel Manager, Licensing W. DiProfio W. Russell G. Randolph Supervisor, Covert Township Office of the Governor T. Strong, State Liaison Officer Michigan Department of Environmental Quality Michigan Office of the Attorney General

SUMMARY OF FINDINGS

IR 05000255/2009003; 04/01/2009 - 06/30/2009; Palisades Power Plant; Maintenance Risk

Assessments and Emergent Work Control, Outage Activities.

The inspection was conducted by resident and regional inspectors. The report covers a 3-month period of resident inspection. Two green findings, one of which has an associated non-cited violation (NCV), were identified. In addition, there were two licensee identified violation. The significance of most findings is indicated by their color (Green, White, Yellow,

Red) using Inspection Manual Chapter (IMC) 0609 Significance Determination Process (SDP).

Cross-cutting aspects were determined using IMC 0305, "Operating Reactor Assessment Program." Findings for which the SDP does not apply may be "Green," or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated July 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low safety significance (Green)without an associated NCV for failure to conduct an adequate risk assessment and recognize a procedurally-required orange risk condition for the vacuum fill of the primary coolant system (PCS) during outage activities. In response to this issue, the licensee changed their risk assessment before performing the vacuum fill evolution.

The licensee entered this issue into their corrective action program as Condition Report (CR)-PLP-2009-02079.

The finding is more than minor in accordance with IMC 0612, Appendix E,

Example 7.e, because the planned evolution would have put the plant into a higher risk category per procedure GOP- 14 Attachment 19. In addition, if left uncorrected, the issue had the potential to lead to a more significant safety concern.

The inspectors determined the finding impacted the Initiating Events cornerstone whose objective is to, in part, limit those events that upset plant stability. Using IMC 0609, Appendix M, this finding is of very low safety significance (Green)because the licensee performed the risk management actions for the orange risk condition prior to performing the orange risk evolution. The inspectors concluded that this finding has a cross-cutting aspect in the area of human performance, Work Control (H.3 (a)), because the licensee did not appropriately plan the work activities by properly incorporating risk insights by following the requirements of procedure GOP-14. (1R13)

Green.

The inspectors identified a Green NCV of 10 CFR 50.65 (a)(4) for the licensees failure to manage the increase in risk by minimizing the plants exposure to elevated risk during the 1R20 refueling outage. Specifically, during the first period of reduced inventory after shutdown with a reduced time-to-boil, the licensees failure to appropriately manage and execute maintenance activities led to extended time being spent in the reduced inventory condition. Later in the outage, two unplanned entries into reduced inventory were required to diagnose and correct issues stemming from the D Primary coolant pump impeller replacement. The licensee entered this issue into their corrective action program as Condition Report (CR)-PLP-2009-03392.

The inspectors determined that a significant portion of the additional time spent in reduced inventory was within licensee control. The issue is greater than minor in that the licensee failed to manage activities in such a way as to minimize the time spent in reduced inventory. The inspectors determined the finding impacted the Initiating Events cornerstone whose objective is to, in part, limit those events that upset plant stability. The finding is of very low safety significance (Green) using Appendix M because it did not involve a loss of control nor did it require a quantitative analysis per IMC 0609 Appendix G, Attachment 1. The inspectors concluded that this finding has a cross-cutting aspect in the area of human performance because a primary cause of the finding is associated with the human performance cross-cutting component of work practices, in that the licensee failed to provide appropriate oversight for work activities consistent with nuclear safety.

(H.4(c))(1R20)

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period shutdown in a refueling outage. On April 28, the licensee took the reactor critical. Due to a failed control rod drive mechanism, the licensee returned to mode 3 the same day. After repairs, the licensee again started the plant and entered mode 1 on April 30. The licensee ascended in power reaching 100 percent on May 4. The plant remained at or near 100 percent power for the remainder of the inspection period.

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

• The coordination between the TSO and the plant during off-normal or emergency events;

• The explanations for the events;

• The estimates of when the offsite power system would be returned to a normal state; and

• The notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

• The actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;

• The compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;

• A re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and

• The communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

Documents reviewed are listed in the attachment to this report. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures.

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• Redundant Train of Containment Spray during Maintenance;

• Service Water during Outage Surveillance Testing; and

• High Pressure Safety Injection (HPSI) during Maintenance.

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), CRs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions.

The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment.

These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings of significance were identified

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On June 22, 2009 the inspectors performed a complete system alignment inspection of the critical service water system to verify the functional capability of the system. This system was selected because it was considered both safety-significant and risk-significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment.

These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• 1-2 Emergency Diesel Generator Room/Fire Area 6;

• Service Water Screenhouse/Fire Area 9;

• Component Cooling Water Room/Fire Area 16; and

• West Engineering Safeguards Room/Fire Area 28.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed, that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

These activities constituted four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings of significance were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the component cooling water heat exchangers to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees test results for the component cooling water heat exchanger as compared against acceptance criteria and visually inspected the interior of the heat exchanger to verify the state of cleanliness. Documents that were reviewed for this inspection are listed in the Attachment to this document.

This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

From March 30, 2009 through April 9, 2009, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, steam generator tubes, emergency feedwater systems, risk significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4, and 1R08.5 below constituted one inservice inspection sample as defined in IP 71111.08-05.

.1 Piping Systems Inservice Inspection

a. Inspection Scope

The inspectors observed and reviewed records of the following nondestructive examinations mandated by the American Society of Mechanical Engineers (ASME)

Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements and if any indications and defects detected were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC approved alternative requirement.

• Ultrasonic Examination of Feedwater Pipe to Nozzle Weld FWS-18-FWL-2SI-262 (Report No. UT-09-022); and

• Magnetic Particle Examination of Feedwater Pipe to Nozzle Weld FWS-18-FWL-2SI-262 (Report No. MT-09-007).

The inspectors reviewed records of the following nondestructive examinations conducted as part of the licensees industry initiative inspection program for primary water stress corrosion cracking to determine if the examination was conducted in accordance with the licensees augmented inspection program, industry guidance documents and associated licensee examination procedures and if any indications and defects were detected, to determine if these were dispositioned in accordance with approved procedures and NRC requirements.

