IR 05000482/2006005

IR 05000482/2006-005; 10/08/06 - 12/31/06; Wolf Creek Generating Station; Refueling and Outage Activities, Access Control to Radiologically Significant Areas

ML070380078
Person / Time
Site:	Wolf Creek
Issue date:	02/06/2007
From:	Vincent Gaddy NRC/RGN-IV/DRP/RPB-B
To:	Muench R Wolf Creek
References
IR-06-005
Download: ML070380078 (51)

Text

February 6, 2007

SUBJECT:

WOLF CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000482/2006005

Dear Mr. Muench:

On December 31, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Wolf Creek Generating Station. The enclosed integrated report documents the inspection findings which were discussed on January 9, 2007, with Mr. S. E. Hedges and other members of your staff.

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

Inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents two NRC-identified findings of very low safety significance (Green).

Both of these findings were determined to involve violations of NRC requirements. Additionally, one licensee-identified violation, which was determined to be of very low safety significance, is listed in Section 4OA7 of this report. The NRC is treating these violations as noncited violations consistent with Section VI.A.1 of the NRC Enforcement Policy because of the very low safety significance and because the findings were entered into your corrective action program. If you contest these noncited violations, you should provide a response within 30 days of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Wolf Creek Generating Station.

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 component of NRCs document system (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Wolf Creek Nuclear Operating Corporation-2-Should you have any questions concerning this inspection, we will be pleased to discuss them with you.

Sincerely,

/RA/

Vincent G. Gaddy, Chief Project Branch B Division of Reactor Projects Docket: 50-482 License: NPF-42

Enclosure:

NRC Inspection Report 05000482/2006005 w/attachment: Supplemental Information

REGION IV==

Docket:

50-482 License:

NPF-42 Report:

5000482/2006005 Licensee:

Wolf Creek Nuclear Operating Corporation Facility:

Wolf Creek Generating Station Location:

1550 Oxen Lane NE Burlington, Kansas Dates:

October 8 through December 31, 2006 Inspectors:

S. D. Cochrum, Senior Resident Inspector J. R. Groom, Resident Inspector G. A. George, Reactor Inspector J. H. Nadel, Reactor Inspector F. L. Brush, Senior Project Engineer P. J. Elkmann, Emergency Preparedness Inspector B. K. Tharakan, Health Physicist, Plant Support Branch Approved By:

V. G. Gaddy, Chief, Project Branch B

Enclosure-2-

SUMMARY OF FINDINGS

IR 05000482/2006005; 10/08/06 - 12/31/06; Wolf Creek Generating Station; Refueling and

Outage Activities, Access Control to Radiologically Significant Areas.

This report covered a 3-month period of inspection by resident and regional inspectors. The inspection identified two Green findings, both of which were noncited violations. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.

Cornerstone: Mitigating Systems

Green.

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

Criterion V, Instructions, Procedures, and Drawings, involving the licensee's failure to properly implement the reactor vessel closure head installation procedure during Refueling Outage 15. Specifically, on October 30, 2006, the licensee performed Procedure FHP-02-007B, Reactor Vessel Closure Head Installation," Revision 5.

During the performance of Procedure FHP-02-007B, the licensee encountered problems with the polar crane that prevented the crane hoist from being lowered. The problems with the polar crane were encountered while the reactor vessel head was being transported along the North-South axis of the refueling cavity towards the reactor vessel. Consequently, the licensee transported the reactor vessel closure head approximately 3 feet over the reactor vessel flange, while suspended approximately feet above the operating deck. This condition was not allowed by procedure and exceeded the maximum analyzed height in the head drop analysis.

The failure to properly implement the reactor vessel closure head installation procedure was considered a performance deficiency. The finding was greater than minor because it affected the human performance attribute of the mitigating systems cornerstone and the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events. Using Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Phase 1 worksheets, the finding was found to be of very low safety significance because it did not affect decay heat removal or reactor coolant system inventory. The inspectors determined that the finding has crosscutting aspects in the area of human performance associated with work practices because the licensee failed to use appropriate human error prevention techniques, such as self-and peer-checking and not proceeding in the face of uncertainty. The inspectors also determined that the finding has crosscutting aspects in the area of problem identification and resolution associated with operating experience because the licensee failed to effectively communicate internally generated lessons learned following the procedural noncompliance during the Refueling Outage 13 reactor vessel head installation. (Section 1R20)

Cornerstone: Occupational Radiation Safety

Green.

The inspector identified a noncited violation of 10 CFR 19.12(a)(2) because the licensee failed to provide instructions to a worker on how to minimize exposure while working with radioactive material and contaminated equipment. Specifically, on October 18, 2006, a worker on the Steam Generator A platform received an intake of Cobalt-58 while removing contaminated conduit from the primary side of the steam generator and placing it in a radioactive material bag for storage. The worker was wearing a face shield; however, the inspector identified that the licensee failed to provide the worker with instructions on how to minimize exposure to radioactive material while performing this task. The licensees corrective actions included providing workers with powered face shields that blow air away from the face. This finding was entered into the licensees corrective action program.

The finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Exposure Control and affected the cornerstone objective to ensure the adequate protection of a workers health and safety from exposure to radioactive materials because a worker received an unintended internal dose. The finding was processed through the Occupational Radiation Safety Significance Determination Process and determined to be of very low safety significance because it was not an as low as is reasonably achievable finding, there was no overexposure or substantial potential for an overexposure, and the ability to assess dose was not compromised. Additionally, this finding has a crosscutting aspect in the area of human performance related to work practices because the licensee did not ensure supervisory oversight of work activities such that exposure to radioactive material was minimized and properly controlled. (Section 2OS1)

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Wolf Creek was shut down for Refueling Outage 15 at the beginning of the inspection period.

The licensee completed the refueling outage and synchronized the generator to the grid on November 10, 2006. The licensee returned to full power operations on November 15, 2006.

Wolf Creek remained at full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness

1R04 Equipment Alignment

Partial System Walkdowns

a. Inspection Scope

The inspectors:

(1) walked down portions of the risk important systems listed below and reviewed plant procedures and documents to verify that critical portions of the selected systems were correctly aligned and

(2) compared deficiencies identified during the walkdown to the licensee's Updated Safety Analysis Report (USAR) and corrective action program to ensure problems were being identified and corrected.

