IR 05000440/2006004

IR 05000440-06-004 and IR 05000440-06-021; on 07/01/2006 - 09/30/2006; Firstenergy Nuclear Operating Company (Fenoc); Perry Nuclear Power Plant

ML062840067
Person / Time
Site:	Perry
Issue date:	10/05/2006
From:	Satorius M Division Reactor Projects III
To:	Pearce L FirstEnergy Nuclear Operating Co
References
FOIA/PA-2010-0209 IR-06-004, IR-06-021
Download: ML062840067 (31)

Text

ber 5, 2006

SUBJECT:

PERRY NUCLEAR POWER PLANT NRC INTEGRATED INSPECTION REPORT 05000440/2006004 AND EMERGENCY PREPAREDNESS INSPECTION REPORT 05000440/2006021

Dear Mr. Pearce:

On September 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Perry Nuclear Power Plant. The enclosed report documents the inspection findings which were discussed on September 28, 2006, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. In addition to the routine NRC inspection and assessment activities, Perry performance is being evaluated quarterly as described in the Assessment Follow-up Letter - Perry Nuclear Power Plant, dated August 12, 2004. Consistent with Inspection Manual Chapter (IMC) 0305, "Operating Reactor Assessment Program," plants in the Multiple/Repetitive Degraded Cornerstone column of the NRCs Action Matrix are given consideration at each quarterly performance assessment review for (1) declaring plant performance to be unacceptable in accordance with the guidance in IMC 0305; (2) transferring to the IMC 0350, "Oversight of Operating Reactor Facilities in a Shutdown Condition with Performance Problems," process; and (3) taking additional regulatory actions, as appropriate.

On August 22, 2006, the NRC reviewed Perry operational performance, inspection findings, and performance indicators for the second quarter of 2006. Based on this review, we concluded that Perry is operating safely. We determined that no additional regulatory actions, beyond the already increased inspection activities and management oversight, are currently warranted.

Based on the results of this inspection, no findings were identified. However, one licensee-identified violation of very low safety significance is listed in Section 4OA7 of this report. Because of the very low safety significance of this violation and because it has been entered into your corrective action program, the NRC is treating this violation as a Non-Cited Violation consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the subject or severity of this 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 Perry Nuclear Power Plant.

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/

Mark A. Satorius, Director Division of Reactor Projects Docket No. 50-440 License No. NPF-58 Enclosure: Inspection Report 05000440/2006004; 05000440/2006021 w/Attachment: Supplemental Information cc w/encl: G. Leidich, President and Chief Nuclear Officer - FENOC J. Hagan, Senior Vice President of Operations and Chief Operating Officer - FENOC D. Pace, Senior Vice President, Fleet Engineering - FENOC J. Rinckel, Vice President, Fleet Oversight Director, Site Operations Director, Regulatory Affairs Manager, Fleet Licensing Manager, Site Regulatory Compliance D. Jenkins, Attorney, FirstEnergy Public Utilities Commission of Ohio Ohio State Liaison Officer R. Owen, Ohio Department of Health

SUMMARY OF FINDINGS

IR 05000440/2006004, 05000440/2006021; 07/01/2006 - 09/30/2006; Perry Nuclear Power

Plant.

This report covers a 3-month period of baseline inspection. The inspection was conducted by the resident and regional inspectors. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 3, dated July 2000.

A. Inspector-Identified and Self-Revealed Findings No findings of significance were identified.

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and the licensees corrective action tracking number are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period at 100 percent power. On July 8, 2006, operators reduced power to 55 percent to conduct planned maintenance activities. On July 9, 2006, operators returned power to 100 percent. On July 17, 2006, the plant experienced hot weather conditions and operators reduced power to 99.5 percent to maintain the main condenser operations within procedural limits. Power was returned to 100 percent on the same day.

Between July 31 and August 3, 2006, the plant experienced an extended period of hot weather conditions. During this period, operators maneuvered power to as low as 92 percent to manage main condenser operations within procedural limits and then returned power to 100 percent.