• Liquid Penetrant Examination of Pressurizer Bottom Nozzle to Safe-End weld PCS-12-PSL-1H1-1 (Report No. PT-09-121);

• Visual Examination of Pressurizer Safe-End to Pipe weld PZR-003 -2 (Report No. VT-09-004);

• Visual Examination of PCS Pipe top Nozzle weld PCS-2-CAL-2A1-48 (Report No. VT-09-082); and

• Ultrasonic Examination of PCS Butt Elbow to Pipe weld

• PCS-12-SDC-2H1-1 (Report No. UT-09-025).

During non-destructive surface and volumetric examinations performed since the previous refuelling outage, the licensee had not identified any recordable indications.

Therefore, no NRC review was completed for this inspection procedure attribute.

The licensee had not performed pressure boundary welding since the beginning of the previous refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings of significance were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the vessel head, a bare metal visual examination and a non-visual examination was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors reviewed the examination record (Report No. VT-09-124) of the visual examination conducted on the reactor vessel head to determine if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed that;

• the required visual examination scope/coverage was achieved and limitations (if applicable were recorded) in accordance with the licensee procedures;

• the licensee criteria for visual examination quality and instructions for resolving interference and masking issues were adequate; and

• if indications of potential through-wall leakage were identified, the licensee entered the condition into the corrective action system and implemented appropriate corrective actions.

The inspectors observed and reviewed records of the automated ultrasonic examinations conducted on the reactor vessel head at penetration CRDM8 to determine if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed that:

• the required examination scope (volumetric and surface coverage) was achieved and limitations (if applicable were recorded) in accordance with the licensee procedures;

• the ultrasonic examination equipment and procedures used were demonstrated by blind demonstration testing;

• if indications or defects were identified, the licensee documented the conditions in examination reports and/or entered this condition into the corrective action system and implemented appropriate corrective actions; and

• if indications were accepted for continued service the licensee evaluation and acceptance criteria were in accordance with the ASME Section XI Code, 10 CFR 50.55a(g)(6)(ii)(D) or an NRC approved alternative.

The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

On March 22 and 23, 2009, the inspectors observed and reviewed records of the licensees initial Boric Acid Corrosion Control visual examinations and verified whether these visual examinations emphasized locations where boric acid leaks can cause degradation of safety significant components.

The inspectors reviewed the following licensee evaluations of reactor coolant system components with boric acid deposits to determine if degraded components were documented in the corrective action system. The inspectors also evaluated corrective actions for any degraded reactor coolant system components to determine if they met the component Construction Code, ASME Section XI Code, and/or NRC approved alternative.

• Evaluation No. 09-1-0014, Component P-74 Safety Injection Refueling Water Tank Recirculation Pump; and

• Engineering Evaluation of Degraded Conditions, CV-1902, Pressurizer Liquid Phase Sample.

The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

• CR-PLP-2007-05261, Results of 1R19, Engineering As-Left Mode 3 Walkdown; and

• CR-PLP-2007-05256, Leakage at Primary Coolant Pump P-50C Casing Flange.

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET data analysts, reviewed the in-situ pressure testing of steam generator B tube R72C107, and reviewed documentation related to the Steam Generator (SG) ISI program to determine if:

• in-situ SG tube pressure testing screening criteria used were consistent with those identified in the Electric Power Research Institute (EPRI) TR-107620;

• Steam Generator In-Situ Pressure Test Guidelines and that these criteria were properly applied to screen degraded SG tubes for in-situ pressure testing;

• in-situ pressure test records demonstrated pressure and hold times consistent with EPRI TR-107620, In-situ Pressure Test Guidelines;

• in-situ pressure test results were properly applied to SG tube integrity performance criteria identified in EPRI TR-107621;

• the numbers and sizes of SG tube flaws/degradation identified was bound by the licensees previous outage Operational Assessment predictions;

• the SG tube ET examination scope and expansion criteria were sufficient to meet the TSs, and the EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• the SG tube ET examination scope included potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to these SG tubes;

• the licensee identified new tube degradation mechanisms and implemented adequate extent of condition inspection scope and repairs for the new tube degradation mechanism;

• the licensee implemented repair methods which were consistent with the repair processes allowed in the plant TS requirements and to determine if qualified depth sizing methods were applied to degraded tubes accepted for continued service;

• the licensee implemented an appropriate plug on detection tube repair threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);

• the licensee primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons-per-day or the detection threshold during the previous operating cycle;

• the ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6; and

• the licensee performed secondary side SG inspections for location and removal of foreign materials.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI/SG related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if;

• the licensee had established an appropriate threshold for identifying ISI/SG related problems;

• the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

• the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On May 12, 2009, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• the ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk significant systems:

• Safety Injection Tanks

• Auxiliary Feedwater System The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verification of appropriate performance criteria for structures, systems, and components/functions classified as (a)(2) or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the attachment to this report.

This inspection constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Elevated risk due to reduced inventory;

• Risk associated with vacuum fill of the PCS;

• Service water pump C replacement; and

• Yellow risk do to HPSI valve maintenance These activities were selected based on their potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

These maintenance risk assessments and emergent work control activities constituted four samples as defined in IP 71111.13-05.

b. Findings

Introduction:

The inspectors identified a Green Finding without an associated violation for failure to perform an adequate risk assessment for the vacuum fill of the PCS in that the licensee failed to recognize that their procedure for risk management required entry into orange risk during outage activities.

Description:

On April 14, 2009, as part of the outage activities, the inspectors reviewed the preparations to vacuum fill the PCS scheduled to occur in the evening of April 14.

During this evolution, a vacuum of 25 in Hg would be established in the PCS. As part of the evolution, the licensee drained the PCS to 619 feet which eliminated the SGs as a method for decay heat removal.