C October 19, 2006, Emergency Diesel Generator A during an Emergency Diesel Generator B run C

October 20, 2006, Emergency Diesel Generator B while Emergency Diesel Generator A was inoperable Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified

1R05 Fire Protection

Fire Protection Tours

a. Inspection Scope

The inspectors walked down the plant areas listed below to assess the material condition of active and passive fire protection features, their operational lineup, and their operational effectiveness. The inspectors:

(1) verified that transient combustibles and hot work activities were controlled in accordance with plant procedures;

(2) observed the condition of fire detection devices to verify they remained functional;

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

(4) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory condition;

(5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems) were in a satisfactory material condition;

(6) verified that adequate compensatory measures were established for degraded or inoperable fire protection features; and

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

• October 11, 2006, Containment

• October 19, 2006, Emergency Diesel Generator B room

• October 20, 2006, Emergency Diesel Generator A room

• November 6, 2006, Turbine-driven auxiliary feed pump room

• December 11, 2006, Essential service water pump house

• December 19, 2006, Lower cable spreading room and common corridor Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

Annual Internal Flooding

a. Inspection Scope

The inspectors:

(1) reviewed the USAR, the flooding analysis, and plant procedures to assess seasonal susceptibilities involving external flooding;

(2) reviewed the USAR and corrective action program to determine if the licensee identified and corrected flooding problems;

(3) inspected underground bunkers/manholes to verify the adequacy of

(a) sump pumps,

(b) level alarm circuits,

(c) cable splices subject to submergence, and

(d) drainage for bunkers/manholes;

(4) verified that operator actions for coping with flooding can reasonably achieve the desired outcomes; and

(5) walked down the below listed area to verify the adequacy of:

(a) equipment seals located below the floodline,

(b) floor and wall penetration seals,

(c) watertight door seals,

(d) common drain lines and sumps,

(e) sump pumps, level alarms, and control circuits, and

(f) temporary or removable flood barriers.

C December 11, 2006, Main steam/main feedwater isolation valve enclosure Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

Procedure 71111.08 requires a minimum sample size of four for each section (Sections 02.01, 02.02, 02.03, and 02.04). The inspectors fulfilled the requirements of Inspection Procedure 71111.08. Documents reviewed by the inspectors are listed in the attachment.

.1 Inspection Activities Other Than Steam Generator Tube Inspections, Pressurized Water

Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control

a. Inspection Scope

The procedure requires the review of two to three types of nondestructive examination activities (i.e., volumetric, surface, or visual). The inspectors reviewed one of each:

(1) visual examination,

(2) magnetic particle (surface) examination, and

(3) seven ultrasonic (volumetric) examinations. Of these examinations, the inspectors witnessed the performance of one visual, one surface, and one ultrasonic examination. The ultrasonic examinations are listed below.

DATA SHEET ISI NUMBER SYSTEM/WELD AREA EXAM METHOD TMC-002 EM-05-S005-B HPCI/pipe to elbow Ultrasonic TMC-002 EM-05-S005-C HPCI/elbow to pipe Ultrasonic AWJ-004 BB-04-F001 Pressurizer spray line/PZR safe end to pipe Ultrasonic JLD-004 TBB03-2-W PZR spray nozzle Ultrasonic AWJ-005 AB-01-F074 Main steam/pipe to pen Ultrasonic AWJ-005 AB-01-F007 Main Steam/Pipe to Pen Ultrasonic TMC-004*

TBB03-CIRCUM-5-W Pressurizer circumferential weld Ultrasonic For each of the activities reviewed, the inspectors verified that the activities performed were in accordance with site procedures and applicable American Society of Mechanical Engineers (ASME) Code requirements. In addition, the inspectors verified that the test equipment was properly used during the current calibration period. During the performance of the activities, the inspectors verified that certifications of nondestructive examination personnel were current and in accordance with industry standards.

The inspectors reviewed the site procedures to verify that recordable indications were dispositioned in accordance with the ASME Code or an NRC approved alternative.

During the performance of the above nondestructive examination activities, no recordable indications were identified or accepted for continued service.

The inspection procedure requires verification that the welding process and welding examinations were performed on one to three welds in accordance with ASME Code requirements or an NRC approved alternative. The inspectors observed three in-process weld overlay activities being performed on pressurizer nozzle dissimilar metal welds that are susceptible to primary water stress corrosion cracking. The inspectors reviewed weld overlays being performed on the pressurizer relief line, pressurizer Safety Line C, and the pressurizer surge line. The licensee personnel performed activities in accordance with ASME Code and 10 CFR 50.55a, Request I3R-05.

The inspectors completed the one sample required by Section 02.01.

b. Findings

No findings of significance were identified.

.2 Vessel Upper Head Penetration Inspection Activities

This section of the inspection procedure was performed using Temporary Instruction 2515/150, Reactor Pressure Vessel and Vessel Head Penetration Nozzles.

The results of this inspection are reported in Section 4OA5, Other Activities.

.3 Boric Acid Corrosion Control Inspection Activities Pressurized Water Reactor)

a. Scope

The inspectors reviewed two boric acid screens and seven boric acid evaluations found on reactor coolant system piping and components that were identified during the previous operating cycle. In addition, the inspectors reviewed the boric acid corrosion control procedures.

Through record review, the inspectors verified that the visual inspections emphasized locations where boric acid leaks can cause degradation and these boric acid leaks were properly documented. On those components where boric acid was identified, the engineering evaluations gave assurance that the ASME Code wall thickness limits were properly maintained. The evaluations also confirmed that the corrective actions performed for evidence of boric acid leaks were consistent with requirements of the ASME Code.

The inspectors completed the one sample required by Section 02.03.

b. Findings

No findings of significance were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The inspection procedure requires that inspectors compare the in-situ screening criteria to Electric Power Research Institute (EPRI) guidelines. In particular, the inspectors must assess whether assumed nondestructive examination flaw sizing accuracy is consistent with EPRI guidelines. In addition, the inspectors are to assess whether the appropriate tubes are to be pressure tested, observe those pressure tests, if possible, and review the results. The inspectors reviewed licensee procedures for in-situ pressure testing and concluded that the in-situ pressure testing program meets EPRI guidelines.

During the outage, conditions, that met EPRI guidelines, had been identified for in-situ pressure testing specific steam generator tubes; however, those tubes were taken out of service by plugging. Therefore, no in-situ pressure testing was performed on any steam generator tubes.

In addition, the inspectors reviewed both the licensee site-validated and qualified acquisition and analysis technique sheets used during this refueling outage. The inspectors also reviewed the qualifying EPRI examination technique specification sheets to verify that the essential variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had been identified and qualified through demonstration.

The inspectors reviewed tube flaws identified in the previous outage comparing them to current outage results. The inspectors verified that minor flaw growth had occurred.

Those flaws that reached the 40 percent plugging criteria were plugged using a process approved by Technical Specifications (TS). Those flaws below the 40 percent criteria were evaluated and plugged, if the evaluation indicated an estimated growth above 40 percent during the next operating cycle. The 40 percent tube repair criterion was applied to all indications in tube support plate and antivibration bar intersections.

The inspection procedure requires the inspectors confirm that the eddy current test probes and equipment are qualified for the expected types of tube degradation.

Inspectors must also assess the site-specific qualification of one or more techniques.

The inspectors reviewed the qualification records of the bobbin coil and motorized rotating pancake coil probes. The calibration and qualification records of the probes were current for the types of detectable tube degradations.

