IR 05000458/2010004

IR 05000458-10-004, on 07/01/10 - 09/30/10, River Bend Station, Integrated Inspection

ML103140581
Person / Time
Site:	River Bend
Issue date:	11/10/2010
From:	Vincent Gaddy NRC/RGN-IV/DRP/RPB-C
To:	Mike Perito Entergy Operations
References
EA-10-159 IR-10-004
Download: ML103140581 (47)

Text

UNITED STATES NU C LE AR RE G ULATO RY C O M M I S S I O N R E GI ON I V 612 EAST LAMAR BLVD , SU I TE 400 AR LIN GTON , TEXAS 76011-4125 November 10, 2010 EA-10-159 Michael Perito Site Vice President Entergy Operations, Inc.

River Bend Station 5485 US Highway 61N St. Francisville, LA 70775 Subject: RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT 05000458/2010004

Dear Mr. Perito:

On September 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your River Bend Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on October 7, 2010, with Mr. E. Olson, General Manager, Plant Operations, and other members of your staff.

The inspections 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.

This report documents one NRC-identified finding and two self-revealing findings of very low safety significance (Green). Two 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 this report. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the violations or the significance of the noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd., Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the River Bend Station facility. In addition, if you disagree with the crosscutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at River Bend Station.

Entergy Operations, Inc. -2-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).

Sincerely,

/RA/

Vincent G. Gaddy, Chief Project Branch C Division of Reactor Projects Docket: 50-458 License: NPF-47

Enclosure:

NRC Inspection Report 05000458/2010004 w/Attachment: Supplemental Information

REGION IV==

Docket: 05000458 License: NPF-47 Report: 05000458/2010004 Licensee: Entergy Operations, Inc.

Facility: River Bend Station Location: 5485 U.S. Highway 61N St. Francisville, LA Dates: July 1 through September 30, 2010 Inspectors: G. Larkin, Senior Resident Inspector, Project Branch C C. Norton, Resident Inspector, Project Branch C R. Hagar, Senior Project Engineer, Project Branch C R. Kumana, Project Engineer, Project Branch C C. Stancil, Resident Inspector, Region II DRP RPB6 BF P. Elkmann, Senior Emergency Preparedness Inspector, Plant Support Branch 1 C. Osterholtz, Senior Operations Engineer, Operations Branch G. Guerra, CHP, Emergency Preparedness Inspector, Plant Support Branch 1 D. Strickland, Operations Engineer, Operations Branch Approved By: Vincent G. Gaddy, Chief, Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000458/2010004; 07/01/2010 - 09/30/2010; River Bend Station, Integrated Inspection

Report; Licensed Operator Requalification; Postmaintenance Testing; Refueling and Other Outage Activities The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Two Green noncited violations and one Green finding of significance were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. The crosscutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a noncited violation of 10 CFR Part 55.49,

Integrity of Examinations and Tests, for the failure of operations training personnel to ensure the integrity of an operating test administered to a licensed operations crew was maintained. One licensed operations crew received two scenarios for their operating test that had been previously administered to a licensed operations staff crew. This failure resulted in a compromise of examination integrity, but did not lead to an actual effect on the equitable and consistent administration of the examination. This finding has a crosscutting aspect in the area of human performance associated with decision making because the licensee did not use conservative assumptions when adopting a 50 percent operating examination overlap practice H.1(b).

The finding is more than minor because, if left uncorrected, the finding could have become more significant in that allowing untested licensed operators at the controls could be a precursor to a significant event if undetected performance deficiencies develop. The finding was determined to have very low safety significance (Green) because the finding resulted in a compromise of the integrity of operating test scenarios and compensatory actions were not immediately taken when the compromise should have been discovered. However, the equitable and consistent administration of the exam was not actually impacted by this compromise. The inspectors applied Inspection Manual Chapter 0609,

Significance Determination Process, Appendix I, Licensed Operator Requalification Significance Determination Process, and determined that the finding should be dispositioned as a Green noncited violation (Section 1R11.2).

Cornerstone: Mitigating Systems

Green.

A self-revealing, very low safety significance (Green) noncited violation 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was reviewed for the licensees failure to prescribe lubrication and installation of bearings on the high-pressure core spray room cooler motors by adequate procedures. In response to this finding, the licensee changed their procedure for performing material equivalency evaluations to require that, when plant components change and associated vendor-recommended maintenance schedules change, licensee personnel also update the corresponding preventive-maintenance tasks. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2010-02919.