When the inspectors reviewed the risk assessment for the evolution they noted that the licensee categorized the condition as Yellow Risk using procedure GOP-14 19 Palisades Shutdown Safety Risk Assessment Section 7.2.c. The inspectors determined that the licensee had not considered the reduction in the boiling point of the PCS with the PCS at vacuum. During the evolution, the licensee established a maximum PCS temperature of 130 F. At the pressure and temperature bands in use, the PCS could be within 10 minutes of boiling upon loss of cooling. At these short times to core boiling, the procedure would require entry into orange risk. Prior to the evolution, the inspectors discussed the concern with the licensee and the licensee agreed that GOP-14 required entry into orange risk. The licensee implemented the risk management actions for the orange risk condition prior to drawing a vacuum on the PCS.

The licensee entered orange risk for reduced inventory on April 14, 2009 at 21:45 and exited it at 08:25 on April 15, 2009 when PCS level increased above 623 feet.

Analysis:

The inspectors determined that the failure to conduct an adequate risk assessment and recognize a procedurally-required orange risk for the vacuum fill of the PCS was a performance deficiency and a finding warranting a significance evaluation.

This finding was determined to be more than minor using Inspection Manual Chapter (IMC) 0612, Appendix E, Example 7.e, because the planned evolution would have put the plant into a higher risk category per Procedure GOP 14, Attachment 19. In addition, if left uncorrected, the issue had the potential to lead to a more significant safety concern. The inspectors determined the finding impacted the Initiating Events cornerstone whose objective is to, in part, limit those events that upset plant stability due the potential to lose decay heat removal.

The inspectors assessed the finding using IMC 0609 Appendix M, "Significance Determination Process Using Qualitative Criteria," because neither IMC 0609 Appendix G, "Shutdown Operations Significance Determination Process" nor IMC 0609 Appendix K, "Maintenance Risk Assessment and Risk Management Significance Determination Process" applied to findings involving inadequate qualitative maintenance risk assessments for shutdown plant conditions. The finding was determined to be of very low safety significance (Green) because the licensee properly classified the shutdown risk plant condition in accordance with GOP-14 after the inspector identified that the existing maintenance risk assessment for the upcoming vacuum fill evolution was incorrect. Additionally the inspectors determined that the finding had a cross-cutting aspect in the area of human performance. Specifically, the licensee did not appropriately plan the work activities by properly incorporating risk by following the requirements of the procedures (H.3(a)).

Enforcement:

Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement. The finding is a performance deficiency because the licensee failed to meet requirements of procedure GOP-14, Shutdown Cooling Operations, in that the licensee did not intend to enter orange risk when time to boil was less than 20 minutes. In addition, the licensees risk profile for the outage was inaccurate in that it did not show the vacuum fill evolution as an orange risk condition. Once the inspectors informed the licensee that their planned action was contrary to procedural requirements, the licensee changed their risk profile to conform to the requirements of GOP-14. Because the finding does not involve a violation of regulatory requirements, has been entered into the corrective action program (CR-PLP-2009-02079) and has very low safety significance, it is identified as FIN-05000255/2009003-01, Failure to Conduct an Adequate Risk Assessment for an Orange Risk Condition.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• P-7C Operability after not meeting minimum required flow acceptance criteria;

• HPSI Operability after exceeding maximum flow criteria;

• 1-1 EDG Based on service water flow verification test results;

• PCS with change in allowed vent path during reduced inventory;

• control rods 18 and 38 due to lack of movement;

• control room HVAC with refrigerant leak; and

• loose connection in safety injection logic discovered during containment high pressure testing.

The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This operability inspection constituted seven samples as defined in IP 71111.15-05

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

.1 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification(s):

• Installation of a vacuum fill system

• Temporary power for the instrument AC bus The inspectors compared the temporary configuration changes and associated 10 CFR 50.59 screening and evaluation information against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors also compared the licensees information to operating experience information to ensure that lessons learned from other utilities had been incorporated into the licensees decision to implement the temporary modification. The inspectors, as applicable, performed field verifications to ensure that the modifications were installed as directed; the modifications operated as expected; modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. Lastly, the inspectors discussed the temporary modification with operations, engineering, and training personnel to ensure that the individuals were aware of how extended operation with the temporary modification in place could impact overall plant performance.

This inspection constituted two temporary modification samples as defined in IP 71111.18-05.

b. Findings

No findings of significance were identified.

.2 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed the following permanent modification(s):

• EC 12249, Replacement of the Containment Sump Strainer Modules The inspectors followed up on the corrective actions taken by the licensee in response to the Generic Letter 2004-02, Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis Accidents at Pressurized Water Reactors. As a result of this Generic Letter, the licensee implemented modifications, conducted tests and analyses, and revised procedures in order to address their particular concerns.

An initial review of the licensees corrective actions was conducted using Temporary Instruction (TI) 2515/166, Potential Impact of Debris Blockage on Emergency Recirculation during Design Basis Accidents at Pressurized Water Reactors. The results of this inspection were documented in Inspection Report 05000255/2008003.

As documented in Inspection Report 05000255/2008003, there were several corrective actions that were not completed by the end of the inspection period. The licensee requested an extension to the due date in order to complete these outstanding items.

By letter dated June 26, 2008, the NRC granted this request by allowing the licensee to complete these actions prior to restart from the 2009 refueling outage.

The inspectors verified the completion of the following outstanding items:

• Installation of the new permanent modification of the sump strainer assemblies;

• combined debris and chemical head loss testing;

• downstream effects evaluation of emergency core cooling system components;

• debris transport analysis; and

• net positive suction head analysis.

This inspection constituted one permanent modification sample as defined in IP 71111.18.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance (PM) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Sump strainer following replacement;

• D primary coolant pump following replacement;

• CRD 38 following repair and troubleshooting

• PCS valves following maintenance

• pressurizer B controller power supply

• HPSI breaker maintenance; These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion), and test documentation was properly evaluated. The inspectors evaluated the activities against TS, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted six testing samples as defined in IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Refueling Outage (RFO), conducted March 22 thru May 2, 2009, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. Portions of this inspection were performed in the first quarter of 2009 because the RFO started in the first quarter. During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below. Documents reviewed during the inspection are listed in the Attachment to this report.

• Licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TS when taking equipment out-of-service.

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

• Controls over the status and configuration of electrical systems to ensure that TS and OSP requirements were met, and controls over switchyard activities.

• Monitoring of decay heat removal processes, systems, and components.

• Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

• Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

• Controls over activities that could affect reactivity.