During the performance of steam generator eddy current activities, the licensee identified foreign material in the secondary side of the steam generator. The inspectors verified that the licensee inspected the secondary side of the steam generator and removed those foreign materials. The licensee then reinspected those steam generator tubes that may have been affected by foreign material. No loose parts or foreign material were inaccessible; therefore, all foreign material was removed.

Finally, the inspection procedure specified review of one to five samples of eddy current test data if questions arose regarding the adequacy of eddy current test data analyses.

The inspectors did not identify any results where eddy current test data analyses adequacy was questionable.

The inspectors completed the one sample required by Section 02.04.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed four problem identification and resolutions, which dealt with inservice inspection activities, and found that the corrective actions were appropriate.

From this review the inspectors concluded that the licensee had an appropriate threshold for entering issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also had an effective program for applying industry operating experience.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors reviewed the maintenance activities listed below to:

(1) verify the appropriate handling of structure, system, and component (SSC) performance or condition problems;

(2) verify the appropriate handling of degraded SSC functional performance;

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

(4) evaluate the handling of SSC issues reviewed under the requirements of the maintenance rule, 10 CFR Part 50, Appendix B, and TSs.

• October 26, 2006, Emergency diesel generator Robert Shaw temperature control valves

• December 6, 2006, Remote shutdown panel and postaccident monitoring instrumentation Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

Risk Assessment and Management of Risk The inspectors reviewed the assessment activities listed below to verify:

(1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and licensee procedures prior to changes in plant configuration for maintenance activities and plant operations;

(2) the accuracy, adequacy, and completeness of the information considered in the risk assessment;

(3) that the licensee recognizes, and/or enters as applicable, the appropriate licensee-established risk category according to the risk assessment results and licensee procedures; and

(4) that the licensee identified and corrected problems related to maintenance risk assessments.

• October 8, 2006, Overall outage risk

• October 20, 2006, Daily risk assessment following discovery of reduced inventory within spent fuel pool Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors:

(1) reviewed plant status documents, such as operator shift logs, emergent work documentation, deferred modifications, and standing orders, to determine if an operability evaluation was warranted for degraded components;

(2) referred to the USAR and design basis documents to review the technical adequacy of licensee operability evaluations;

(3) evaluated compensatory measures associated with operability evaluations;

(4) determined degraded component impact on any TSs;

(5) used the significance determination process to evaluate the risk significance of degraded or inoperable equipment; and

(6) verified that the licensee has identified and implemented appropriate corrective actions associated with degraded components.

• October 21, 2006, Residual Heat Removal Trains A and B seismic loading

• November 7, 2006, Emergency Diesel Generator A fuel line fretting Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors selected the below listed postmaintenance test activities of risk significant systems or components. For each item, the inspectors:

(1) reviewed the applicable licensing basis and/or design-basis documents to determine the safety functions;

(2) evaluated the safety functions that may have been affected by the maintenance activity; and

(3) reviewed the test procedure to ensure it adequately tested the safety function that may have been affected. The inspectors either witnessed or reviewed test data to verify that acceptance criteria were met, plant impacts were evaluated, test equipment was calibrated, procedures were followed, jumpers were properly controlled, the test data results were complete and accurate, the test equipment was removed, the system was properly realigned, and deficiencies during testing were documented. The inspectors also reviewed the USAR and corrective action program to determine if the licensee identified and corrected problems related to postmaintenance testing.

• October 26, 2006, Essential Service Water Pump B replacement

• October 27, 2006, Emergency Diesel Generator B break-in run

• November 28, 2006, Steam generator blowdown isolation valve Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities

a. Inspection Scope

The inspectors reviewed the following risk significant refueling items or outage activities to verify defense in-depth commensurate with the outage risk control plan, compliance with TS, and adherence to commitments in response to Generic Letter 88-17, Loss of Decay Heat Removal:

(1) the risk control plan;

(2) tagging/clearance activities;

(3) reactor coolant system instrumentation;

(4) electrical power;

(5) decay heat removal;

(6) spent fuel pool cooling;

(7) inventory control;

(8) reactivity control;

(9) containment closure;

(10) reduced inventory or midloop conditions;

(11) refueling activities;

(12) heatup and cooldown activities;

(13) restart activities; and

(14) licensee identification and implementation of appropriate corrective actions associated with refueling and outage activities. The inspectors' containment inspections included observations of the containment sump for damage and debris, and supports, braces, and snubbers for evidence of excessive stress, water hammer, or aging.

• October 7, 2006, Reactor coolant system cooldown

• October 8, 2006, Initial containment entry, including normally inaccessible areas behind the bio-shield wall

• October 10-11, 2006, Reactor vessel head de-tensioning and removal

• October 12, 2006, Removal of reactor upper internals

• October 13, 2006, Core offload (observed from containment and control room)

• October 17, 2006, Outage risk assessment techniques, including assessment of decay heat removal/spent fuel pool cooling, availability of offsite power, reactivity control, and control of containment.

• October 25, 2006, Core reload (observed from control room and fuel handling platform)

• October 30, 2006, Reactor vessel head set (observed from outage control center)

• November 1, 2006, Reactor coolant system fill and vent, including reduced inventory or midloop conditions, which included adherence to commitments in response to Generic Letter 88-17

• November 6, 2006, Reactor coolant system heatup and establishing bubble in pressurizer

• November 7, 2006, Containment closure walkdown, including inspection of containment recirculation sumps

• November 8, 2006, Under reactor vessel inspection

• November 9-11, 2006, Reactor startup, physics testing, and review of core operating limits report

• December 6, 2006, Verification of core reload (by video)

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction:

The inspectors identified a Green noncited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, involving the licensee's failure to properly implement the reactor vessel closure head installation procedure during Refueling Outage 15.

Description:

On October 30, 2006, the inspectors observed the licensee perform Procedure FHP-02-007B, Reactor Vessel Closure Head Installation," Revision 5.

Step 8.1.9 of Procedure FHP-02-007B directs the reactor vessel closure head be raised from the head stand until clear of all obstacles, approximately 4 feet above the operating deck. Following movement of the head to the refueling cavity, step 8.1.11 of Procedure FHP-02-007B directs the crane operator to reposition the polar crane onto the north-south axis of the reactor building and lower the head to approximately 12 inches but no more than 2 feet above the operating deck, which translates to a maximum elevation of 2049'-6" in containment.

During the performance of Procedure FHP-02-007B, the licensee encountered problems with the polar crane that prevented the crane hoist from being lowered. The problems with the polar crane were encountered while the reactor vessel head was being transported along the north-south axis of the refueling cavity towards the reactor vessel.

Upon determination that the polar crane was unable to be lowered, the licensee stopped the transport of the head towards the reactor vessel. Following direction from the outage control center manager, the reactor vessel head was moved to the storage stand for troubleshooting. The reactor vessel head was successfully installed on a subsequent attempt with the crane operator utilizing the controls from the local cab.