This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, in that this finding caused inoperability of the high-pressure core spray. The significance of this finding was determined by completing a Phase 3 analysis in accordance with Inspection Manual Chapter 0609, Appendix A, which determined that the incremental core damage probability maximum was 2x10-7, and that the finding was therefore of very low safety significance (Green). This finding did not represent current licensee performance and consequently did not have a cross-cutting aspect because the cause of this finding was that when the licensee replaced a component by a similar component from a different vendor, no licensee procedure required them to update the associated maintenance frequencies, and because before this finding was identified, the licensee had no reasonable opportunity to identify and correct that deficiency in that procedure.

(Section 1R19).

Green.

A self-revealing finding of very low safety significance (Green) was identified when turbine bypass valve number 1 opened unexpectedly causing the reactor to exceed 100 percent core thermal power. Operators promptly lowered core thermal power to 90 percent to preserve margin to fuel thermal limits. A failed power supply and inadequate calibration and testing of the steam bypass and pressure regulation system and electro-hydraulic control system caused the event. Corrective actions include replacing system power supplies and revising applicable calibration and test instructions. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2010-03343.

This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, technical specification mitigation equipment (main turbine bypass system, end-of-cycle recirculation pump trip function, and rod block instrumentation functions) became inoperable. Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of nontechnical specification equipment; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that this finding did not represent current licensee performance because the preventative maintenance schedule and calibration procedure were developed and approved over two years ago. Therefore, no crosscutting aspect was assigned to this finding (Section 1R20).

Licensee-Identified Violations

One violation of very low safety significance, which was 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

River Bend Station began the inspection period at 100 percent thermal power. On July 23, 2010, the plant reduced reactor power to 90 percent to exercise partially withdrawn control rods and perform turbine bypass valve testing. The plant returned to full power on July 25, 2010. On July 30, 2010, the plant shut down the reactor for a planned outage to replace reactor recirculation pump B seal. On August 10, 2010, the plant returned to continuous full power operations. On August 27, 2010, the plant reduced reactor power to 90 percent to exercise partially withdrawn control rods and perform turbine bypass valve testing. The plant returned to full power on August 27, 2010. On September 10, 2010, the plant reduced reactor power to 74 percent to remove main condenser water box C from service to plug a leaking tube. The plant returned to 100 percent reactor power on September 11, 2010. On September 24, 2010, the plant reduced power to 98 percent for partially withdrawn control rod testing and turbine bypass valve testing and returned to 100 percent reactor power.

REACTOR SAFETY

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

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed a partial system walkdown of the following risk-significant system:

• Division 2 control building chilled water The inspectors selected this system based on its risk significance relative to the reactor safety cornerstones at the time it was inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the system incapable of performing its intended function. The inspectors also inspected accessible portions of the system to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with

the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one partial system walkdown sample as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

The inspectors performed a complete system alignment inspection of the following risk-significant systems to verify their functional capability:

• Division I control building chilled water, August 18, 2010

• Division I MSIV sealing system and penetration valve leakage control, September 15, 2010 The inspectors selected these systems because they were considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors inspected the systems to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the function of these systems. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two complete system walkdown samples as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Inspection Tours

a. Inspection Scope

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

• July 27, 2010, control building, 98-foot elevation and 116-foot elevation

• August 2, 2010, drywell, 70-foot elevation, 95-foot elevation, 114-foot elevation, and 141-foot elevation

• August 17, 2010, control building, 70-foot elevation and 98-foot elevation; diesel generator building, 98-foot elevation

• August 30, 2010, auxiliary building, 78-foot elevation and 98-foot elevation; fuel building, 70-foot elevation, 95-foot elevation, 113-foot elevation, and 148-foot elevation

• August 31, 2010, auxiliary building, 114-foot elevation and 141-foot elevation; reactor building, 141-foot elevation and 186-foot elevation

• September 7, 2010, reactor building, 141-foot elevation, 162-foot elevation, and 186-foot elevation The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan.

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

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review

a. Inspection Scope

On July 13, 2010, the inspectors observed a crew of licensed operators in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications The inspectors compared the crews performance in these areas to pre-established operator action expectations and successful critical task completion requirements.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one quarterly licensed-operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Biennial Inspection

The licensed operator requalification program involves two training cycles that are conducted over a 2-year period. In the first cycle, the annual cycle, the operators are administered an operating test consisting of job performance measures and simulator scenarios. In the second part of the training cycle, the biennial cycle, operators are administered an operating test and a comprehensive written examination.

a. Inspection Scope

To assess the performance effectiveness of the licensed operator requalification program, the inspectors conducted personnel interviews, reviewed both the operating tests and written examinations, and observed ongoing operating test activities.