• Maintenance of secondary containment as required by TS.

• Refueling activities, including fuel handling and sipping to detect fuel assembly leakage.

• Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing.

• Licensee identification and resolution of problems related to RFO activities.

This inspection constituted one RFO sample as defined in IP 71111.20-05.

b. Findings

Introduction:

The inspectors identified a green NCV of 10 CFR 50.65 (a)(4) for the licensees failure to manage risk during the time spent in reduced inventory (a condition which elevates plant risk) during the 1R20 refueling outage. Controllable delays in performing activities in support of the first reduced inventory period combined with the extra entries required to support D primary coolant pump work later in the outage resulted in extended time spent in elevated risk conditions.

Description:

On March 26, 2009, during the 1R20 refueling outage, the licensee entered their first planned reduced inventory condition. The licensee planned to spend 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br /> in reduced inventory and included work items to remove the D primary coolant pump motor and install steam generator nozzle dams. Reduced inventory places the plant in an orange risk condition with a short time to boil and part of the risk management of the elevated risk was minimizing time in reduced inventory. However, the licensee spent 38 hours4.398148e-4 days <br />0.0106 hours <br />6.283069e-5 weeks <br />1.4459e-5 months <br /> in reduced inventory. The inspectors reviewed the cause of the time extension in reduced inventory and indentified several delays that were within the licensees ability to foresee and correct. The delays included:

• Failure to provide power to high efficiency particulate air units required to support nozzle dam installation

• Removal of a temporary power supply supporting nozzle dam installation

• Failure to validate worker qualifications for steam generator work prior to entering reduced inventory The inspectors concluded that about half of the extended time in reduced inventory could be attributed to delays under the licensees control. The inspectors also noted that the licensee did not write a condition report to evaluate the extended time in reduced inventory until June.

The licensee scheduled a second period of reduced inventory to remove SG nozzle dams and complete installation of the new D Primary Coolant Pump. Although this entry occurred with minimal delays, after exiting reduced inventory, the licensee discovered the Primary Coolant Pump D could not rotate freely by hand. The licensee used a Kepner-Tregoe process to troubleshoot the issue and correct the problem. As part of the process, the licensee entered reduced inventory to check the pump seals and other portions of the pump. During this entry, the licensee discovered that the pump and motor were not properly aligned. Although the licensee corrected this condition, the pump could still not be rotated by hand. Another reduced inventory period was required, and during this time the licensee removed and inspected the auxiliary impeller. This inspection revealed that the impeller was rubbing on the pump cavity wall thus preventing free rotation. The licensee machined the auxiliary impellor to eliminate the rubbing. A subsequent root cause by the licensee determined that the manufacturer had modified the inner diameter of the auxiliary impeller without a proper evaluation of the change. The vendor did not write non-conformance reports nor did licensee personnel assigned to observe vendor performance provide sufficient oversight of the vendor. For the misalignment, the licensee determined that the quality control inspector failed to ensure test equipment remained functional.

Analysis:

The failure of the licensee to plan and execute work activities in a manner that would minimize the time spent in a high risk reduced inventory condition was a performance deficiency warranting further assessment with IMC 0612, Power Reactor Inspection Reports. Minimizing time at higher risk conditions is a key risk management action. The issue was not similar to any of the maintenance rule implementation examples in IMC 0612 Appendix E, Examples of Minor Issues, due to plant risk being assessed qualitatively for the shutdown condition that existed. The inspectors then used IMC 0612 Appendix B, Issue Screening, and determined that Section 1-3 question 5(i)applied in that there was ineffective management of measures to reduce plant risk. As a result, the issue was more than minor.

The inspectors initially evaluated the finding using IMC 0609 Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process; however, it was determined that this appendix did not apply based on the qualitative risk assessment used by the licensee. Therefore, the inspectors utilized IMC 0609 Appendix M and used risk insights available in conjunction with NRC Management Review. The review utilized information in IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, and determined the finding impacted checklist #3 item 1 under Procedures/Training based on the extended time in reduced inventory. The finding screened as very low safety significance (Green)because the finding did not represent a loss of control nor did it require a Phase 2 or Phase 3 analysis. The inspectors determined the finding impacted the Initiating Events cornerstone whose objective is to, in part, limit those events that upset plant stability.

A contributing cause of the finding was associated with the human performance cross-cutting component of work practices, in that the licensee failed to provide appropriate supervisory oversight consistent with nuclear safety. Specifically, ineffective oversight caused the plant to remain in reduced inventory (an elevated risk period) for a longer time than scheduled (H.4(c)).

Enforcement:

10 CFR 50.65 (a)(4) requires, in part, that before performing maintenance activities (including but not limited to surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

As part of risk management strategies, the licensee stipulates in their GOP-14 procedure that the time spent in reduced inventory shall be minimized. Contrary to the above, during 1R20 (March 22, 2009, thru May 2, 2009) the licensee failed to manage the risk associated with multiple entries into reduced inventory. Specifically, the licensee failed to manage the first reduced inventory such that the licensee unnecessarily spent additional time in reduced inventory. Further, the licensee failed to manage construction and assembly of the D primary coolant pump such that additional entries into reduced inventory were required to properly assemble the D primary coolant pump. Because this violation was of very low safety significance and it was entered into the licensees corrective action program as CR-PLP-2009-03392, this violation is being treated as NCV 5000255/2009003-02, Failure to Manage Risk in Reduced Inventory, consistent with the NRC Enforcement Policy.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• RO-32, local leak rate test, isolation valve testing;

• QO-16, IST containment spray;

• QI-5, Containment High Pressure Test; and

• RT-8D Engineered Safeguards System Testing.

The inspectors observed in plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency were in accordance with TSs, the UFSAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted two routine surveillance testing samples, one inservice testing sample, and one containment isolation valve sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1 Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys in the following radiologically significant work areas within radiation areas, high radiation areas, and airborne radioactivity areas in the plant to determine if radiological controls including surveys, postings, and barricades were acceptable:

• Auxiliary Building;

• Containment Building; and

• Spent Fuel Pool Area.

This inspection constitutes one sample as defined in IP 71121.01-5.