Following the installation of the reactor vessel closure head, the inspectors reviewed Calculation BB-FW-011, WCNOC, Reactor Vessel Head Drop Analysis, Revision 0.

Calculation BB-FW-011 postulates the maximum stress transmitted to the four support nozzles in the event of a failure of the polar crane. The calculation concluded that a reactor vessel head drop from an analyzed height of 28 feet above the reactor vessel flange would not challenge core cooling capability or the integrity of the fuel cladding.

The 28 feet translates to a maximum elevation of 2049'-6" in containment; the limit imposed by step 8.1.11 of Procedure FHP-02-007B.

The inspectors also noted that step 8.1.11 contains commitment step 3.2.6 that references a Performance Improvement Request (PIR) 2003-3589, Procedure Noncompliance During Reactor Head Move. Commitment step 3.2.6 was implemented in response to a procedural error during the Refueling Outage 13 head installation, where the reactor vessel head was lifted greater than the 28 feet analyzed in Calculation BB-FW-011. No additional precautions, details, or procedural requirements regarding commitment step 3.2.6 were included in the procedure.

Because Precaution/Limitation 5.3 allows operators to deviate from step-by-step procedural compliance and step 8.1.11 of Procedure FHP-02-007B did not contain a specific requirement to lower reactor vessel closure head to the required height prior to moving toward the vessel flange, the inspectors questioned whether any portion of the reactor vessel closure head was suspended greater than the allowed height above the operating deck while over the reactor vessel. Since step 8.1.9 of Procedure FHP-02-007B directs the reactor vessel closure head be raised approximately 4 feet above the operating deck and the controls for the polar crane did not allow for the crane hoist to be lowered, the inspectors concluded that the reactor vessel closure head was approximately 2 feet above the maximum allowed height above the vessel flange while being transported towards the reactor vessel. This conclusion was verified by examining video footage of the Refueling Outage 15 reactor vessel closure head installation.

To determine the proximity of the reactor vessel closure head relative to the reactor vessel flange, the inspectors again reviewed video footage of the Refueling Outage 15 reactor vessel closure head installation. Line of sight bearings were established to closely approximate the position of the reactor vessel closure head within the refueling cavity. Additionally, distinguishing marks along the polar crane were examined and compared to video footage of the head installation that occurred on October 30, 2006.

Through review of both the video footage and the actual physical inspection of the polar crane, the inspectors determined that the reactor vessel closure head was approximately 3 feet over the reactor vessel flange while suspended approximately 4 feet above the operating deck. This condition exceeded the maximum allowed height analyzed in the head drop analysis.

Analysis:

The failure to properly implement the reactor vessel closure head installation procedure was considered a performance deficiency. This finding was more than minor because it affected the human performance attribute of the mitigating systems cornerstone and the cornerstone objective to ensure the availability, reliability, and capability of system that respond to initiating events. Using Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, Phase 1 worksheets, the finding was found to be of very low safety significance because it did not affect decay heat removal or reactor coolant system inventory. The inspectors determined that the finding has crosscutting aspects in the area of human performance associated with work practices because the licensee failed to use appropriate human error prevention techniques, such as self-and peer-checking and not proceeding in the face of uncertainty. The inspectors also determined that the finding has crosscutting aspects in the area of problem identification and resolution associated with operating experience because the licensee failed to effectively communicate internally generated lessons learned following the procedural noncompliance during the Refueling Outage 13 reactor vessel head installation.

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to Procedure FHP-02-007B, Reactor Vessel Closure Head Installation," Revision 5, the licensee failed to lower the reactor vessel closure head to the maximum allowed analyzed height prior to positioning over the vessel flange. Because this violation was of very low safety significance and was entered into the corrective action program as Condition Report 2006-003342, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2006005-01, Failure to implement the reactor vessel closure head installation procedure.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the USAR, procedure requirements, and TSs to ensure that the listed surveillance activities demonstrated that the SSCs tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the following significant surveillance test attributes were adequate:

(1) preconditioning;

(2) evaluation of testing impact on the plant;

(3) acceptance criteria;

(4) test equipment;

(5) procedures;

(6) jumper/lifted lead controls;

(7) test data;

(8) testing frequency and method demonstrated TS operability;

(9) test equipment removal;

(10) restoration of plant systems;

(11) fulfillment of American Society of Mechanical Engineers code requirements;

(12) updating of performance indicator data;

(13) engineering evaluations, root causes, and bases for returning tested SSCs not meeting the test acceptance criteria were correct;

(14) reference setting data; and

(15) annunciators and alarms setpoints. The inspectors also verified that the licensee identified and implemented any needed corrective actions associated with the surveillance testing:

• October 19, 2006, STS KJ-005B, Manual/Auto Start, Synchronization & Loading of Emergency D/G NE02, Revision 44 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed plant drawings, work orders, and Temporary Modification Package 06000BG to ensure that the temporary modification was properly implemented.

The inspectors:

(1) verified that the modification did not have an affect on system operability/availability,

(2) verified that the installation was consistent with the modification documents,

(3) ensured that the postinstallation test results were satisfactory and that the impact of the temporary modification on permanently installed SSCs were supported by the test,

(4) verified that the modifications were identified on control room drawings and that appropriate identification tags were placed on the affected drawings, and

(5) verified that appropriate safety evaluations were completed.

The inspectors verified that the licensee identified and implemented any needed corrective actions associated with temporary modifications:

• Normal charging pump (PBG04) balance line, December 13, 2006 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1EP2 Alert Notification System Testing

a. Inspection Scope

The inspector discussed with licensee staff the status of offsite siren and tone alert radio systems to determine the adequacy of licensee methods for testing the alert and notification system in accordance with 10 CFR Part 50, Appendix E. The licensees alert and notification system testing program was compared with criteria in NUREG-0654, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," Revision 1, Federal Emergency Management Agency (FEMA) Report REP-10, "Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants," and the licensees current FEMA-approved alert and notification system design report, dated June 12, 1987. The inspector also reviewed the following procedures:

• Procedure EP 06-019, "Alert and Notification System Sirens," Revision 3

• Procedure EP 06-022, "Tone Alert Radio Maintenance/Compensatory Measures," Revisions 0-4 Documents reviewed by the inspectors are listed in the attachment.

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation Testing

a. Inspection Scope

The inspector discussed with licensee staff the status of primary and backup systems for augmenting the on-shift emergency response staff to determine the adequacy of licensee methods for staffing emergency response facilities. The inspector reviewed the following documents related to the emergency response organization augmentation system to evaluate the licensees ability to staff their emergency response facilities in accordance with the emergency plan and the requirements of 10 CFR Part 50, Appendix E:

• Procedure EP 06-015, "Emergency Response Organization Callout,"

Revisions 7-9

• Tool Kit-011, "Callout Test Guidance," Revision 4

• Emergency response organization guidance, Revision 1

• Callout system call detail report, dated February 16, 2006 Documents reviewed by the inspectors are listed in the attachment.