The inspectors interviewed six licensee personnel, consisting of four operators and two instructors, to determine their understanding of the policies and practices for administering requalification examinations. The inspectors also reviewed operator performance on the written exams and operating tests. These reviews included observations of portions of the operating tests by the inspectors. The operating tests observed included three scenarios that were used in the current biennial requalification cycle. These observations allowed the inspectors to assess the licensee's effectiveness in conducting the operating test to ensure operator mastery of the training program content. The inspectors also reviewed medical records of ten licensed operators for conformance to license conditions and the licensees system for tracking qualifications and records of license reactivation for one operator.

The results of these examinations were reviewed to determine the effectiveness of the licensees appraisal of operator performance and to determine if feedback of performance analyses into the requalification training program was being accomplished.

The inspectors interviewed members of the training department and reviewed minutes of training review group meetings to assess the responsiveness of the licensed operator requalification program to incorporate the lessons learned from both plant and industry events. Examination results were also assessed to determine if they were consistent with the guidance contained in NUREG 1021, "Operator Licensing Examination Standards for Power Reactors", Revision 9, Supplement 1, and NRC Manual Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance Determination Process."

In addition to the above, the inspectors reviewed examination security measures, simulator fidelity and existing logs of simulator deficiencies.

The inspectors completed one inspection sample of the biennial licensed operator requalification program.

b. Findings

Introduction.

The inspectors identified a Green noncited violation of 10 CFR Part 55.49, Integrity of Examinations and Tests, for the failure of operations training personnel to

ensure the integrity of an operating test administered to a licensed operations crew was maintained. This failure resulted in a compromise of examination integrity, but did not lead to an actual effect on the equitable and consistent administration of the examination.

Description.

On August 17, 2010, while performing a biennial requalification inspection in accordance with Inspection Procedure 71111.11, Licensed Operator Requalification Program, the inspectors discovered that during the week of June 23, 2009, licensed operations crew B received two scenarios for their operating test that had been previously administered to a licensed operations staff crew the week of June 10, 2009.

This resulted in licensed operations crew B receiving 100 percent overlap on their operating test scenarios. Entergy Procedure EN-TQ-114, Licensed Operator Requalification Training Program Description, Revision 3, Step 5.7[1](g) requires that at least 50 percent of each annual operating examination (simulator scenarios) shall be comprised of test items not used in any other examination in the same examination cycle. The inspectors noted that the licensee failed to fulfill the procedural requirements of EN-TQ-114, which constituted a compromise of examination integrity required by 10 CFR 55.49. The licensee verified that none of the operators involved with the 2009 integrity compromise were currently performing licensed duties unless they had already passed a 2010 operating examination. The licensee documented this issue in Condition Report CR-RBS-2010-04012.

The inspectors inquired if any of the operations personnel involved in the two overlapped scenarios had signed a security agreement to not divulge the scenario content when the operating tests were first administered the week of June 10, 2009. Of the seven licensed operators who were initially administered the scenarios, three had signed the security agreement and four had not. The inspectors considered that not providing for all licensed operator examinees to sign security agreements to enhance exam integrity a poor practice. The inspectors noted that the 50 percent overlap allowance was a limit that the licensee was using as a goal rather than a limit, leaving no margin for error on overlap. The inspectors determined that the licensee applied non-conservative standards to ensure examination integrity by targeting 50 percent overlap between operating test scenarios. The inspectors concluded that applying non-conservative standards to operating test integrity directly contributed to the occurrence of this violation.

The inspectors were concerned about the overlap standards during in-office inspection activities that took place during the week of August 9, 2010. The inspectors telephoned licensee representatives on August 11, 2010, after discovering that the 2010 requalification exam schedule appeared to indicate that a crew had received an operating test consisting of 100 percent overlap from operating test scenarios that were administered in previous weeks. The licensee representatives indicated that one of the two scenarios scheduled to be administered to that crew had been replaced with a new one (i.e., they did not administer the two scenarios originally scheduled) due to concerns unrelated to examination overlap requirements; as a result of the schedule change, the actual scenario overlap was only 50 percent for that crew. The inspectors considered this a near miss and emphasized to licensee personnel that targeting the 50 percent

overlap limit for requalification exams (which leaves no margin for error in terms of exceeding the overlap limit) was a non-conservative practice. The licensee documented this issue in Condition Report CR-RBS-2010-03848.

