IR 05000373/2008005

IR 05000373-08-005, 05000374-08-005; on 10/01/2008 - 12/31/2008; LaSalle County Station, Units 1 & 2; Problem Identification and Resolution

ML090370950
Person / Time
Site:	LaSalle
Issue date:	02/06/2009
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Pardee C Exelon Generation Co, Exelon Nuclear
References
IR-08-005
Download: ML090370950 (43)

Text

February 6, 2009

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000373/2008005; 05000374/2008005

Dear Mr. Pardee:

On December 31, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your LaSalle County Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on January 13, 2009, with Site Vice President, Mr. Daniel Enright, and other members of your staff.

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

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, one NRC-identified finding of very low safety significance was identified. The finding involved a violation of NRC requirements. However, because of its very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the issue as a Non-Cited Violation (NCV) in accordance with Section VI.A.1 of the NRC Enforcement Policy.

If you contest the subject or severity of this NCV, 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 LaSalle County Station.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (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/

Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Enclosure: Inspection Report 05000373/2008005; 05000374/2008005 w/Attachment: Supplemental Information cc w/encl: Site Vice President - LaSalle County Station Plant Manager - LaSalle County Station Manager Regulatory Assurance - LaSalle County Station Senior Vice President - Midwest Operations Senior Vice President - Operations Support Vice President - Licensing and Regulatory Affairs Director - Licensing and Regulatory Affairs Manager Licensing - Braidwood, Byron and LaSalle Associate General Counsel Document Control Desk - Licensing Assistant Attorney General J. Klinger, State Liaison Officer, Illinois Emergency Management Agency Chairman, Illinois Commerce Commission

SUMMARY OF FINDINGS

IR 05000373/2008-005, 05000374/2008-005 10/01/2008 -12/31/2008; LaSalle County Station,

Units 1 & 2; Problem Identification and Resolution.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding was identified by the inspectors.

The finding was considered a Non-Cited Violation (NCV) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified an NCV for the licensees failure to comply with 10 CFR 50, Appendix B, Criterion XI, Test Control. Specifically, the licensee failed to establish a minimum diesel generator (DG) run time of at least five minutes when performing the hot restart test as is called for by Regulatory Guide 1.9, Selection,

Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class 1E Onsite Electric Power Systems at Nuclear Power Plants, Revision 3. The licensees Updated Final Safety Analysis Report (UFSAR), Appendix B commits to Regulatory Guide 1.9, Revision 3 with noted exceptions for testing of the sites emergency diesel generator units.

This finding is greater than minor because it is associated with the procedure quality attribute and affected the objective of the Mitigating Systems Cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This finding was determined to be a finding of very low safety significance because all IMC 0609 phase 1 Mitigating Systems issue characterization questions were answered no. The inspector determined there was no cross cutting aspect associated with this finding. (Section 4OA2.4)

Licensee-Identified Violations

No violations of significance were identified.

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit began the inspection period in mode 3 (hot shutdown). It had been shutdown on September 28, 2008 to perform repairs of a hydrogen leak on the main generator housing.

Following the repairs, the unit was returned to full power on October 4, 2008. On October 6, 2008, power was reduced to approximately 70 percent for control rod pattern adjustments and the unit was returned to full power on October 7, 2008. On December 20, 2008, the unit commenced a reduction in power to approximately 72 percent to perform control rod sequence exchange and to repair the normal drain valve in one of the low pressure water heaters. The unit returned to full power on December 21, 2008, and remained there for the rest of the inspection period.

Unit 2 The unit began the inspection period operating at full power. On October 8, 2008, power was reduced to approximately 82 percent to perform repairs of the Linear Voltage Differential Transmitter (LVDT) for Turbine Control Valve #3. The unit was returned to full power on October 9, 2008. On October 18, 2008, power was reduced to approximately 72 percent for control rod exercising, pattern adjustments and fuel channel distortion testing. Full power was restored on October 19, 2008. On November 29, 2008, power was reduced to approximately 82 percent to perform control rod pattern adjustments. The unit was returned to full power on November 30, 2008. On December 1, 2008, power was reduced to approximately 82 percent to perform repairs of the LVDTs for Turbine Control Valve #3. Full power was restored on December 2, 2008. On December 14, 2008, power was reduced to approximately 70 percent for control rod pattern adjustments and fuel channel distortion testing. The unit was returned to full power on December 15, 2008 and that same day it initiated coast down for refueling outage L2R12 which was scheduled to commence on January 19,

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the UFSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the Attachment. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• Control room (VC) and auxiliary electrical equipment room (VE) ventilation;

• Diesel generator area ventilation;

• Condensate storage tank heater control system.