The inspectors reviewed the radiation work permits (RWPs) and work packages used to access these areas and other high radiation work areas. The inspectors assessed the work control instructions and control barriers specified by the licensee. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. The inspectors interviewed workers to verify that they were aware of the actions required if their electronic dosimeters noticeably malfunctioned or alarmed.

This inspection constitutes one sample as defined in IP 71121.01-5.

The inspectors walked down and surveyed (using an NRC survey meter) these areas to verify that the prescribed Radiation Work Permit (RWP), procedure, and engineering controls were in place; that licensee surveys and postings were complete and accurate; and that air samplers were properly located.

This inspection constitutes one sample as defined in IP 71121.01-5.

The inspectors reviewed RWPs for airborne radioactivity areas to verify barrier integrity and engineering controls performance (e.g., high-efficiency particulate air ventilation system operation) and to determine if there was a potential for individual worker internal exposures in excess of 50 millirem committed effective dose equivalent.

Work areas having a history of, or the potential for, airborne transuranics were evaluated to verify that the licensee had considered the potential for transuranic isotopes and had provided appropriate worker protection.

This inspection constitutes one sample as defined in IP 71121.01-5.

The inspectors also reviewed the licensees physical and programmatic controls for highly activated and/or contaminated materials (non-fuel) stored within the spent fuel pool or other storage pools.

This inspection constitutes one sample as defined in IP 71121.01-5.

b. Findings

No findings of significance were identified.

.2 Job-In-Progress Reviews

a. Inspection Scope

The inspectors observed the following four jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers:

• Control Rod Drive Seal Housing Rebuild;

• Upper Guide Structure Platform Installation;

• Control Rod Drive 21 Extension Removal; and

• In-Core Instrumentation Cutting and Removal.

The inspectors reviewed radiological job requirements for these activities, including RWP requirements and work procedure requirements, and attended as-low-as-is-reasonably-achievable (ALARA) job briefings.

This inspection constitutes one sample as defined in IP 71121.01-5.

Job performance was observed with respect to the radiological control requirements to assess whether radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors evaluated the adequacy of radiological controls, including required radiation, contamination, and airborne surveys for system breaches; radiation protection job coverage, including any applicable audio and visual surveillance for remote job coverage; and contamination controls.

This inspection constitutes one sample as defined in Inspection Procedure 71121.01-5.

The inspectors reviewed radiological work in high radiation work areas having significant dose rate gradients to evaluate whether the licensee adequately monitored exposure to personnel and to assess the adequacy of licensee controls. These work areas involved areas where the dose rate gradients were severe; thereby increasing the necessity of providing multiple dosimeters or enhanced job controls.

This inspection constitutes one sample as defined in IP 71121.01-5.

b. Findings

No findings of significance were identified.

.3 High Risk Significant, High Dose Rate, High Radiation Area and Very High Radiation Area

Controls

a. Inspection Scope

The inspectors conducted plant walkdowns to assess the posting and locking of entrances to high dose rate high radiation areas and very high radiation areas.

This inspection constitutes one sample as defined in IP 71121.01-5.

b. Findings

No findings of significance were identified

.4 Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation safety work requirements. The inspectors evaluated whether workers were aware of any significant radiological conditions in their workplace, of the RWP controls and limits in place, and of the level of radiological hazards present. The inspectors also observed worker performance to determine if workers accounted for these radiological hazards.

This inspection constitutes one sample as defined in IP 71121.01-5.

b. Findings

No findings of significance were identified.

.5 Radiation Protection Technician Proficiency

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation protection technician performance with respect to radiation safety work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

This inspection constitutes one sample as defined in Inspection Procedure 71121.01-5.

b. Findings

No findings of significance were identified.

2OS2 As-Low-As-Is-Reasonably-Achievable Planning And Controls (71121.02)

.1 Inspection Planning

a. Inspection Scope

The inspectors reviewed plant collective exposure history, current exposure trends, and ongoing and planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants current 3-year rolling average for collective exposure in order to help establish resource allocations and to provide a perspective of significance for any resulting inspection finding assessment.

This inspection constituted one required sample as defined in IP 71121.02-5.

The inspectors reviewed the outage work scheduled during the inspection period and associated work activity exposure estimates for work activities which were likely to result in the highest personnel collective exposures.

This inspection constituted one required sample as defined in IP 71121.02-5.

The inspectors reviewed procedures associated with maintaining occupational exposures ALARA and processes used to estimate and track work activity specific exposures.

This inspection constituted one required sample as defined in IP 71121.02-5.

b. Findings

No findings of significance were identified.

.2 Job Site Inspections and ALARA Control

a. Inspection Scope

The inspectors observed the following jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas to evaluate work activities that presented the greatest radiological risk to workers:

• Control Rod Drive Seal Housing Rebuild;

• Upper Guide Structure Platform Installation;

• Control Rod Drive 21 Support Tube Removal; and

• In-Core Instrumentation Cutting and Removal.

The inspectors reviewed the licensees use of ALARA controls for the work activities.

The licensees use of engineering controls to achieve dose reductions was evaluated to verify that procedures and controls were consistent with the licensees ALARA reviews, that sufficient shielding of radiation sources was provided, and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding.

This inspection constituted one required sample as defined in IP 71121.02-5.

Job sites were observed to determine if workers used low dose waiting areas and if workers were effective in maintaining their doses ALARA by moving to the low dose waiting area when subjected to temporary work delays.

This inspection constituted one optional sample as defined in IP 71121.02-5.

The inspectors attended work briefings and observed ongoing work activities to determine if workers received appropriate on-the-job supervision to ensure the ALARA requirements are met. The inspectors assessed whether the first-line job supervisor ensured that the work activity was conducted in a dose efficient manner by minimizing work crew size and by ensuring that workers were properly trained and that proper tools and equipment were available when the job started.

This inspection constituted one optional sample as defined in IP 71121.02-5.

b. Findings

No findings of significance were identified.

.3 Radiation Worker Performance

a. Inspection Scope

Radiation worker and radiation protection technician performance was observed during work activities being performed in radiation areas, airborne radioactivity areas, and high radiation areas that presented the greatest radiological risk to workers. The inspectors evaluated whether workers demonstrated the ALARA philosophy by being familiar with the scope of the work activity and tools to be used, by utilizing ALARA low dose waiting areas, and by complying with work activity controls. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to the radiological hazards and the work involved.