Between September 1, 2010, and September 13, 2010, the inspectors evaluated additional information to fully evaluate the significance of the 2009 overlap issue. The inspectors noted that licensee training personnel performed a formal briefing to all operations personnel prior to the administration of their 2009 operating test that specifically directed them NOT to discuss the details of their examination with other personnel. The inspectors also noted that the licensee had interviewed all operations personnel who were involved in the administration of the 2009 operating test that contained excessive overlap. None of the interviewed operators indicated that they had discussed any portions of the operating test with other individuals as per their briefing.

Further, the interviewed operators submitted signed statements to the effect that the details of their examination were not discussed with other individuals. The inspectors also reviewed the grading of the 2009 operating examinations to determine if there was any discernable discrepancy in evaluated performance between operating crews that would indicate that the equitable and consistent administration of the examination had actually been affected. The inspectors found the examination results to be relatively consistent among operating crews, with no abnormalities noted between the crew that was initially evaluated on the operating examination and the crew that received the overlapped operating examination. The inspectors concluded that, although the integrity of the 2009 operating examination was not maintained, no actual affect on the equitable and consistent administration of the 2009 operating examination had occurred.

Analysis.

The failure of training personnel to maintain the integrity of examinations administered to licensed operations personnel was a performance deficiency. The performance deficiency is more than minor because, if left uncorrected, the finding could have become more significant in that allowing untested licensed operators (in this case, operators that had the potential to have an invalid test because of the lack of examination integrity) at the controls could be a precursor to a significant event if undetected performance deficiencies develop. Using Inspection Manual Chapter 0609, Significance Determination Process, Appendix I, Licensed Operator Requalification Significance Determination Process, Phase 1 Worksheets, the finding was determined to have very low safety significance (Green) because, although the finding resulted in a compromise of the integrity of operating test scenarios and compensatory actions were not immediately taken when the compromise should have been discovered, the equitable and consistent administration of the exam was not actually impacted by this compromise. This finding has a crosscutting aspect in the area of human performance associated with decision making because the licensee did not use conservative assumptions when adopting the 50 percent operating examination overlap practice

H.1(b).

Enforcement.

Title 10 CFR 55.49, Integrity of Examinations, requires, in part, that facility licensees shall not engage in any activity that compromises the integrity of any application, test, or examination required by this part. The integrity of a test or examination is considered compromised if any activity, regardless of intent, affected, or,

but for detection, would have affected the equitable and consistent administration of the test or examination. This includes activities related to the preparation, administration, and grading of the tests and examinations required by this part.

Contrary to the above, during the week of June 23, 2009, the licensee engaged in an activity that compromised the integrity of a test required by 10 CFR Part 55. Specifically, training personnel administered two requalification test scenarios to licensed operations crew B that had been previously administered in the requalification testing cycle, resulting in a 100 percent overlap of previously administered operating tests.

Administering an operating test with greater than 50 percent overlap from previously administered operating tests is considered a compromise of the integrity of the test in that it is a practice that would, but for detection, affect the equitable and consistent administration of the tests. The inspectors determined that the compromise of the 2009 operating test did not result in an actual effect on the equitable and consistent administration of the examination. Because this violation is of low safety significance and it has been entered into the licensees corrective action program as Condition Report CR-RBS-2010-04012, this violation is being treated as a noncited violation consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000458/2010004-04, Failure to Maintain Licensed Operator Examination Integrity.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• Standby service water system

• Emergency 480 Vac system

• High pressure core spray

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

• Implementing appropriate work practices

• Identifying and addressing common cause failures

• Scoping of systems in accordance with 10 CFR 50.65(b)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1)

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Loss of steam bypass and pressure regulation channel A, July 23-30, 2010

• Loss of feedwater level control system master controller, August 24, 2010 The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk

analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• CR-RBS-2010-02828, control building chiller 1D low compressor oil temperature, reviewed on July 7, 2010

• CR-RBS-2010-03028, containment unit cooler 1A dirty filters, reviewed on July 7, 2010

• CR-RBS-2010-03208, emergency diesel generator Division 2 combustion air intercooler support bracket weld failures, reviewed on July 16, 2010

• CR-RBS-2010-03345, reactor core isolation cooling flow indication, reviewed on July 26, 2010

• CR-RBS-2010-04584, cycling of service water pressure control valve SWP-PVY32C, reviewed on September 15, 2010 The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Updated Safety Analysis Report to the licensee personnels evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five operability evaluations inspection samples as defined in Inspection Procedure 71111.15-04

b. Findings

No findings were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors reviewed the following postmaintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• WO 236138, HVR-UC5-Functional Test, Remove, Replace, Hybrid, HFC, EQ, reviewed on July 6, 2010

• WO 00241070, HVR-UC1B Failed to Start During Swap for STP, reviewed on July 17, 2010

• WO 00179129, H13-P637-PS2 AR10Z102 - Replace Power Supply, reviewed on August 26, 2010

• WO 00179129, H13-P637-PS1 AR10Z102 - Replace Power Supply, reviewed on August 26, 2010

• WO 00238022, B33-PC001B - Replace the Mechanical Seal, reviewed on September 21, 2010 The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following:

• 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 The inspectors evaluated the activities against the technical specifications, the Updated Safety Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance tests to determine whether the licensee was identifying problems and entering them in the

corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

Introduction.