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector performed an in-office review of Revision 8 to Emergency Plan Implementing Procedure Form APF 06-002-01 "Emergency Action Levels," submitted November 3, 2006. This revision changed the amount of steam generator leakage necessary to enter Emergency Action Level 2, "Steam Generator Tube Failure,"

consistent with NRC-approved changes to station TS for steam generator leakage.

The revision was compared to the previous revision; to the criteria of NUREG-0654, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," Revision 1; to the criteria of Nuclear Energy Institute 99-01, "Methodology for Development of Emergency Action Levels,"

Revision 2; and to the standards in 10 CFR 50.47(b) to determine if the revision was adequately conducted according to the requirements of 10 CFR 50.54(q). This review was not documented in a safety evaluation report and did not constitute approval of the licensees changes; therefore, this revision is subject to future inspection.

Documents reviewed by the inspectors are listed in the attachment.

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed the licensees corrective action program requirements in Procedures AP 28A-100, "Condition Reports," Revision 2; AP 28A-001, "Performance Improvement Request," Revision 26; and AP 28B-001, "Root Cause Analysis,"

Revision 2. The inspector reviewed summaries of 186 PIRs and condition reports assigned to the emergency preparedness department between May 2004 and November 2006, and selected 19 for detailed review against the program requirements.

The inspector evaluated the response to the corrective action requests to determine the licensees ability to identify, evaluate, and correct problems in accordance with the licensee program requirements and 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E. The inspector also reviewed other documents listed in the attachment to this report.

Documents reviewed by the inspectors are listed in the attachment.

The inspector completed one sample during the inspection.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

For the below listed drill and simulator-based training evolution contributing to drill/exercise performance and emergency response organization performance indicators, the inspectors:

(1) observed the training evolution to identify any weaknesses and deficiencies in classification, notification, and protective action requirements development activities;

(2) compared the identified weaknesses and deficiencies against licensee identified findings to determine whether the licensee is properly identifying failures; and

(3) determined whether licensee performance is in accordance with the guidance of the Nuclear Energy Institute 99-02 documents acceptance criteria.

• April 20, 2006, fire in vital Buss XNB02 and loss of all alternating current power to the vital busses Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess licensee performance in implementing physical and administrative controls for airborne radioactivity areas, radiation areas, high radiation areas, and worker adherence to these controls. The inspector used the requirements in 10 CFR Part 20 and the licensees procedures required by TSs as criteria for determining compliance. During the inspection, the inspector interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspector performed independent radiation dose rate measurements and reviewed the following items:

• Performance indicator events and associated documentation packages reported by the licensee in the Occupational Radiation Safety Cornerstone

• Controls (surveys, posting, and barricades) of three radiation, high radiation, or airborne radioactivity areas

• Radiation work permits, procedures, engineering controls, and air sampler locations

• Conformity of electronic personal dosimeter alarm setpoints with survey indications and plant policy; workers knowledge of required actions when their electronic personnel dosimeter noticeably malfunctions or alarms

• Barrier integrity and performance of engineering controls in airborne radioactivity areas

• Adequacy of the licensees internal dose assessment for any actual internal exposure greater than 50 millirem committed effective dose equivalent

• Physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools

• Self-assessments and audits related to the access control program since the last inspection; there were no licensee event reports (LERs) and special reports

• Corrective action documents related to access controls

• Licensee actions in cases of repetitive deficiencies or significant individual deficiencies

• Radiation work permit briefings and worker instructions

• Adequacy of radiological controls such as, required surveys, radiation protection job coverage, and contamination controls during job performance

• Dosimetry placement in high radiation work areas with significant dose rate gradients

• Changes in licensee procedural controls of high dose rate - high radiation areas and very high radiation areas

• Controls for special areas that have the potential to become very high radiation areas during certain plant operations

• Posting and locking of entrances to all accessible high dose rate - high radiation areas and very high radiation areas

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements Documents reviewed by the inspectors are listed in the attachment.

The inspector completed 21 of the required 21 samples.

b. Findings

Introduction:

The inspector identified a noncited violation of 10 CFR 19.12(a)(2)because the licensee failed to provide workers with instructions on how to correctly handle and store radioactive material and contaminated equipment. The violation had very low safety significance.

Description:

On October 18, 2006, a steam generator worker on the Steam Generator A platform received an intake of Cobalt-58 while removing conduit from the primary side of the steam generator and placing it into a radioactive material bag for storage. The worker was observed pushing down on the bag in order to compact its size for easier storage. The release of air from the bag during this compaction was the most likely source of Cobalt-58 that resulted in the intake. The worker was wearing a face shield. However, the inspector interviewed the workers involved and identified that the licensee failed to provide the workers with instructions on how to minimize exposure to radioactive material while performing this task. The licensees corrective actions included placing workers in powered face shields that blow air away from the face and ensuring that there was supervisory oversight during these types of tasks. The worker received a committed effective dose equivalent of one millirem and a committed dose equivalent of four millirem to the lung.

Analysis:

The failure to provide instructions to workers was a performance deficiency.

The finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of exposure control, and affected the cornerstone objective to ensure the adequate protection of a workers health and safety from exposure to radioactive materials because a worker received an unintended internal dose. Because the finding involved unplanned, unintended dose resulting from conditions that were contrary to NRC regulations, the finding was evaluated using the Occupational Radiation Safety Significance Determination Process. The finding was determined to be of very low safety significance because:

(1) it was not an ALARA (as low as is reasonably achievable) finding,

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

(4) the finding did not compromise licensees ability to assess dose. Additionally, this finding also had a crosscutting aspect in the area of human performance related to work practices because the licensee did not ensure supervisory oversight of work activities such that exposure to radioactive material was minimized and properly controlled.

Enforcement:

Section 19.12(a)(2) of Title 10 of the Code of Federal Regulations states, in part, that all individuals who in the course of employment are likely to receive in a year an occupational dose in excess of 100 millirem shall be instructed in precautions and procedures to minimize exposure to radiation and radioactive materials. Contrary to this requirement, on October 18, 2006, the licensee failed to provide instructions to workers about working with radioactive material and contaminated equipment. This violation was entered into licensees corrective action program as Condition Report 2006-2668.

Because this finding is of very low safety significance and was entered into licensees corrective action program, it is being treated as a noncited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000482/2006005-02, Failure to provide instructions to workers.

2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual and collective radiation exposures ALARA. The inspector used the requirements in 10 CFR Part 20 and the licensees procedures required by TSs as criteria for determining compliance. The inspector interviewed licensee personnel and reviewed:

• Site-specific ALARA procedures

• ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements

• Interfaces between operations, radiation protection, maintenance, maintenance planning, and scheduling and engineering groups

• Integration of ALARA requirements into work procedure and radiation work permit (or radiation exposure permit) documents

• Workers use of the low dose waiting areas

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas Documents reviewed by the inspectors are listed in the attachment.