This inspection constituted one required sample as defined in IP 71121.02-5.

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

.1 Inspection Planning and Identification of Instrumentation

a. Inspection Scope

The inspectors reviewed the licensees UFSAR to identify applicable radiation monitors associated with measuring transient high and very high radiation areas, including those intended for remote emergency assessment. The inspectors identified the types of portable radiation detection instrumentation that were used for job coverage of high radiation area work, including instruments for underwater surveys, portable and fixed area radiation monitors that were used to provide radiological information in various plant areas, and continuous air monitors that were used to assess airborne radiological conditions and work areas with the potential for workers to receive a 50 millirem or greater committed effective dose equivalent. Whole body counters that were used to monitor for internal exposure and those radiation detection instruments that were used to conduct surveys for the release of personnel and equipment from the radiologically controlled area, including contamination monitors and portal monitors, were also identified.

This inspection constituted two samples as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

.2 Calibration and Testing of Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors reviewed radiological instrumentation to determine if it had been calibrated as required by the licensees procedures, consistent with industry and regulatory standards. The inspectors also reviewed alarm setpoints for selected instruments to determine whether they were established consistent with the UFSAR or TSs, as applicable, and with industry practices and regulatory guidance. Specifically, the inspectors reviewed calibration procedures and the most recent calibration records for the following radiation monitoring instrumentation and calibration equipment:

• Survey meters with ion chambers;

• Survey meters with Geiger-Muller tubes;

• Air Samplers; and

• Personnel Contamination Monitors.

The inspectors observed the licensees use of the portable survey instrument calibration units, discussed calibrator output validation methods, and compared calibrator exposed readings with calculated/expected values. The inspectors evaluated compliance with licensee procedures while radiation protection (RP) personnel demonstrated the methods for performing source checks of portable survey instruments and source checks of personnel contamination and portal monitors.

This inspection constitutes a partial sample as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors reviewed licensee corrective action program documents and any Licensee Event Reports or special reports that involved personnel contamination monitor alarms due to personnel internal exposures to determine whether identified problems were entered into the corrective action program for resolution.

While no internal exposure with a committed effective dose equivalent greater than 50 millirem occurred since the last inspection in this area, the inspectors reviewed the licensees methods for internal dose assessment to determine if affected personnel would be properly monitored using calibrated equipment and if the data would be analyzed and exposures properly assessed.

This inspection constituted one sample as defined in IP 71121.03-5.

The inspectors reviewed corrective action program reports related to exposure significant radiological incidents that involved radiation monitoring instrument deficiencies since the last inspection in this area, as applicable. Members of the RP staff were interviewed and corrective action documents were reviewed to determine whether follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:

• 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;

• Resolution of NCVs tracked in the corrective action system; and

• Identification and implementation of effective corrective actions.

This inspection constituted one sample as defined in IP 71121.03-5.

The inspectors determined if the licensees self-assessment and audit activities completed for the approximate 2-year period that preceded the inspection were identifying and addressing repetitive deficiencies or significant individual deficiencies in problem identification and resolution, as applicable.

This inspection constituted one sample as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

.4 Radiation Protection Technician Instrument Use

a. Inspection Scope

The inspectors verified that calibrations for those survey instruments used to perform job coverage surveys and for those currently designated for use had not lapsed. The inspectors determined if response checks of portable survey instruments and checks of instruments used for unconditional release of materials and workers from the radiologically controlled area were completed prior to instrument use, as required by the licensees procedure. The inspectors also discussed instrument calibration methods and source response check practices with RP staff and observed staff demonstrate instrument source checks.

This inspection constituted one sample as defined in IP 71121.03-5.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Specific Activity

a. Inspection Scope

The inspectors sampled licensee submittals for the Reactor Coolant System (RCS)

Specific Activity performance indicator for the period from the second quarter 2008 through the first quarter of 2009. To determine the accuracy of the Performance Indicator (PI) data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees RCS chemistry samples, TS requirements, issue reports, event reports and NRC Integrated Inspection Reports for the period of the second quarter 2008 through the first quarter of 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified. In addition to record reviews, the inspectors observed a chemistry technician obtain and analyze a reactor coolant system sample. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one reactor coolant system specific activity sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.2 Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent

Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent TS (RETS)/Offsite Dose Calculation Manual (ODCM) Radiological Effluent Occurrences performance indicator for the period of the second quarter 2008 through the first quarter of 2009. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between the second quarter of 2008 through the first quarter of 2009 to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RETS/ODCM radiological effluent occurrences sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.3 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours PI for the period from the first quarter 2008 through the first quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Inspection Reports for the period of January 1, 2008, through March 31, 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. The licensee corrected one error effecting hours critical. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one unplanned scrams per 7000 critical hours sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.4 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications performance indicator for the period from the first quarter 2008 through the first quarter 2009. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Integrated Inspection Reports for the period of January 1, 2008 through March 31, 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. The licensee corrected one error effecting hours critical. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one unplanned scrams with complications sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.5 Mitigating Systems Performance Index (MSPI) - Auxiliary Feedwater System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Auxiliary Feedwater System performance indicator for the period from the first quarter through the fourth quarter of 2008 to determine the accuracy of the Performance Indicator data reported during those periods.

Performance Indicator definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used to assist the inspectors evaluation. The inspectors reviewed the licensees operator narrative logs, condition reports, MSPI derivation reports, MSPI margin reports, and maintenance rule data for the period of first quarter through fourth quarter 2008 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI auxiliary feedwater system sample as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

.1 Routine Review of items Entered Into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: the complete and accurate identification of the problem; that timeliness was commensurate with the safety significance; that evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the attached List of Documents Reviewed.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings of significance were identified.