A self-revealing, very low safety significance (Green) non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was reviewed for the licensees failure to prescribe lubrication and installation of bearings on the high-pressure core spray room cooler motors by adequate procedures.

Description.

On June 25, 2010, after the licensee noted light smoke and loud noise coming from the high-pressure core spray unit cooler, they secured that cooler, and thereby rendered inoperable the high-pressure core spray pump. Subsequent metallurgical inspection revealed that the motors inboard bearing had experienced extensive metal-to-metal contact between the bearing balls and the inner race due to lack of lubrication. Investigation revealed that in 1995, the licensee had replaced the original motor and bearings with a motor and bearings from a different vendor. At that time, the vendor-recommended lubrication frequency had changed from once every three years to once every nine months, and the vendor-recommended bearing-replacement frequency had changed from once every twenty-six years to once every ten years. However, because no procedure required the licensee to verify that maintenance frequencies were adequate, the licensee failed to incorporate these new frequencies into their preventive-maintenance procedures. Instead, the licensee continued to lubricate the bearings every three years and replace the bearings every twenty-six years.

Consequently, the bearings failed on June 25, 2010.

In response to this finding, the licensee changed their procedure for performing material equivalency evaluations, EN-DC-313, Procurement Engineering Process, to require that, when plant components change and associated vendor-recommended maintenance schedules change, licensee personnel also update the corresponding preventive-maintenance tasks.

Analysis.

The performance deficiency was that the licensee had failed in 1995 to provide adequate procedures to prescribe lubrication and installation of the bearings on the high-pressure core spray room cooler motor. That performance deficiency resulted in failure of the motor bearing, which resulted in loss of high-pressure core spray pump safety function. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, in that this finding resulted in loss of the high-pressure core spray pump. Using Inspection Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, this issue screened as potentially risk-significant because the finding represented a loss of high-pressure core spray system safety function. The inspectors performed

a Phase 2 analysis using Inspection Manual Chapter 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, and the River Bend Plant Phase 2 pre-solved table item, High-pressure Core Spray Pump, for an exposure time of four days. The Phase 2 determination screened as a low-risk-significant event. A senior reactor analyst performed a Phase 3 analysis using the Systems Analysis Programs for Hands-on Integrated Reliability Evaluations Version 8.x (SAPHIRE 8), and determined that the corresponding incremental core damage probability maximum was 2x10-7/year. Therefore, the finding was of very low safety significance (Green). As discussed above, the cause of this finding was that when the licensee replaced a component by a similar component from a different vendor, no licensee procedure required them to update the associated maintenance frequencies. However, the inspectors determined that before this finding was identified, the licensee had no reasonable opportunity to identify and correct that deficiency in that procedure. The inspectors therefore determined that this finding did not represent current licensee performance and consequently did not have a cross-cutting aspect.

Enforcement.

10 CFR 50, Appendix B, Criterion V requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Contrary to the above, in 1995, the licensee failed to prescribe activities affecting quality by documented procedures of a type appropriate to the circumstances, in that:

• Lubricating and replacing the bearings on the high-pressure core spray unit cooler motor were activities affecting quality;

• For those activities, procedures of a type appropriate to the circumstances would require lubrication of the bearings every nine months and replacement of the bearings every ten years; and

• Since before 1995, licensee preventive-maintenance procedures have required lubrication of the bearings every three years and replacement of the bearings every twenty-six years.

In response to this finding, the licensee changed their procedure for performing material equivalency evaluations to require that, when plant components change and associated vendor-recommended maintenance schedules change, licensee personnel also update the corresponding preventive-maintenance tasks. Because this finding is of very low safety significance and it has been entered into the licensees corrective action program as Condition Report CR-RBS-2010-2919, this violation is being treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy:

NCV 05000458/2010004-05, Inadequate High-pressure Core Spray Pump Room Cooler Bearing Maintenance.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for planned outage PO-10-01, conducted from July 31 to August 4, 2010, to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense in depth. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

• Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

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

• Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met, and controls over switchyard activities.

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

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

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

• Controls over activities that could affect reactivity.

• Maintenance of secondary containment as required by the technical specifications.