The inspector completed 3 of the required 15 samples and 3 of the optional samples.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

Cornerstone: Emergency Preparedness Cornerstone

The inspector reviewed licensee evaluations for the three emergency preparedness cornerstone performance indicators of:

(1) drill and exercise performance,

(2) emergency response organization participation, and

(3) alert and notification system reliability, for the period October 1, 2005, through September 30, 2006. The definitions and guidance of Nuclear Energy Institute 99-02, "Regulatory Assessment Indicator Guideline," Revisions 2-4, and licensee performance indicator Procedure AI 26A-004, "Emergency Planning Performance Indicators," Revision 2, were used to verify the accuracy of the licensees evaluations for each performance indicator reported during the assessment period.

The inspector reviewed a sample of drill and exercise scenarios and licensed operator simulator training sessions, notification forms, and attendance and critique records associated with training sessions, drills, and exercises conducted during the verification period. The inspector reviewed 15 selected emergency responder qualification, training, and drill participation records. The inspector reviewed alert and notification system testing procedures, maintenance records, and all records of siren tests performed during the inspection period. The inspector also reviewed other documents listed in the attachment to this report.

The inspector completed three samples.

Occupational Radiation Safety Cornerstone

• Occupational exposure control effectiveness The inspector reviewed licensee documents from April 1 through September 30, 2006.

The review included corrective action documentation that identified occurrences in locked high radiation areas (as defined in the licensees TSs), very high radiation areas (as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in Nuclear Energy Institute 99-02). Additional records reviewed included ALARA records and whole-body counts of selected individual exposures. The inspector interviewed licensee personnel that were accountable for collecting and evaluating the performance indicator data. In addition, the inspector toured plant areas to verify that high radiation, locked high radiation, and very high radiation areas were properly controlled.

Performance indicator definitions and guidance contained in Nuclear Energy Institute 99-02, "Regulatory Assessment Indicator Guideline," Revision 4, were used to verify the basis in reporting for each data element.

The inspector completed the required one sample in this cornerstone.

Public Radiation Safety Cornerstone

• Radiological effluent TS/offsite dose calculation manual radiological effluent occurrences The inspector reviewed licensee documents from April 1 through September 30, 2006.

Licensee records reviewed included corrective action documentation that identified occurrences for liquid or gaseous effluent releases that exceeded performance indicator thresholds and those reported to the NRC. The inspector interviewed licensee personnel that were accountable for collecting and evaluating the performance indicator data. Performance indicator definitions and guidance contained in Nuclear Energy Institute 99-02, "Regulatory Assessment Indicator Guideline," Revision 4, were used to verify the basis in reporting for each data element.

Documents reviewed by the inspectors are listed in the attachment.

The inspector completed the required one sample in this cornerstone.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolutions of Problems

a. Inspection Scope

The inspectors performed a daily screening of items entered into the licensee's corrective action program. This assessment was accomplished by reviewing work requests, work orders, and PIRs, and attending corrective action review and work control meetings. The inspectors:

(1) verified that equipment, human performance, and program issues were being identified by the licensee at an appropriate threshold and that the issues were entered into the corrective action program;

(2) verified that corrective actions were commensurate with the significance of the issue; and (3)identified conditions that might warrant additional followup through other baseline inspection procedures.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Semiannual Trend Review

a. Inspection Scope

The inspectors completed a semiannual trend review of repetitive or closely-related issues that were documented in trend reports, problem lists, performance indicators, health reports, quality assurance audits, corrective action documents, corrective maintenance documents, and departmental self-assessments and interviewed selected licensee staff to determine if any adverse trends existed. Additionally, the inspectors reviewed the licensees trending efforts to identify trends that might indicate the existence of more safety-significant issues. The inspectors review consisted of the 6-month period from June to December 2006. When warranted, some of the samples expanded beyond those dates to fully assess the issue. The inspectors also reviewed corrective action program items associated with the below listed issues. The inspectors compared and contrasted their results with the results contained in the licensee's quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensee's trend report were reviewed for adequacy. These areas were chosen based on information gathered by the inspectors during daily plant status reviews over the previous 6 months.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings and Observations

No findings of significance were identified. However, during the review the inspectors noted the following trends:

• The inspectors noticed a continuing negative trend in the area of clearance orders and plant status control issues. Although the licensee had identified trends previously, they were not considered continuing negative trends. The licensee has completed several root causes in these areas and has ongoing corrective actions in place addressing the previously identified negative trends.

Corrective actions developed from the last apparent cause determination for clearance orders contained in PIR 2006-001663 and corrective actions developed from a common cause analysis for plant status control issues are contained in Condition Report 2006-00813; however, the current corrective actions have been slow to adequately correct the problems. Condition Report 2006-000610 had been written to identify a continuing trend in status control.

• The inspectors noticed an increasing negative trend in the area of procedure use and adherence issues. A trend was identified by the licensee in 2005; however, corrective actions have been ineffective to date. Although the licensee had identified a trend previously, they did not consider the trend as an increasing negative trend.

.3 Health Physics Review of Identification and Resolutions of Problems

a. Inspection Scope

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

• Access control to radiologically significant areas

• ALARA planning and controls

b. Findings and Observations

Section 2OS1 describes a finding associated with the failure to provide instructions to workers to minimize exposure to radioactive materials. The licensees corrective actions did not identify that an apparent cause of the intake of radioactive material was due to the worker not being provided adequate instructions and supervision with respect to controlling contamination and minimizing exposure to radioactive material.

.4 Annual Sample Review (Emergency Preparedness)

a. Inspection Scope

The inspector selected 19 PIRs and condition reports generated between June 1, 2004, and November 1, 2006, for detailed review. The reports were reviewed to ensure that the full extent of the issues were identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspector evaluated the PIRs and condition reports against the requirements of licensee Procedures AP 28A-100, "Condition Reports," Revision 2, and AP 28A-001, "Performance Improvement Request," Revision 26.

b. Findings

No findings of significance were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 Personnel Performance During Nonroutine Evolutions, Events and Transients

a. Inspection Scope

The inspectors:

(1) reviewed operator logs, plant computer data, and/or strip charts for the below listed evolutions to evaluate operator performance in coping with nonroutine events and transients;

(2) verified that operator actions were in accordance with the response required by plant procedures and training; and

(3) verified that the licensee has identified and implemented appropriate corrective actions associated with personnel performance problems that occurred during the events sampled.

• On November 10, 2006, the inspectors observed the licensees response after identifying that a symmetrical circular region of fuel assemblies in the center of the core were operating less than predicted power. This condition was found during the review of the initial power ascension flux maps. The licensee verified all nuclear parameters were within specifications and adequate design margin existed. The licensees cause analysis determined that the flux suppression was not caused by manufacturing or modeling errors but was most likely an artifact of design and not indicative of a problem with the core. The inspectors reviewed the flux maps and core map video to verify the fuel locations in the core.

b. Findings

No findings of significance were identified.