.3 Semi-Annual Trend Review

a. Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6 month period of October 2008 through March 2009, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted a single semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings of significance were identified.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report (LER) 05000255/2008-007-01, Potential Loss of a safety

Function due to Non-Conservative Auxilary feedwater Trip Setpoints On February 13, 2006, the inspectors raised a concern regarding the setpoints for the low suction pressure trip for the auxiliary feedwater pumps. The inspectors were concerned that the setpoints of the Auxiliary Feed Water (AFW) low suction pressure trip would not ensure protection of the AFW pumps for all design bases events. In particular, tornado borne missiles could damage the condensate storage tank (CST)near the bottom of the tank. In this scenario, as the CST lost inventory, vortexing in the CST supply line to the AFW could result in damage to all three AFW pumps. Initially, the licensee believed the pumps would survive, in part due to a 3.5 second coastdown time.

In March of 2006, the inspectors timed the coastdown of the AFW pumps during pump testing and determined pump coastdown time to be closer to 23 seconds. Since the analysis would not support pump survival with the longer coast down time, the licensee instituted controls to prevent the automatic start of one of the AFW pumps during tornado warning. Subsequently, the licensee corrected the condition by constructing a protective wall around the CST and by adjusting the CST setpoints. The inspectors previously documented the failure to adequately protect the AFW pumps as NCV-05000255/2008004-05.

The inspectors reviewed the guidance in NUREG-1022, event reporting guidelines, and determined that the licensee failed to promptly report the condition. Specifically, 10 CFR 50.73 requires reporting on conditions within 60 days of discovery.

NUREG-1022 clarifies that when an evaluation is needed, when reasonable expectation of operability no longer exists, the licensee should report the condition. In this case, the licensee lost reasonable assurance of operability on March 3, 2006 and should have reported the condition by May 2, 2006. The LER was not issued until 2009. Since the inspectors were aware of the condition and documented the condition as Unresolved Item (URI)05000255/2006002-04, the inspectors concluded the late LER had only a minor impact on the regulatory process. Therefore, the inspectors concluded the performance deficiency was minor. The inspectors did not identify any additional safety concerns. Documents reviewed as part of this inspection are listed in the attachment.

This LER is closed.

This event follow-up review constituted one sample as defined in Inspection Procedure 71153-05.

4OA5 Other Activities

.1 (Closed - Update) NRC TI 2515/166, Pressurized Water Reactor Containment Sump

Blockage (NRC Generic Letter 2004-02)

As documented in Section 1R18, the inspectors confirmed that the licensee has completed the outstanding actions as described in Section 4OA5.7 of IR 05000255/2008003. This documentation of TI-2515/166 completion as well as any results of sampling audits of licensee actions will be reviewed by the NRC staff (Office of Nuclear Reactor Regulation - NRR) as input along with the GL 2004-02 responses to support closure of Generic Letter 2004-02 and GSI-191 Assessment of Debris Accumulation on Pressurized-Water Reactor Sump Performance. The NRC will notify each licensee by letter of the results of the overall assessment as to whether GSI-191 and Generic Letter 2004-02 have been satisfactorily addressed.

.2 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status review and inspection activities.

b. Findings

No findings of significance were identified.

.3 (Discussed) Confirmatory Order EA-06-178

a. Inspection Scope

By letter dated January 3, 2007, the NRC issued an immediately effective Confirmatory Order EA-06-178 (Order) that formalized commitments made by the Nuclear Management Company, LLC (NMC). The Order was in response to an August 22, 2006 settlement agreement between NMC and the NRC, regarding an apparent violation of 10 CFR 50.7, Employee Protection.

The Order required the licensee to:

• Order Item 1: By no later than 9 months after the issuance of the Confirmatory Order, NMC shall review, revise, and communicate to NMC employees and managers its policy relating to the writing of CAP reports, and provide training to NMC employees and managers to clarify managements expectations regarding the use of the program and the goal to ensure employees are not discouraged, retaliated against, or perceived to be retaliated against, for using the CAP.

• Order Item 2: By no later than June 30, 2007, NMC shall communicate its safety culture policy (including safety conscious work environment (SCWE)) to NMC employees, providing employees with the opportunity to ask questions in a live forum.

• Order Item 3: By no later than 9 months after the issuance of this Confirmatory Order, NMC shall train its employees holding supervisory positions and higher who have not had formal training on SCWE principles within the previous 2 years of the confirmatory order. NMC agrees to use a qualified training instructor (internal or external) for such training.

NRC shall review and enhance, if necessary, its refresher SCWE training consistent with NMCs refresher training program and provide such refresher training to its employees. New employees holding supervisory positions and higher shall be trained on SCWE principles within 9 months of their hire dates unless within the previous 2 years of their hire dates, theyve had the same or equivalent SCWE training.

• Order Item 4: By no later than March 30, 2007, NMC shall develop action plans to address significant issues identified as needing management attention in the NMC 2004 and 2006 Comprehensive Cultural Assessments at PBNP (Point Beach Nuclear Plant); to conduct focus group interviews with Priority 1 & 2 organizations to understand the cause of the survey results; and to review and, as appropriate, reflect nuclear industry best practices in its conduct of focus groups and action plans to address the issues at PBNP.

As part of the development of the action plans, NMC shall also assess and address any legacy issues identified in prior safety culture assessments (i.e. CAP Report AR00510074 and synergy Safety Culture Assessment) that impact the safety culture at PBNP.

The executive summary, analysis, and contemplated action plans shall also be submitted to the NRC.

• Order Item 5: By no later than December 31, 2008, NMC shall perform another survey at PBNP comparable to the 2004 and 2006 surveys to assess trends of the safety culture at the site and the overall effectiveness of corrective actions taken in response to prior year assessments, (i.e. CAP report AR00510074 and 2006 Synergy survey)

• Order Item 6: By no later than 3 months after the receipt of the next cultural survey results at PBNP, NMC shall submit the executive summary, analysis of the results, and the contemplated corrective actions to the NRC.

• Order Item 7: NMC shall continue to implement a process which ensures that adverse employment actions are in compliance with NRC employee protection regulations and principles of SCWE.

• Order Item 8: NMC shall continue to implement a process which ensures that adverse employment actions are in compliance with NRC employee protection regulations and principles of SCWE.

• Order Item 9: Any reference to NMC employees includes all NMC employees fleet wide. The Director, Office of Enforcement, may relax or rescind, in writing, any of the above conditions upon a showing by the licensee of good cause.