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

• Licensee identification and resolution of problems related to refueling outage activities.

These activities constitute completion of one refueling outage and other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

Introduction.

A self-revealing finding of very low safety significance (Green) was identified when turbine bypass valve number 1 opened unexpectedly causing the reactor to exceed 100 percent core thermal power. Operators promptly lowered core thermal power to 90 percent to preserve margin to fuel thermal limits. A failed power supply and inadequate calibration and testing of the steam bypass and pressure regulation system and electro-hydraulic control system caused the event. Corrective actions include replacing system power supplies and revising applicable calibration and test instructions.

The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2010-03343.

Description.

On July 23, 2010, while the plant was at full power operations, the steam bypass and pressure regulation system pressure control channel A swapped to channel B and turbine bypass valve number 1 opened to approximately 42 percent. Core thermal power increased to approximately 100.5 percent due to decreased reactor feedwater temperatures caused by decreased extraction steam flow to the feedwater heaters. Operators promptly reduced core thermal power to 90 percent to protect fuel thermal limits from additional turbine bypass valve or control valve instability. Technical specification mitigation equipment (main turbine bypass system, end-of-cycle recirculation pump trip function, and rod block instrumentation functions) that rely on turbine first stage pressure were declared inoperable because the calibrated pressure difference between the reactor and turbine first stage instrumentation was altered with steam discharging to the condenser and bypassing the turbine. This event began when a power supply card failed in the steam bypass and pressure regulation system causing pressure control channel A to swap to channel B. The failed power supply card had been in service for greater than 25 years but was qualified for only ten years based on the reliability of the cards electrolytic capacitors.

Following the power supply failure, the total steam flow demand and control valve flow reference signals, processed in the steam bypass and pressure regulation system and electro-hydraulic control system, should have equaled each other. This signal mismatch caused turbine bypass valve number 1 to open. Troubleshooting efforts after the event, revealed that the pressure regulator task instructions were difficult to follow, vague, and incomplete. As a result, certain circuit card voltage readings were outside of their calibration or expected voltage limits. A review of past task performances found that field notes that were added to compensate for inadequacies were never formally incorporated into the tasks instructions. The licensee corrected the steam bypass and pressure regulation system and electro-hydraulic control system PMID 50034892 and 50034898 to successfully perform system calibrations.

Analysis.

Failing to replace a power supply circuit card that had a known material condition restriction in a timely manner and using vague, incomplete, and inaccurate calibration and testing instructions resulted in a plant transient that caused the reactor to exceed 100 percent thermal power was a performance deficiency. This finding was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective to

ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, technical specification mitigation equipment (main turbine bypass system, end-of-cycle recirculation pump trip function, and rod block instrumentation functions) became inoperable. Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet the inspectors determined that the finding was of very low safety significance (Green) because the finding did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of nontechnical specification equipment; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that the cause of this finding was the failure of preventative maintenance optimization process task PMID 17488-01 to replace the steam bypass and pressure regulation system power supply cards prior to exceeding its required 10 replacement frequency. That task had been developed in 2003 and has since been corrected to replace the subject cards within their replacement frequency, so that task does not reflect current licensee performance. Therefore, no crosscutting aspect was assigned to this finding.

Enforcement.

The inspectors did not identify a violation of regulatory requirements because the licensees quality assurance program classifies the steam bypass and pressure regulation system, and the electro-hydraulic control system, as nonsafety-related systems. This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2010-3343. This finding is identified as Finding FIN 05000458/2010004-06: Inadequate Maintenance Results in Unplanned Opening of Main Turbine Bypass Valve.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Updated Safety Analysis Report procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• STP-302-1205, ENS-SWG1B Degraded Voltage Channel Functional, performed on June 15, 2010

• STP-302-1203, ENS-SWG1B Loss of Voltage Channel Functional, performed on June 15, 2010

• STP-403-0301, Containment Unit Cooler HVR-UC1A Flow Rate Verification, performed on July 7, 2010

• STP-257-0202, Standby Gas Treatment System Filter Train B Monthly Operability Test, performed on July 22, 2010

• STP-000-0001, Daily Operating Logs (for unidentified RCS leakage), performed on August 16, 2010

• TSP-0029, Control Bldg. Accumulator Test, performed on August 18, 2010

• STP-057-7705, Primary Containment Airlocks Seal Leakage Rate Test, performed on September 7, 2010

• STP-255-6302, Div II PVLCS Quarterly Valve Operability Test, performed on September 16, 2010

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of eight surveillance testing inspection samples as defined in Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

1EP1 Exercise Evaluation

a. Inspection Scope

The inspectors reviewed the objectives and scenario for the 2010 biennial emergency plan exercise to determine if the exercise would acceptably test major elements of the emergency plan. The scenario simulated a fire in an electrical switchgear, loss of the reactor condensate and feedwater system, a leak in the drywell from the reactor water clean-up bottom head drain, a loss of reactor level leading to core damage and a radiological release to the environment through the Standby Gas Treatment System caused by a steam leak on the reactor core isolation system with failure of the inboard and outboard isolation valves, to demonstrate the licensee personnels capability to implement their emergency plan.