This inspection constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 1 A residual heat removal (RHR) service water (WS) during 1B work;

• 0 DG with 2A DG out of service; and

• B VC Ventilation during A VC work.

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the

.

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

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Unit 1 reactor building 786 (Fire zone 2D);

• Unit 2 high pressure core spray (HPCS) room (Fire zone 3H2);

• Unit 2 Division II switchgear (Fire zone 4E4); and

• Unit 1 Division 1 RHR core standby cooling system (Fire zone 7C6).

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

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

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

b. Findings

No findings of significance were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the Attachment to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of the WS and circulating water (CW) systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant area to assess the adequacy of newly installed seismic restraining devices:

• WS/CW piping modifications to mitigate turbine building flooding.

This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

.1 Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the individual Job Performance Measure operating tests, and the simulator operating tests (required to be given per 10 CFR 55.59(a)(2)) administered by the licensee from November 2008 through December 2008 as part of the licensees operator licensing requalification cycle. These results were compared to the thresholds established in IMC 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP)." The evaluations were also performed to determine if the licensee effectively implemented operator requalification guidelines established in NUREG 1021, Operator Licensing Examination Standards for Power Reactors, and IP 71111.11, Licensed Operator Requalification Program. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Resident Inspector Quarterly Review

a. Inspection Scope

On November 15, 2008, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

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

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

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Primary containment isolation system (PCIS); and

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

• implementing appropriate work practices;

• identifying and addressing common cause failures;

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

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

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

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

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

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• 1B DG emergent repair and yellow risk;

• Yellow risk on both units for planned work;

• Unit 2 Division II DC battery charger planned outage; and

• Emergent replacement of a unit 1 main steam line high flow switch.

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

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

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Unit 1 control rod 34-31 excessive withdrawal speed;

• Emergency core cooling system (ECCS) room cooler degraded flow condition;

• 1B DG governor shutdown solenoid failure; and

• Unit 1 containment tendon covers with rust and calcium deposits.

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing (PMT)

a. Inspection Scope

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

• 0B VE compressor run after replacement;

• 2A containment ventilation (VP) chiller return to service; and

• 1A reactor protection system (RPS) motor generator set return to service after controller box modification.

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

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

This inspection constituted three PMT samples as defined in IP 71111.19-05.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• LOS-DG-M3: 1B DG monthly idle start (Routine);

• LOS-CS-SR1: secondary containment leak rate test (Routine); and

• LOS-LP-Q1: 1C low pressure coolant injection quarterly pump and valve surveillance (IST).

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

• did preconditioning occur;

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

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

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

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

• measuring and test equipment calibration was current;

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

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

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

• test equipment was removed after testing;

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

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

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

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

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

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

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2PS2 Radioactive Material Processing and Transportation (71122.02)

.1 Radioactive Waste System

a. Inspection Scope

The inspectors reviewed the liquid and solid radioactive waste system description in the UFSAR for information on the types and amounts of radioactive waste (radwaste)generated and disposed. The inspectors reviewed the scope of the licensees audit program with regard to radioactive material processing and transportation programs to verify that it met the requirements of 10 CFR 20.1101(c).

This inspection constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

.2 Radioactive Waste System Walkdowns

a. Inspection Scope

The inspectors performed walkdowns of the liquid and solid radwaste processing systems to verify that the systems agreed with the descriptions in the UFSAR and the Process Control Program and to assess the material condition and operability of the systems. The inspectors reviewed the status of radwaste processing equipment that was not operational and/or was abandoned in place. The inspectors reviewed the licensees administrative and physical controls to ensure that the equipment would not contribute to an unmonitored release path or be a source of unnecessary personnel exposure.

The inspectors reviewed changes to the waste processing system to verify that the changes were reviewed and documented in accordance with 10 CFR 50.59 and to assess the impact of the changes on radiation dose to members of the public. There were no changes during the inspection period. The inspectors reviewed the current processes for transferring waste resin into shipping containers to determine if appropriate waste stream mixing and/or sampling procedures were utilized. The inspectors also reviewed the licensees methods for waste concentration averaging to determine if representative samples of the waste product were provided for the purposes of waste classification, as required by 10 CFR 61.55.

This inspection constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

.3 Waste Characterization and Classification

a. Inspection Scope

The inspectors reviewed the licensees radiochemical sample analysis results for each of the licensees waste streams, including dry active waste, spent resins, and filters. The inspectors also reviewed the licensees use of scaling factors to quantify difficult-to-measure radionuclides (e.g., pure alpha or beta emitting radionuclides). The reviews were conducted to verify that the licensees program assured compliance with 10 CFR 61.55 and 10 CFR 61.56, as required by Appendix G of 10 CFR Part 20. The inspectors also reviewed the licensees waste characterization and classification program to ensure that the waste stream composition data accounted for changing operational parameters and thus remained valid between the annual sample analysis updates.