In reviewing all of the Orders requirements, only Items 1,2,3,7, and 8 were found to be applicable at Palisades.

To assess the licensees implementation of Order Items 1,2,3,7, and 8, the inspector review documentation (specified in an attachment to this report) including, condition reports, corrective actions, policies, procedures, slide presentation, Oversight Observation Checklists, and training attendance lists. In addition, the inspector discussed the implementation of specific procedures and training activities with licensee staff.

b. Observations Based on the documentation reviews and interviews, the inspectors concluded that:

• Order Item 1: By no later than 9 months after the issuance of the Confirmatory Order, NMC shall review, revise, and communicate to NMC employees and managers its policy relating to the writing of CAP reports, and provide training to NMC employees and managers to clarify managements expectations regarding the use of the program and the goal to ensure employees are not discouraged, retaliated against, or perceived to be retaliated against, for using the CAP.

Conclusion: The licensee appropriately implemented Order Item 1.

• Order Item 2: By no later than June 30, 2007, NMC shall communicate its safety culture policy (including SCWE) to NMC employees, providing employees with the opportunity to ask questions in a live forum.

Conclusion: The licensee appropriately implemented Order Item 2.

• Order Item 3: By no later than 9 months after the issuance of this Confirmatory Order, NMC shall train its employees holding supervisory positions and higher who have not had formal training on SCWE principles within the previous 2 years of the confirmatory order. NMC agrees to use a qualified training instructor (internal or external) for such training. New employees holding supervisory positions and higher shall be trained on SCWE principles within 9 months of their hire dates unless within the previous 2 years of their hire dates theyve had the same or equivalent SCWE training.

Conclusion: The licensee wrote CR-PLP-2009-00041 for one occasion when the order was not met for eight people in early 2009. This is discussed in 4OA7. With the initial actions and immediate actions taken for CR-PLP-2009-00041, the inspector concluded that the licensee has implemented Order Item 3.

• Order Item 7: NMC shall continue to implement a process which ensures that adverse employment actions are in compliance with NRC employee protection regulations and principles of SCWE.

Conclusion: The licensee appropriately implemented Order Item 7

• Order Item 8: NMC shall continue to implement a process which ensures that adverse employment actions are in compliance with NRC employee protection regulations and principles of SCWE.

Conclusion: The licensee appropriately implemented Order Item 8.

Based on the results of this inspection, the inspector concluded that the licensee had implemented Order Items 1,2,7, and 8 in accordance with the Order (EA-06-178)requirements. In addition, the inspector concluded that with the implementation of immediate corrective action associated with CR-PLP-2009-00041, that the licensee has implemented Order Item 3.

c. Findings

No findings of significance were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On June 30, 2009, the inspectors presented the inspection results to Chris Schwarz and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. On August 3, 2009, the inspectors conducted an additional exit meeting with P. Anderson of the licensee staff to discuss changes in the characterization of certain issues.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the access control to radiologically significant areas and ALARA inspection with the Site Vice President, Mr. C. Schwarz, and other members of the staff, on April 3, 2009.

• The results of the Radiation Monitoring Instrumentation and Protective Equipment with Mr. C. Sherman, on June 30, 2009.

• On April 9, 2009, the inspectors presented the ISI inspection results to Mr. A.

Blind and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee and were violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

• On January 7, 2009, the licensee identified a violation of Confirmatory Order Item 3 (3-2005-10). The Confirmatory Order, required, in part, that the licensee provide training to supervisors within 9 months of being hired. The licensee identified that as of January 7, eight supervisors had not or would not complete the training within the required time. The licensee completed the required training by January 26. The inspectors concluded that the finding impacted the NRCs ability to perform its regulatory function because the licensee did not meet a requirement from a Confirmatory Order issued under Alternate Dispute Resolution. The finding was not more than very low safety significance because there were no instances of an adverse impact on a safety conscious work environment as a result of the finding. Because the licensee identified the issue, entered it into the corrective action program as CR-PLP-2009-0041, and corrected the deficiency, the NRC is treating this as a licensee identified violation.

• Title 10 CFR 20.1802 requires licensees to control and maintain constant surveillance of licensed material that is in a controlled or unrestricted area and that is not in storage. Contrary to this, on May 1, 2009, slings, gloves and tie down straps, with detectable levels of radioactive contamination, were found inside the cab and on the bed of a flatbed truck located outside of the protected area in the main parking lot. The licensee confiscated the material and documented the issue in its corrective action program as CR-PLP-2009-02495.

The finding was determined to be of very low safety significance because it was a radioactive material control issue that resulted in public exposure of less than 0.005 rem.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

C. Schwarz, Site Vice President

D. Bemis, ISI Program Owner

V. Beilfuss, Project Manager

A. Blind, Engineering Director

N. Brott, Emergency Preparedness Coordinator

K. Bowers, Radiation Protection

T. Davis, Regulatory Compliance

B. Dotson, Regulatory Compliance

J. Fontaine, Senior Emergency Planning Coordinator

J. Ford, Corrective Action Manager

M. Ginzel, Radiation Protection

G. Goralski, Design Engineering Supervisor

J. Hager, Steam Generator Program Owner

T. Kirwin, Plant General Manager

D. Moody, radiation Protection

T. Shewmaker, Chemistry Manager

C. Sherman, Radiation Protection Manager

M. Sicard, Operations Manager

G. Sleeper, Assistant Operations Manager

B. VanWagner, Engineering Programs Supervisor

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000255/2009003-01 FIN Failure to Conduct an Adequate Risk Assessment for an Orange Risk Condition

05000255/2009003-02 NCV Failure to Manage Risk in Reduced Inventory

Closed

05000255/2009003-01 FIN Failure to Conduct an Adequate Risk Assessment for an Orange Risk Condition

05000255/2009003-02 NCV Failure to Manage Risk in Reduced Inventory

05000255/2008-007-01, LER Function Due to Non-Conservative Auxiliary Feedwater Trip Setpoints

Discussed

EA-06-178 ORD Confirmatory Order for NMC re: 10 CFR 50.7 Violation Attachment