On September 11, 2006, operators reduced power to about 80 percent in order to repair the A reactor turbine-driven feed pump. On September 12, 2006, operators returned power to 100 percent. On September 29, 2006, operators commenced reactor downpower maneuvers to conduct planned maintenance activities and ended the inspection period on September 30, 2006, at 82 percent power.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

a. Inspection Scope

During the week of August 21, 2006, the inspectors observed licensee activities associated with the treatment of raw water systems to control populations of zebra mussels. The inspectors observed infrequently performed test or evolution briefings, pre-shift briefings, and control room briefings to determine whether the briefings met criteria specified in the Perry Operations Section Expectations Handbook and Perry Administrative Procedure (PAP)-1121, Conduct of Infrequently Performed Tests or Evolutions, Revision 4. The inspectors also reviewed prerequisites identified in licensee procedure PTI-GEN-P0024, Mussel Treatment, Revision 11, to determine whether they were completed prior to the initiation of treatment on August 22, 2006.

Finally, during the remainder of the inspection period, the inspectors periodically reviewed licensee activities and data collection as specified by licensee procedure PTI-GEN-P0023, Mussel Monitoring, Revision 4, to determine whether mussel settlement was being properly monitored.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Semi-Annual Complete System Walkdown

a. Inspection Scope

The inspectors performed a complete walkdown of accessible portions of the residual heat removal (RHR) system to determine system operability and condition during the month of July 2006. The RHR system was selected due to its risk significance. The inspectors used valve lineup instructions (VLIs) and system drawings to accomplish the inspection.

The inspectors observed selected switch and valve positions, electrical power availability, system pressure and temperature indications, component labeling, and general material condition. The inspectors determined whether system configurations and operating parameters were consistent with licensee procedures and drawings. The inspectors also reviewed open system engineering issues as identified in the licensees Quarterly System Health Report, outstanding maintenance work requests, and a sampling of condition reports (CRs) to determine whether problems and issues were identified, and corrected, at an appropriate threshold. The documents used for the walkdown are listed in the attached List of Documents Reviewed.

This review represented one semi-annual complete system walkdown.

b. Findings

No findings of significance were identified.

.2 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors conducted a partial walkdown of the system trains listed below to determine whether the systems were correctly aligned to perform their designed safety function. The inspectors used VLIs and system drawings during the walkdown. The walkdown included selected switch and valve position checks, and verification of electrical power to critical components. Finally, the inspectors evaluated other elements, such as material condition, housekeeping, and component labeling. The documents used for the walkdown are listed in the attached List of Documents Reviewed. The inspectors reviewed the following systems:

• B standby liquid control (SLC) system during testing of the SLC A system; and

• A and B annulus exhaust gas treatment system (AEGTS) trains following maintenance on the A AEGTS train.

This review represented two quarterly partial system walkdown samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

The inspectors walked down the following areas to assess the overall readiness of fire protection equipment and barriers:

• Turbine Building elevations 605', 620' and 624';

• Fire Zones 1CC-5A and 2CC-5A, Unit 1 and Unit 2 Control Rooms;

• Technical Support Center;

• Reactor Recirculation Pump Carbon Dioxide Drywell Fire Suppression System;

• Turbine Building Lube Oil Room;

• Fire Zone 1AB-1, Auxiliary Building Unit 1, elevation 574';

• Fire Zone 1AB-3, Auxiliary Building Unit 1, elevation 620';

• Turbine Power Complex Building; and

• Fire Zone 1AB-1C, reactor core isolation cooling pump room, elevation 574'.

Emphasis was placed on evaluating the licensees control of transient combustibles and ignition sources, the material condition of fire protection equipment, and the material condition and operational status of fire barriers used to prevent fire damage or propagation. The inspectors utilized the general guidelines established in Fire Protection Instruction (FPI)-A-A02, Periodic Fire Inspections, Revision 3; Perry Administrative Procedure (PAP)-1910, Fire Protection Program, Revision 11; and PAP-0204, Housekeeping/Cleanliness Control Program, Revision 15; as well as basic National Fire Protection Association Codes, to perform the inspection and to determine whether the observed conditions were consistent with procedures and codes.