This inspection constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

.4 Shipment Preparation and Shipment Manifests

a. Inspection Scope

The inspectors reviewed the documentation of shipment packaging, radiation surveys, package labeling and marking, vehicle inspections and placarding, emergency instructions, determination of waste classification/isotopic identification, and licensee verification of shipment readiness for five non-excepted material and radwaste shipments made in 2007 and 2008. The shipment documentation reviewed consisted of:

• Two LSA-II, One LSA-I, and One Type A Shipments to Waste Processors; and

• One Type-B(U) Packages to Barnwell.

For each shipment, the inspectors determined if the requirements of 10 CFR Parts 20 and 61 and those of the Department of Transportation (DOT) in 49 CFR Parts 170-189 were met. Specifically, records were reviewed and staff involved in shipment activities was interviewed to determine if packages were labeled and marked properly, if package and transport vehicle surveys were performed with appropriate instrumentation, if radiation survey results satisfied DOT requirements, and if the quantity and type of radionuclides in each shipment were determined accurately. The inspectors also determined whether shipment manifests were completed in accordance with DOT and NRC requirements, if they included the required emergency response information, if the recipient was authorized to receive the shipment, and if shipments were tracked as required by 10 CFR Part 20, Appendix G.

This inspection constitutes one sample as defined in Inspection Procedure 71122.02-5.

Selected staff involved in shipment activities were observed by the inspectors to determine if they had adequate skills to accomplish shipment related tasks and to determine if the shippers were knowledgeable of the applicable regulations to satisfy package preparation requirements for public transport with respect to NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, and 49 CFR Part 172 Subpart H.

This inspection constitutes one sample as defined in Inspection Procedure 71122.02-5.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed condition reports, audits and self assessments that addressed radioactive waste and radioactive materials shipping program deficiencies since the last inspection to verify that the licensee had effectively implemented the CAP and that problems were identified, characterized, prioritized and corrected. The inspectors also verified that the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution.

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

• Initial problem identification, characterization, and tracking;

• Disposition of operability/reportability issues;

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

• Identification of repetitive problems;

• Identification of contributing causes;

• Identification and implementation of effective corrective actions;

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

• Implementation/consideration of risk-significant operational experience feedback.

This inspection constituted one sample as defined in IP 71122.02-5.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the safety system functional failures performance indicator (PI) for unit 1 and unit 2 for the period from the 4th quarter 2007 through the 3rd quarter 2008. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73" definitions and guidance, were used. The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance WOs, issue reports (IRs), event reports and NRC Integrated Inspection Reports for the period of October 2007 through September 2008 to validate the accuracy of the submittals.

The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two safety system functional failures samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.2 Mitigating Systems Performance Index (MSPI) - Emergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - emergency AC power system PI for unit 1 and unit 2 for the period from the fourth quarter 2007 through the third quarter 2008. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, IRs, event reports and NRC Integrated Inspection Reports for the period of October 2007 through September 2008 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI emergency AC power system samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.3 MSPI - High Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - high pressure injection systems PI for unit 1 and unit 2 for the period from the 4th quarter 2007 through the 3rd quarter 2008. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors reviewed the licensees operator narrative logs, IRs, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2007 through September 2008 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and identified that an unavailability period of 6.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> for unit 1 HPCS was not properly reported. This was entered into the licensees CAP as IR 840907. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI high pressure injection systems samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.4 MSPI - Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - heat removal system PI for unit 1 and unit 2 reactor core isolation cooling (RCIC) for the period from the 4th quarter 2007 through the 3rd quarter 2008. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the licensees operator narrative logs, IRs, event reports, MSPI derivation reports, and NRC Integrated Inspection Reports for the period of October 2007 through September 2008 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted two MSPI heat removal system samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.5 MSPI - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - RHR system PI for unit 1 and unit 2 for the period from the 4th quarter 2007 through the 3rd quarter 2008. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the licensees operator narrative logs, IRs, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2007 through September 2008 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and identified that 1.9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> of unavailability on Unit 2 were reported in error.