.2 (Closed) LER 2006-004-00, Failure to Maintain Closure of Containment Penetrations

During Fuel Movement On October 24, 2006, while in Mode 6, refueling, the licensee discovered an air-to-air pathway existed from the containment recirculation sumps though the containment spray system to the auxiliary building. The containment sump suction valves for Containment Spray Pump B were stroked open while downstream valves in the auxiliary building were uncapped and open under a clearance order. This resulted in an air-to-air pathway during fuel movement that was not administratively controlled. This is contrary to TS 3.9.4, which states, in part, a penetration flow path providing direct access from the containment atmosphere to the outside atmosphere may be unisolated under administrative controls. Upon discovery, the penetration was immediately placed under administrative controls. The root cause for this event was determined to be human performance resulting from inadequate instructions that provided vague guidance. This licensee-identified violation is documented in Section 4OA7. This LER is closed.

4OA5 Other Activities

.1 Temporary Instruction 2515/150, Reactor Pressure Vessel Head And Vessel Head

Penetration Nozzles (NRC Order EA-03-009), Revision 3 Background The reactor pressure vessel (RPV) heads of pressurized-water reactors (PWRs) have penetrations for control rod drive mechanisms and instrumentation systems. Nickel-based alloys (e.g., Alloy 600) are used in the penetration nozzles and weld materials.

Primary coolant water and the operating conditions of PWR plants can cause cracking of these nickel-based alloys through a process called PWSCC. The susceptibility of RPV head penetrations to pressurized water stress corrosion cracking (PWSCC)appears to be linked to the operating time and temperature of the RPV head. In early 2001, circumferential cracking of the vessel head penetration nozzles at the Oconee Nuclear Station was identified. Circumferential cracking is a safety concern because of the possibility of a nozzle ejection if the condition is not detected and repaired. In early 2002, axial cracking of a vessel head penetration nozzle was discovered at the Davis Besse Nuclear Power Station. The axial crack resulted in primary water leakage, which in turn created a cavity in the RPV head.

The operating experience with respect to PWSCC of RPV head penetration nozzles has reinforced the need for more effective inspections.Section XI of the ASME Boiler and Pressure Vessel Code, which is incorporated into NRC regulations by 10 CFR 50.55a, Codes and Standards, currently specifies that inspections of the RPV head need only include a visual check for leakage on the insulated surface or surrounding area. These inspections may not detect small amounts of leakage from an RPV head penetration with circumferential or axial cracks. NRC Order EA-03-009 was issued in February 11, 2003, to establish required inspections of RPV heads and associated penetration nozzles at PWRs. These requirements are necessary to provide reasonable assurance that plant operations did not pose an undue risk to the public health and safety. The requirements of that Order were expected to remain in effect pending long-term resolution of RPV head penetration inspection requirements, which is expected to involve changes to the NRC regulations, specifically 10 CFR 50.55a.

Bare metal visual (BMV) examinations of the Wolf Creek Generating Station RPV head had been performed in Refueling Outage RF-13. No indication of leakage was detected in those examinations. Based on no indications of leakage, BMV inspections were not performed in Refueling Outage 14.

In response to NRC Order EA-03-009, Wolf Creek Generating Station performed a BMV and nonvisual nondestructive examination (NDE) of the RPV head and penetration nozzles during Refueling Outage RF-15. The following paragraphs describe the inspection scope and findings related to the examination.

a. Inspection Scope

From October 12-18, 2006, the inspectors conducted an evaluation and assessment of the RPV head and vessel head penetration examinations performed by Wolf Creek Generating Station. During the inspection, the inspectors performed the following actions.

• A review of the susceptibility ranking, including the effective degradation years calculation.

• Independently observe (via videotape if available and if direct observation of the head is not possible) the RPV head BMV and NDE examinations.

• Independent review and report on the condition of the RPV.

• A report on anomalies, deficiencies, and discrepancies identified with the associated structures or the examination process when such problems are judged to be significant enough to potentially impede the examination process.

• A review of the scope of Wolf Creeks plan to examine the pressure-retaining components above the RPV head to ensure that all possible sources of boric acid leakage are included, that examination would be effective in identifying boric acid leakage in this area, and that appropriate actions are implemented should boron deposits be identified on the RPV head or related insulation.

• A review of the results of the examination to ensure that appropriate actions have been taken in response to identified boron deposits on the RPV head or related insulation.

The inspectors observed approximately 20 percent of the RPV head and vessel head penetration nozzles using direct observation and videotapes of the examination (16 of 78 nozzles). Additionally, the inspectors visited the area of the RPV head to observe its general condition and the movement of insulation to accommodate the examination.

b. Findings

No findings of significance were identified. This completes the inspection requirements for the first review of Temporary Instruction 2515/150.

General Wolf Creek performed BMV and NDE examinations of the reactor vessel head on October 12-18, 2006, and they did not identify any evidence of primary water leakage from cracks in the RPV head and vessel head penetration nozzles. The inspectors reviewed 20 percent of the RPV head and vessel head penetration nozzles and verified the absence of boric acid deposits that could indicate PWSCC on the RPV head.

Susceptibility Ranking The inspectors reviewed the bases for the type of examinations performed by Wolf Creek. Wolf Creek determined that the effective degradation period for the reactor vessel head was 4 years, as described in Procedure STS PE-04E, RPV Head Bare Metal Inspection, Revision 1. The inspectors reviewed the calculation, verified that the appropriate plant-specific information was used as input to the calculation, and confirmed that the effective degradation period was correct. As a result of the calculated effective degradation years, and absence of previous PWSCC, Wolf Creek was a low susceptible reactor. NRC Order EA-03-009 requires that low susceptible plants perform at least a BMV examination every three refueling outages. At least once over the course of every four refueling outages, low susceptible plants are to perform a BMV examination and a nonvisual exam, such as ultrasonic, eddy current, or dye penetrant tests. The inspectors determined that the BMV and NDE examination of the reactor vessel head met the inspection requirements of NRC Order EA-03-009.

Volumetric Examinations Specific details of the NDE data gathering and analysis methods used were considered proprietary. Therefore, details of the techniques, data, and analyses are not discussed in this report.

The inspectors concluded that Wolf Creek performed a 100 percent NDE examination of the vessel head penetration nozzles. The inspectors observed that personnel training, examination equipment, and procedures were adequate. The inspectors reviewed the examiner qualifications of two Level II and one Level III eddy current examiners, and three Level II and two Level III ultrasonic examiners and verified the examiners were qualified to ASME certification standards. It was also noted that the examiners performing the examination had performed BMV examinations for other Westinghouse PWR plants.