The inspectors observed fire hoses, sprinklers, and portable fire extinguishers to determine whether they were installed at their designated locations, were in satisfactory physical condition, and were unobstructed. The inspectors also evaluated the physical location and condition of fire detection devices. Additionally, passive features such as fire doors, fire dampers, and mechanical and electrical penetration seals were inspected to determine whether they were in good physical condition. The documents listed in the List of Documents Reviewed at the end of this report were used by the inspectors during the inspection of this area.

These reviews represented nine quarterly inspection samples.

b. Findings

Introduction The inspectors identified an unresolved item (URI 05000440/2006004-01) requiring further inspection. The URI was associated with a longstanding degraded condition of the drywell reactor recirculation pump carbon dioxide (CO2) fire suppression system that resulted in an insufficient CO2 tank level.

Description On August 1, 2006, the inspectors observed that the CO2 suppression tank level for the reactor recirculation pump fire suppression system was 42 percent. This was below the minimum operability limit of 45 percent. The inspectors also noted that the tank was leaking CO2. On further review, the inspectors determined that the tank was below the minimum level to be considered operable in March 2006, October 2005, August 2005, June 2005, May 2005, April 2005, October 2003, September 2003, August 2002, and July 2001. In addition, during reviews of licensee condition reports, the inspectors determined that the inoperability of the CO2 tank was unnecessarily extended due to the late arrival of CO2 delivery trucks since 2005. The inspectors observed that the CO2 delivery was also delayed following the identification of a low tank level on August 1, 2006. Licensee personnel performed procedure PTI-P54-P0016, Carbon Dioxide Storage Tank Pressure and Level Verification, Revision 4, on August 2, 2006, and recorded tank level at 37 percent. On August 8, 2006, the inspectors observed that the CO2 tank level had decreased to 10 percent due to the delay in CO2 delivery.

Perry License Condition C(6) required that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the Perry Final Safety Analysis Report (FSAR). Section 9A.5, Position C.8 of the FSAR stated that measures had been established to ensure conditions adverse to fire protection, such as failures, malfunctions, deficiencies, deviations, defective components, uncontrolled combustible materials, and nonconformances are promptly identified, reported, and corrected. Attachment 3 of PAP-1910, Fire Protection Program/Fire Protection Functional Specifications, Revision 12, stated that the minimum required level for the reactor recirculation pumps CO2 system was 45 percent (2460 lbs).

Because the issue was associated with a fire protection system for the drywell and required the development of potential fire scenarios, the issue required further inspection by regional fire protection specialists in order to determine the significance of the issue. As a result, this issue is considered an unresolved item (URI 05000440/2006004-01) pending the development of potential drywell fire scenarios and the subsequent determination of the overall issue significance.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors performed an inspection of internal flooding vulnerabilities associated with the building roof drains. The inspection consisted of a review of the roof drain system design features described in the Updated Safety Analysis Report (USAR). In addition, the inspectors reviewed corrective action documents to determine whether previously identified deficiencies were appropriately prioritized and addressed. The inspectors walked down the roof drain system to determine whether observations were consistent with design. The inspectors also walked down the upper internal elevations of major safety-related buildings for any indications of severe roof leakage problems.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

On July 20, 2006, the resident inspectors observed licensed operator performance in the plant simulator. The inspectors evaluated crew performance in the areas of:

• clarity and formality of communication;

• ability to take timely action in the safe direction;

• prioritizing, interpreting, and verifying alarms;

• correct use and implementation of procedures, including alarm response procedures;

• timely control board operation and manipulation, including high-risk operator actions; and

• group dynamics.

The inspectors also observed the licensees evaluation of crew performance to determine whether the training staff had identified performance deficiencies and specified appropriate remedial actions.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Quarterly Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensee's implementation of the maintenance rule requirements to determine whether component and equipment failures were identified and scoped within the maintenance rule and that select structures, systems, and components (SSCs) were properly categorized and classified as (a)(1) or (a)(2) in accordance with 10 CFR 50.65. The inspectors reviewed station logs, maintenance work orders (WOs), selected surveillance test procedures, and a sample of CRs to determine whether the licensee was identifying issues related to the maintenance rule at an appropriate threshold and that corrective actions were appropriate. Additionally, the inspectors reviewed the licensees performance criteria to determine whether the criteria adequately monitored equipment performance and to determine whether changes to performance criteria were reflected in the licensees probabilistic risk assessment.