This issue was captured in the licensees CAP as IR 857522. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI RHR system samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

.6 MSPI - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - cooling water systems PI for Unit 1 and Unit 2 for the period from the fourth quarter 2007 through the third quarter 2008. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, was used. The inspectors reviewed the licensees operator narrative logs, IRs, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of October 2007 through September 2008 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees IR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI cooling water system samples as defined in IP 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

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

a. Scope

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

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

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

b. Findings

No findings of significance were identified.

.2 Daily Corrective Action Program Reviews

a. Scope

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

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

b. Findings

No findings of significance were identified.

.3 Semi-Annual Trend Review

a. Scope

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

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

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

b. Findings

No findings of significance were identified.

.4 Selected Issue Follow-Up Inspection: Review of Operating Experience Smart Sample:

OpESS FY 2008-01, Negative Trend and Recurring Events Involving Emergency Diesel Generators

a. Scope

The inspectors performed an in-depth review of the testing and maintenance standards associated with the sites emergency DGs. Specifically, the inspectors reviewed licensing basis documents such as the UFSAR, TS, industry standards, and NRC issued Regulatory Guides committed to by the licensee to ensure that the sites diesel generators were being tested and maintained in accordance with the licensing basis.

The inspectors verified surveillance procedures identified the appropriate acceptance criteria when applicable and that testing was being performed correctly in accordance with committed to testing methodologies. In addition, the inspectors performed in field walkdowns of the sites emergency diesel generators to ensure their material conditions and support systems were properly maintained.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

Introduction The inspectors' identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion XI, Test Control, for the failure to establish a minimum DG run time of at least five minutes when performing the hot restart test as is called for by Regulatory Guide 1.9, Selection, Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class 1E Onsite Electric Power Systems at Nuclear Power Plants, Revision 3.

Description While reviewing DG testing and maintenance methodologies at LaSalle Station as a part of operating experience smart sample OpESS 2008-01, the inspectors identified that licensee procedures for performing the DG hot restart test did not include a minimum run time requirement of five minutes as is required in Regulatory Guide 1.9, Selection, Design, Qualification, and Testing of Emergency Diesel Generator Units Used as Class 1E Onsite Electric Power Systems at Nuclear Power Plants, Revision 3. The inspectors noted that the licensee is committed to Regulatory Guide 1.9, Revision 3 for testing of the sites DGs as is noted in Appendix B of the LaSalle County Station UFSAR.

Regulatory Guide 1.9, Revision 3 section 2.2.10 stated in part Demonstrate hot restart functional capability at full-load temperature conditions ... by verifying that the emergency diesel generator starts on a manual or autostart signal, attains the required voltage and frequency within acceptable limits and time, and operates for longer than five minutes. The inspectors noted that licensee procedures which performed the hot restart test were solely based on acceptance criteria specified in the stations TS Surveillance Requirement 3.8.1.15 which did not include the minimum five minute run time. The inspectors noted that the licensees TS Bases document described the minimum 5 minute run time for those surveillances which required it as a TS acceptance criteria by stating in part, the surveillance should be continued for a minimum of five minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.

The inspectors subsequently reviewed operator logs to determine if the DGs had been run for the minimum five minutes when hot restart testing had been last performed. The inspectors identified that on September 19, 2007, the 1A diesel was run for only three minutes and on October 9, 2007, the 2B diesel was run for only two minutes when the hot restart test was last performed.

Analysis The inspectors concluded that the failure to incorporate testing requirements, committed to in the UFSAR, in the stations surveillance requirement procedures constituted a performance deficiency that warranted evaluation using the SDP. Specifically, the licensee failed to require a five minute minimum run time to ensure engine stability as committed to in the UFSAR and as called for in Regulatory Guide 1.9, Revision 3 in station surveillance testing procedures. Using IMC 0612, Appendix B, Issue Screening, the inspectors determined that the finding was of more than minor significance because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone, and it affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

To further assess significance of the finding, the inspectors used IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, and determined that Mitigating Systems was the only cornerstone affected. Using the Mitigating Systems column on the Phase 1 SDP characterization worksheet, the inspectors determined that the finding was not a design or qualification deficiency; did not represent the loss of a safety function; did not represent the loss of a single train for greater than the TS allowed outage time; did not involve risk-significant non-TS equipment; and was not potentially risk significant due to seismic, flooding, or severe weather. In this case, the diesels remained capable of performing their intended safety functions if called upon. Therefore, the finding was considered to be of very low safety significance (Green).

The inspector did not identify a cross-cutting aspect associated with this finding because the concern was not indicative of current licensee performance.