The inspectors evaluated exercise performance by focusing on the risk-significant activities of event classification, offsite notification, recognition of offsite dose consequences, and development of protective action recommendations, in the Control Room Simulator and the following dedicated emergency response facilities:

• Technical Support Center

• Operations Support Center

• Emergency Operations Facility The inspectors also assessed recognition of, and response to, abnormal and emergency plant conditions, the transfer of decision making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of emergency workers, emergency repair evaluation and capability, and the overall implementation of the emergency plan to protect public health and safety and the environment. The inspectors reviewed the current revision of the facility emergency plan, emergency plan implementing procedures associated with operation of the licensees emergency response facilities, procedures for the performance of associated emergency functions, and other documents as listed in the attachment to this report.

The inspectors compared the observed exercise performance with the requirements in the facility emergency plan, 10 CFR 50.47(b), 10 CFR Part 50, Appendix E, and with the guidance in the emergency plan implementing procedures and other federal guidance.

The inspectors attended the postexercise critiques in each emergency response facility to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended a subsequent formal presentation of critique items to plant management.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.01-05.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the third quarter 2010 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Heat Removal System (MS08)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - heat removal system performance indicator for the period from the fourth quarter 2009 through the third quarter 2010. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports for the period of October 2009 through September 2010 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index heat removal system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Residual Heat Removal System (MS09)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - residual heat removal system performance indicator for the period from the fourth quarter 2009 through the third quarter 2010. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 2009 through September 2010 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index residual heat removal system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the fourth quarter 2009 through the third quarter 2010. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions

and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 2008 through September 2009 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one mitigating systems performance index cooling water system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.5 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill and Exercise Performance, performance indicator for the period January 2009 through March 2010. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator; assessments of performance indicator opportunities during predesignated control room simulator training sessions, performance during the 2010 biennial exercise, and performance during other drills. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the drill/exercise performance sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.6 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspectors sampled licensee submittals for the Emergency Response Organization Drill Participation performance indicator for the period January 2009 through March 2010. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator, rosters of personnel assigned to key emergency response organization positions, and exercise participation records. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the emergency response organization drill participation sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.7 Alert and Notification System (EP03)

a. Inspection Scope

The inspectors sampled licensee submittals for the Alert and Notification System performance indicator for the period January 2009 through March 2010. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator and the results of periodic alert notification system operability tests. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the alert and notification system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

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

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees 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. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report 05000458/2010-002-00: Standby Gas Treatment Filter

Inoperable Due to Inadequate Surveillance Test Acceptance Criteria On May 5, 2010, the licensee determined that the standby gas treatment filter B heater circuitry had failed and gone undetected since May 26, 2005. The test procedure used acceptance criteria based on the heaters name plate voltage rating instead of design basis accident bus voltages.

The licensee corrected the test procedure acceptance criteria and replaced a failed neutral bus bar that reduced the heaters capacity. The cause of the inadequate test procedure was a lack of rigor in engineering processes when the heater capacity acceptance criteria were developed. This finding was more than minor because it was associated with auxiliary building barrier performance attribute of the Barrier Integrity Cornerstone. The finding was determined to be of very low safety significance (Green)because the finding only represents a degradation of the radiological barrier function provided by the standby gas treatment system. This is a licensee identified violation of Technical Specification 5.5.7, Ventilation Filter Testing Program. This licensee event report is closed.

.2 (Closed) Licensee Event Report 05000458/2010-003-00: High Pressure Core spray

System Declared Inoperable Due to Failure of Pump Room Cooler This licensee event report discusses that the high pressure core spray would be unavailable after an hours run time to mitigate an accident condition because the high pressure core spray room cooler fan had failed. The fan failed because the motors inboard bearing was not adequately lubricated in accordance with the vendors preventative maintenance recommendations. Contributing to the failure was improper installation of the original bearings in the motor and inaccurate collection of vibration monitoring data. See Section 1R19 for additional details. This licensee event report is closed.