During this inspection period, the inspectors reviewed the following SSCs:

• containment airlock system; and

• leak detection system.

These reviews represented two quarterly inspection samples.

b. Findings

No findings of significance were identified.

.2 Periodic Evaluation

a. Inspection Scope

The inspectors examined the Maintenance Rule periodic evaluation report completed for the period of May 31, 2003, through May 6, 2005. The inspectors reviewed a sample of (a)(1) Action Plans, Performance Criteria, Functional Failures, and Condition Reports to evaluate the effectiveness of (a)(1) and (a)(2) activities. These same documents were reviewed to verify that the threshold for the identification of problems was at an appropriate level and the associated corrective actions were appropriate. Also, the inspectors reviewed the maintenance rule procedures and processes. The inspectors focused the inspection on the following four systems:

• high pressure core spray;

• diesel generator;

• reactor recirculation; and

• plant radiation monitoring and process monitoring.

The inspectors verified that the periodic evaluation was completed within the time constraints defined in 10 CFR 50.65 (once per refueling cycle, not to exceed 24 months). The inspectors also ensured that the licensee reviewed maintenance rule goals, monitored SSC performance, reviewed industry operating experience, and made appropriate adjustments to the maintenance rule program as a result of the above activities.

The inspectors verified that:

• the licensee balanced reliability and unavailability during the previous cycle, including a review of high safety significant SSCs;

• (a)(1) goals were met, that corrective actions were appropriate to correct the defective condition, including the use of industry operating experience, and that (a)(1) activities and related goals were adjusted as needed; and

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

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

These reviews represented four periodic inspection samples.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensees evaluation of plant risk, scheduling, configuration control, and performance of maintenance associated with planned and emergent work activities to determine whether scheduled and emergent work activities were adequately managed in accordance with 10 CFR 50.65(a)(4). In particular, the inspectors reviewed the licensees program for conducting maintenance risk assessments to determine whether the licensees planning, risk management tools, and the assessment and management of on-line risk were adequate. The inspectors also reviewed licensee actions to address increased on-line risk when equipment was out of service for maintenance, such as establishing compensatory actions, minimizing the duration of the activity, obtaining appropriate management approval, and informing appropriate plant staff, to determine whether the actions were accomplished when on-line risk was increased due to maintenance on risk-significant SSCs. The following assessments and/or activities were reviewed:

• licensees management of risk and work control during a period of elevated electrical power grid risk during the weeks of July 24 and July 31, 2006;

• licensees management of risk and work control associated with maintenance on the common emergency diesel generator (EDG) exhaust hallway modification during the week of August 14, 2006;

• licensees management of risk and work control associated with maintenance on the emergency service water intake structure during the week of August 28, 2006;

• licensees management of risk and work control associated with the replacement of a containment isolation valve for the condensate storage and transfer system during the week of September 4, 2006;

• licensees management of risk and work control associated with maintenance on both Division 1 EDG ventilation fans during the week of September 4, 2006;

• licensees management of risk and work control associated with the repair of the A turbine-driven reactor feed pump during the week of September 11, 2006; and

• licensees management of risk and work control associated with repairs to the A control complex chiller during the week of September 18, 2006.

These reviews represented seven inspection samples.

b. Findings

No findings of significance were identified.

1R14 Operator Performance During Non-Routine Evolutions and Events

During the inspection period, this Inspection Procedure was deleted and activities performed prior to deletion are now documented in Section 71153.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors selected CRs related to potential operability issues for risk-significant components and systems. These CRs were evaluated to determine whether the operability of the components and systems was justified. The inspectors compared the operability and design criteria in the appropriate sections of the Technical Specification (TS) and USAR 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 were in place, would function as intended, and were properly controlled. Additionally, the inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. The inspectors reviewed the following issues:

• an operability evaluation associated with the seismic qualification of the Division 1 and Division 2 EDG flywheel covers on July 13, 2006;

• an operability evaluation associated with a latent calculation error for a fire protection carbon dioxide system thermal relief valve affecting the primary containment system on August 4, 2006;

• an operability evaluation associated with the flooding analysis for a moderate energy water line break affecting the control complex switchgear rooms during the week of August 7, 2006;

• an operability evaluation associated with the ASME (American Society of Mechanical Engineers) qualification of the relief valve for the suppression pool makeup system heat exchanger on July 14, 2006;

• an operability evaluation associated with the inadvertent addition of ultra low sulfur fuel oil to the Division 3 EDG fuel oil storage tank on September 8, 2006; and

• an operability evaluation associated with high particulate and acidity levels found in a reactor core isolation cooling turbine oil sample on September 21, 2006.