The inspectors reviewed the applicable surface and volumetric examination requirements and concluded that the techniques were able to identify indications in the vessel upper head penetrations. The inspectors reviewed the acceptance criteria and determined that the acceptance criteria met the flaw evaluation guidelines. Plant specific procedures stated that any relevant indication exceeding 0.170 inch shall be reported. There were no indications that met the criteria.

The inspectors concluded that examiners encountered no impediments, such as debris, boric acid deposits, insulation, or other obstacles, that impacted the effective examination of the RPV head.

Bare Metal Visual Examination The inspectors concluded that Wolf Creek performed a 100 percent BMV examination of the reactor vessel head and vessel head penetration nozzles. The inspectors observed that personnel training, examination equipment, and procedures were adequate to detect small boron deposits that could arise from circumferential or axial PWSSC of the vessel head penetration nozzles. Wolf Creek used a robotic crawler with a front-and rear-mounted camera to perform the examination. The cameras had the capability to adjust lighting and focus and articulate the view angle up and down to view the control rod drive and reactor vessel head vent nozzles. The crawler and video probe cameras were able to show, with clarity, letters that were as small as 0.02 inches in height (i.e.,

Jaeger J-1 images). The reactor vessel head insulation package was not in direct contact with the head, which allowed access to the entire head. Wolf Creek was able to inspect completely around all of the nozzles and detect any small amounts of boron.

The BMV examination was videotaped, and the inspectors used the videotape, as well as direct observation, to verify the absence of boric acid deposits that would be indicative of PWSCC. There were no portions of the head obscured due to debris, preexisting leaks, or other obstructions. The inspectors also determined that the inspection was performed in accordance with licensee Procedure STS PE-040E, RPV Head Bare Metal Inspection, Revision 1. The inspectors did not identify any active boric acid leaks on or other concerns with the condition of the vessel head.

The inspectors reviewed the training and qualification of the personnel performing the BMV examination. Persons performing the inspection held a VT-2 Level 2 or Level 3 qualification. Persons performing the BMV examination had performed the previous BMV examinations for other Westinghouse PWR plants. The inspectors observed the examiners identification and disposition of visual data and found their disposition to be appropriate.

The inspectors verified the adequacy of Procedure STS PE-040E, RPV Head Bare Metal Inspection, Revision 1. The inspectors verified that the procedure provided adequate guidance and examination criteria. Specifically, the procedure provided guidance for complete reactor vessel head examination, including a documentation and tracking mechanism to ensure all vessel head penetrations are examined. The procedure also provided clear standards and acceptance criteria for which the examiners had training and experience. The inspectors observed that the procedure contained guidance for dispositioning boric acid deposits and reporting of anomalies.

During the examination, the inspectors noted that personnel were following the procedural guidance and tracking progress according to the procedure.

As stated above, the inspectors noted the absence of boric acid leakage from the vessel head penetrations. Additionally, the inspectors also noted that there were no boric acid deposits on the head or insulation as a result of leakage from above the reactor vessel head. The inspectors did not identify any significant differences between the condition of the head in this inspection and the bare metal examination during the 2005 refueling outage. In the 2005 outage, the licensee removed portions of the vessel head insulation during which the inspectors conducted a visual inspection of the vessel head and did not identify any issues.

The inspectors concluded that examiners encountered no impediments, such as debris, boric acid deposits, insulation, or other obstacles that impacted the effective examination of the RPV head.

.2 (Closed) Temporary Instruction 2515/166, Pressurizer Water Reactor Containment

Sump Blockage

a. Inspection Scope

The inspectors reviewed Wolf Creeks implementation of plant modifications and procedure changes committed to in their response to Generic Letter 2004-02.

The inspectors observed installation of the containment recirculation sump strainers, debris barriers and interceptors, and addition of caps to the top of vertically mounted pipe supports. In addition, the inspectors verified that Wolf Creek has implemented specific procedure changes to control tags, labels, tape, and other objects inside the containment building. At the time of the exit meeting, Wolf Creek was in the final stages of implementing a containment coatings assessment program, a latent debris assessment program, and a containment strainer inspection program.

At the time of the inspection, industry testing for chemical effects on containment recirculation sumps was not complete. Since the testing was not complete, Wolf Creek evaluated the new recirculation sump modifications to the original design basis, Regulatory Guide 1.82, Revision 0. The inspectors verified that the design meets the original design basis. The Office of Nuclear Reactor Regulation will determine the adequacy of the modification in regard to Generic Safety Issue-191, Assessment of Debris Accumulation on PWR Sump Performance.

b. Findings

No findings of significance were identified. This completes the inspection requirements for this Temporary Instruction.

4OA6 Meetings, Including Exit

On October 20, 2006, the inspector presented the occupational radiation safety inspection results to Mr. R. Muench, President and Chief Executive Officer, and other members of the licensee's staff who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On October 26, the inspectors presented the results of the inservice inspection and completion of Temporary Instruction 2515/166 inspections to Mr. S. E. Hedges, Vice President of Operations & Plant Manager, and other members of licensee management.

Licensee management acknowledged the inspection findings. The inspectors identified that they had reviewed proprietary information but had returned it to licensee personnel.

On December 1, 2006, the inspector presented the emergency preparedness inspection results to Mr. R. A. Muench, President and Chief Executive Officer, and other members of his staff who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On January 9, 2007, the resident inspectors presented the inspection results to Mr. S. E.

Hedges and other members of licensee management. Licensee management acknowledged the inspection findings. The inspectors identified that they had reviewed proprietary information but had returned it to licensee personnel.

4OA7 Licensee-Identified Violations

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

• TS 3.9.4, containment penetrations, requires, in part, that during core alterations each penetration providing direct access from the containment atmosphere to the outside atmosphere be closed by a manual or automatic isolation valve, blind flange, or equivalent but may be unisolated under administrative controls.

Contrary to this requirement, during core alterations on October 24, 2006, the licensee failed to adequately control Valve ENHV-0007, containment recirculation sump suction for containment spray Pump B (containment penetration 13), resulting in the valve being opened intermittently for testing.

Opening Valve ENHV-0007 provided a direct path from the containment atmosphere to the outside atmosphere. The licensee entered this item in its corrective action program as Condition Report 2006-002804. This finding was determined to be of very low safety significance because it occurred in a shutdown condition when the refueling cavity water level is at or above the minimum level required for movement of irradiated fuel assemblies within containment as defined by TS.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. J. Garrett, Vice President Engineering

S. E. Hedges, Vice President Operations and Plant Manager

R. A. Muench, President and Chief Executive Officer

K. Scherich, Director Engineering

M. Sunseri, Vice President Oversight

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000482/2006005-01 NCV Failure to implement the reactor vessel closure head installation procedure (Section 1R20)

05000482/2006005-02 NCV Failure to provide instructions to workers (Section 2OS1)

05000482/2006-004-00 LER Failure to Maintain Closure of Containment Penetrations During Fuel Movement (Section 4OA3)