4OA5 Other Activities

To determine the licensees compliance with the decommissioning financial assurance requirements in 10 CFR 50.75, the Nuclear Regulatory Commission reviewed the decommissioning funding report for the River Bend Station, submitted by the licensee on March 30, 2009. The review is described in ADAMS document ML1025200621 and identified three apparent violations. For administrative purposes, these violations have been assigned the tracking numbers listed below (EA-10-159):

• AV 05000458/2010004-01, Failure to provide adequate decommissioning funding assurance from Dec. 31, 2008 through the present (10 CFR 50.75(b)).

• AV 05000458/2010004-02, Failure to provide complete and accurate information by failing to disclose its reliance on a contract in the March 2009 funds status report (10 CFR 50.75(f)(1) and 10 CFR 50.9).

• AV 05000458/2010004-03, Use of a decommissioning funding mechanism that did not meet the requirements of 10 CFR 50.75(e)(1)(v).

4OA6 Meetings

Exit Meeting Summary

On July 8, 2010, the inspectors conducted a telephonic exit meeting to present the results of the onsite inspection of the licensees biennial emergency preparedness exercise to Mr. J. Roberts, Director, Nuclear Safety Assurance, and other members of the licensees staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On September 13, 2010, the inspectors briefed Mr. R. Persons and other members of the licensees staff of the results of the licensed operator requalification program inspection. The licensee representatives acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On October 7, 2010, the inspectors presented the integrated inspection results to Mr. E. Olson, General Manager, Plant Operations, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

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 a noncited violation.

• On May 5, 2010, the licensee determined that the standby gas treatment filter B heater circuitry had failed and gone undetected since May 26, 2005. This was a licensee-identified violation of Technical Specification 5.5.7, Ventilation Filter Testing Program.

See 4OA3, Event Follow-up, Licensee Event Report 05000458/2010-002-00 for additional details.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Burnett, Manager, Emergency Preparedness

G. Bush, Manager, Maintenance

M. Chase, Manager, Training

J. Clark, Assistant Operations Manager - Shift

B. Cox, Manager, Operations

G. Degraw, Superintendent, Training

M. Feltner, Manager, Outage

C. Forpahl, Manager, Engineering Programs & Components

W. Fountain, Senior Licensing Specialist

H. Goodman, Director, Engineering

D. Heath, Supervisor, Radiation Protection

R. Heath, Manager, Chemistry

B. Houston, Manager, Radiation Protection

K. Huffstatler, Senior Licensing Specialist

A. James, Manager, Security

L. Kitchen, Manager, Planning and Scheduling, Outages

R. Kowalewski, Manager, Corrective Actions & Assessments

G. Krause, Assistant Operations Manager - Support

D. Lorfing, Manager, Licensing

W. Mashburn, Manager, Design Engineering

R. McAdams, Manager, System Engineering

E. Olson, General Manager, Plant Operations

M. Perito, Site Vice President

R. Persons, Superintendent, Training

J. Roberts, Director, Nuclear Safety Assurance

T. Shenk, Assistant Operations Manager - Training

D. Williamson, Senior Licensing Specialist

L. Woods, Manager, Quality Assurance

NRC Personnel

G. Larkin, Senior Resident Inspector

C. Norton, Resident Inspector

J. Berry, Physical Security Inspector, NSIR

N. Makris, Reactor Inspector

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

Failure to provide adequate decommissioning funding

05000458/2010004-01 AV assurance from Dec. 31, 2008 through the present (10 CFR 50.75(b)) (Section 4OA5)

Failure to provide complete and accurate information by failing to disclose its reliance on a contract in the March 2009

05000458/2010004-02 AV funds status report (10 CFR 50.75(f)(1) and 10 CFR 50.9)

(Section 4OA5)

Use of a decommissioning funding mechanism that did not

05000458/2010004-03 AV meet the requirements of 10 CFR 50.75(3)(1)(v)

(Section 4OA5)

Opened and Closed

Failure to Maintain Licensed Operator Examination Integrity

05000458/2010004-04 NCV (Section 1R11)

Inadequate High Pressure Core Spray Pump Room Cooler

05000458/2010004-05 NCV Bearing Maintenance (Section 1R19)

Inadequate Maintenance Results in Unplanned Opening of

05000458/2010004-06 FIN Main Turbine Bypass Valve (Section 1R20)

Closed

Standby Gas Treatment Filter Inoperable Due to Inadequate

05000458/2010-002-00 LER Surveillance Test Acceptance Criteria (Section 4OA3)

High Pressure Core spray System Declared Inoperable Due

05000458/2010-003-00 LER to Failure of Pump Room Cooler (Section 4OA3)