These reviews represented six inspection samples.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors evaluated the following post-maintenance testing (PMT) activities for risk-significant systems to ensure 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; and equipment was returned to its operational status following testing. The inspectors evaluated the activities against TS, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications. In addition, the inspectors reviewed CRs associated with PMTs to determine whether the licensee was identifying problems and entering them in the corrective action program. The specific procedures and CRs reviewed are listed in the attached List of Documents Reviewed. The following post-maintenance activities were reviewed:

• testing of the containment lower airlock inner door after maintenance that was conducted on June 21, 2006;

• testing of the electric motor-driven fire pump that was conducted on July 31, 2006;

• testing of the main generator hydrogen oil extractor pump that was conducted on July 21,2006;

• testing of the reactor core isolation cooling system following maintenance on August 11, 2006;

• testing of the average power range monitor channel G that was conducted on August 25, 2006;

• testing of the reactor feed pump turbine A thrust bearing wear detection and trip system after repair on September 12, 2006;

• testing of the reactor water cleanup leak detection system after repair on September 20, 2006; and

• testing of a fuel pool cooling and cleanup system motor-operated valve following maintenance on September 26, 2006.

These reviews represented eight inspection samples.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed surveillance testing or reviewed test data for risk-significant systems or components to assess compliance with TS, 10 CFR 50, Appendix B, and licensee procedure requirements. The testing was also evaluated for consistency with the USAR. The inspectors verified that the testing demonstrated that the systems were ready to perform their intended safety functions. The inspectors determined whether test control was properly coordinated with the control room and performed in the sequence specified in the surveillance instruction (SVI), and if test equipment was properly calibrated and installed to support the surveillance tests. The procedures reviewed are listed in the attached List of Documents Reviewed. The surveillance activities assessed were:

• low pressure core spray system pump and valve in-service testing conducted on July 12, 2006;

• high pressure core spray system essential service water pump and valve in-service testing on July 26, 2006;

• Division 2 EDG monthly routine testing on August 15, 2006;

• SLC B system quarterly pump and valve in-service testing on August 17, 2006;

• oscillation power range monitor G routine functional testing on August 21, 2006; and

• containment isolation local leak rate test in-service testing on August 29, 2006.

These reviews represented four in-service inspection samples and two routine testing inspection samples.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed documentation for a ventilation system modification to provide additional air cooling for the auxiliary building during the week of July 24, 2006.

The inspectors assessed the acceptability of this temporary configuration change by comparing the 10 CFR 50.59 screening and evaluation information against the design basis, the Updated Final Safety Analysis Report (UFSAR), and the TS as applicable.

The comparisons were performed to ensure that the new configurations remained consistent with design basis information. 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.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed activities in the simulator control room, the Technical Support Center, the Emergency Operations Facility, and Operations Support Center during an emergency preparedness drill conducted on September 16, 2006. The inspection focused on the ability of the licensee to appropriately classify emergency conditions, complete timely notifications, and implement appropriate protective action recommendations in accordance with approved procedures.

This review represented one inspection sample.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to determine whether they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed.

This is not an inspection sample.

b. Findings

No findings of significance were identified.

.2 Annual Sample Review

a. Inspection Scope

The inspectors selected the licensees root cause evaluation associated with the licensees excursion from the maximum extended operating domain (MEOD) boundary during reactor power ascension on July 9, 2006. The inspectors selected this issue for detailed review because the issue was associated with the cross-cutting area of human performance. The inspectors reviewed the corrective actions associated with the event and reviewed the licensees evaluation to determine whether licensing or design limits were exceeded.

This review represented one inspection sample.

b. Findings and Observations

As a result of the root cause evaluation, the licensee identified three root causes:

(1) weaknesses in the management, implementation, and oversight of the reactivity management program;

(2) weaknesses in procedure use and adherence, and evolution control and monitoring, that led to inappropriate decisions; and

(3) lack of organizational engagement. The licensee evaluated the MEOD boundary excursion for normal and limiting postulated transients and concluded that design and licensing limits were not exceeded. Licensee corrective actions included: a site-wide human performance stand-down, additional oversight expectations for reactivity management plans, added simulator training and training program changes for operations and reactor engineering personnel, and changes to the work management process.

While not a finding, the inspectors noted that the licensee had previously identified weaknesses in the reactivity management process in May 2006. The inspectors also noted that the MEOD boundary was exceeded after operators made a decision to exceed a procedural administrative limit that was put in place to provide margin to the MEOD boundary and that this procedure allowed the limit to be exceeded in certain cases with the operations shift managers approval. The inspectors determined that the operations and reactor engineering personnel were not aware that the MEOD limit had been exceeded until after the event had occurred.

4OA3 Event Followup

.1 Notification of Unusual Event

a. Inspection Scope

On June 20, 2006, a minor earthquake occurred that was centered about 3 miles northwest of Perry. The inspectors responded to the control room and observed the licensees declaration of a Notice of Unusual Event and operator performance associated with the event. The licensees actions included plant walkdowns to inspect for damage and ground water sampling to inspect for leaks. The licensee identified no adverse affects resulting from the earthquake. The inspectors conducted confirmatory walkdowns of safety significant areas of the plant and reviewed the licensees actions to determine whether the actions were consistent with procedures and TS requirements.

b. Findings

No findings of significance were identified.

This review represented the first of six inspection samples.

.2 LER 05000440/2006-003-00 Incorrect Wiring in the Division 1 Emergency Diesel

Generator Results in a Fire Protection Program Violation.

A discussion of this event, and an associated licensee-identified NCV, is contained in Section 4OA7 of this report.

This review represented the second of six inspection samples.

.3 Reactor Recirculation System Vortex and Reactivity Event

a. Inspection Scope

On July 6, 2006, control room operators responded to unexpected local power range monitor and rod block alarms that immediately reset. Operators determined that a reactor recirculation system vortex shedding event had occurred, which caused a brief neutron flux spike. The inspectors reviewed the operator performance associated with the reactivity event. The inspectors reviewed the licensees actions to determine whether the actions were consistent with procedures and TS requirements.

This review represented the third of six samples for this inspection procedure.

b. Findings

No findings of significance were identified.

.4 Reactor Downpower and Rod Control and Indication System (RCIS) Failure

a. Inspection Scope

On July 8, 2006, control room operators reduced reactor power to about 61 percent to conduct planned maintenance. Subsequently, a failure occurred in the RCIS that prevented rod withdrawal. The inspectors observed the operator performance associated with the power maneuvers and the operator response to the failure of RCIS.

The inspectors reviewed the licensees actions to determine whether the actions were consistent with procedures and TS requirements.

This review represented the fourth of six samples for this inspection procedure.

b. Findings

No findings of significance were identified.

.5 Maximum Extended Operating Domain Boundary Excursion During Power Ascension

a. Inspection Scope

On July 9, 2006, control room operators conducted a reactor power ascension to 100 percent power. While withdrawing rods, control room operators exceeded an administrative power to flow operating limit and questioned whether the plant remained within the maximum extended operating domain boundary limit. On July 10, 2006, licensee personnel determined that the maximum extended operating domain boundary line of the power to flow map was exceeded during the power ascension. The inspectors reviewed the operator performance associated with the power ascension that contributed to the domain boundary excursion. The inspectors reviewed the licensees actions to determine whether the actions were consistent with procedures and TS requirements.

This review represented the fifth of six samples for this inspection procedure.

b. Findings

No findings of significance were identified.

.6 Reactor Downpower for A Reactor Turbine-Driven Feed Pump Emergent Maintenance

a. Inspection Scope

On September 11, 2006, control room operators conducted a reactor power reduction to 80 percent power in order to troubleshoot an emergent thrust bearing wear indication system alarm on the A reactor turbine-driven feed pump. Operators started the motor-driven feed pump prior to the power reduction and then secured the A reactor turbine-driven feed pump after reaching 80 percent power. The inspectors observed the operator performance associated with the power reduction and the manipulation of the reactor feed system. The inspectors reviewed the licensees actions to determine whether the actions were consistent with procedures and TS requirements.

This review represented the sixth of six samples for this inspection procedure.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 Review of World Association of Nuclear Operators (WANO) Report

The inspectors completed a review of the interim report for the WANO May 2006 Peer Review, dated June 27, 2006. No additional followup is planned.

.2 Licensee Strike Contingency Plans

a. Inspection Scope

The inspectors completed an evaluation of the adequacy of strike contingency plans and implementation associated with the transition to the licensees new contract with the labor union. The inspectors reviewed the adequacy of qualified personnel staffing, maintenance of reactor operation and facility security, and determined whether the plan was in compliance with TS and the CFR.

b. Findings

No findings of significance were identified.

4OA6 Meetings

.1 Exit Meeting

On September 28, 2006, the resident inspectors presented the inspection results to Mr. L. Pearce, Site Vice President, and other members of his staff who acknowledged the findings.

The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

.2 Interim Exit Meeting

An interim exit meeting was conducted for:

• Maintenance Effectiveness Periodic Evaluation with Mr. J. Shaw, Engineering Director, on September 14, 2006.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

Cornerstone: Mitigating Systems

• License Condition C(6), Fire Protection, required the licensee to implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report, as amended. The Updated Final Safety Analysis Report, Revision 12, Section 9A.6 Response L, Fire Protection of Safe Shutdown Capability, referred to USAR Section 7.4.1.4, Remote Shutdown System. USAR Section 7.4.1.4 stated that the Division 1 remote shutdown capability is designed to control the required shutdown systems from outside the control room irrespective of shorts, opens or grounds in the control circuit in the control room that may have resulted from an event causing an evacuation. Contrary to this requirement, on May 4, 2006, licensee personnel identified that the Division 1 EDG control room pull-to-lock control switch was not designed to isolate the control room from the local Division 1 EDG controls in the event of a control room fire and that a potential fire induced hot short in the EDG logic circuit could have resulted in a failure to start or a spurious trip of the EDG even if control was transferred to local. The licensee implemented procedure changes to address the issue and entered the issue into their corrective action program as CR 06-01930, Additional Fire Protection Evaluation Needed For EDG Circuit, dated May 2, 2006. The Region III Senior Reactor Analysts (SRAs) performed a Phase 3 SDP evaluation of the issue because Inspection Manual Chapter (IMC) 0609, Appendix F, Fire Protection SDP, does not address control room evacuation scenarios. Based on information from the licensees Individual Plant Examination for External Events (IPEEE), the control room panel fire scenario that could result in a fire-induced hot short and the unavailability of the Division 1 EDG does not result in a loss of offsite power.

Additionally, fire spread from the Division 1 EDG control panel to the control room panels for offsite power controls was unlikely to occur because of the construction of the control panels and the separation of the panels. Therefore, a fire that would cause a loss of offsite power and result in the postulated hot short was not a credible fire. The SRAs determined that the finding was of very low safety significance (Green) due to the low likelihood of the postulated fire concurrent with a non-fire induced loss of power to Division 1 offsite power.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

L. Pearce, Vice President-Nuclear

F. von Ahn, General Manager, Nuclear Power Plant Department

R. D. Gray, Maintenance Rule Program Engineer

J. Lausberg, Manager, Regulatory Compliance

G. Halnon, Director, Performance Improvement Initiative

J. Messina, Manager, Operations

M. Wayland, Director, Maintenance

J. Shaw, Director, Nuclear Engineering

S. Thomas, Manager, Radiation Protection

K. Russell, Regulatory Affairs

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000440/2006004-01 URI Failure to Promptly Correct Degraded Condition of the Reactor Recirculation Pump CO2 Fire Suppression System (Section 1R05 )

Closed

05000440/2006-003-00 LER Incorrect Wiring in the Division 1 Emergency Diesel Generator Results in a Fire Protection Program Violation (Section 71153)

Attachment