Enforcement Appendix B of 10 CFR Part 50, Criterion XI, Test Control, requires, in part, that a test program be established to assure that all testing required to demonstrate that structures, systems and components will perform satisfactorily in service is identified and performed in accordance with written test procedures which incorporate the requirements and acceptance limits contained in the applicable design documents. Contrary to this requirement, the inspectors identified that on September 19, 2007, when performing LOP-DG-R1A and on October 9, 2007, when performing LOS-DG-R2B, the hot restart test for the 1A DG and the 2B DG respectively, the engines were not run for the minimum required five minute period to ensure engine stabilization as is called for in Regulatory Guide 1.9, Revision 3. The licensees surveillance requirement procedures for all five emergency DGs did not direct the operators to run the diesel for any minimum time requirement, contrary to the licensing basis document. Because the finding is of very low safety significance and has been entered into the licensees CAP as IR 861714, this violation of 10 CFR 50, Appendix B, Criterion XI, is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy.

(NCV 05000373/2008005-01; 05000374/2008005-01).

4OA5 Other Activities

.1 Implementation of Temporary Instruction (TI) 2515/176, Emergency Diesel generator

Technical Specification Surveillance Requirements Regarding Endurance and Margin Testing a. The objective of TI 2515/176 was to gather information to assess the adequacy of nuclear power plant emergency diesel generator endurance and margin testing as prescribed in plant-specific TSs. The inspectors reviewed the licensee's TS, procedures, and calculations and interviewed licensee personnel to complete the TI. The information gathered for this TI was forwarded to the Office of Nuclear Reactor Regulation for further review and evaluation on December 15, 2008. This TI is complete at LaSalle County Station; however, this TI 2515/176 will not expire until August 31, 2009. Additional information may be required after review by the Office of Nuclear Reactor Regulation.

b. Findings

No findings of significance were identified.

.2 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

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

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

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

b. Findings

No findings of significance were identified.

.3 Closed Unresolved Item (URI)05000373/2007004-03;050003742007004-3: State Of

South Carolina Suspended Access To Barnwell Disposal Facility On August 22, 2007 The inspectors reviewed the circumstances surrounding a shipment of radioactive waste from LaSalle County Station to Barnwell, South Carolina on June 29, 2007. During unloading and cleaning of the shipping cask at Barnwell, the staff noticed elevated dose rates in the cask and recovered a small contaminated particle that was subsequently, properly disposed by the site contractor personnel. On August 22, 2007, LaSalle Station was notified that the State of South Carolina had issued a notice of non-compliance and restricted access to the Barnwell facility. After an administrative and legal review process that concluded on October 16, 2008, Exelon and the State of South Carolina entered a Consent Order of Dismissal that vacated all prior administrative decisions associated with the shipment.

The inspectors reviewed the shipping documentation, the procedures used to load the shipment contents, the Certificate of Compliance for the shipping cask, the licensees root cause analysis of the event and procedural changes as a result of the root cause analysis. Upon review of the event, the inspectors determined that LaSalle Station failed to meet a self-imposed standard to limit foreign debris and loose impediments.

Specifically, licensee approved and implemented, NUKEM Technical1016, Handling the TN-RAM Cask Using the Pool Filling Method, Step 7.4.5.7, directs video surveillance to identify and eliminate foreign debris outside of the liner. However, the recipient of the shipment identified that this standard had not been met. The inspectors reviewed the circumstances surrounding the issue and concluded that the finding could not be reasonably viewed as a precursor to a more significant event, if left uncorrected the finding would not become a more significant safety concern, the finding does not relate to a performance indicator and the finding is not associated with one the cornerstone attributes in IMC 0612 and does not affect a cornerstone objective. Therefore, the failure to meet a self-imposed standard is minor. The inspectors did not identify any violations of NRC requirements. This Unresolved Item, URI 05000373/2007004-03; 05000374/2007004-03, is closed.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 13, 2009, the inspectors presented the inspection results to Mr. D. Enright, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• the results of the radioactive material processing and transportation inspection with the Site Vice President, Mr. D. Enright, on December 15, 2008;

• the results of the TI 2515/176 inspection with Mr. D. Rhoades, Plant Manager, and other licensee staff on November 21, 2008; and

• the licensed operator requalification training annual operating test results with Mr. L. Blunk, Operations Training Manager, on December 29, 2008.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

4OA7 Licensee-Identified Violations

No findings of significance were identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

D. Enright, Site Vice President

D. Rhoades, Plant Manager

J. Bashor, Site Engineering Director

L. Blunk, Operations Training Manager

S. Wilkinson, Chemistry Manager

H. Do, Corporate Inservice Inspection Manager

B. Ginter, Engineering Programs Manager

F. Gogliotti, System Engineering Senior Manager

W. Hilton, Engineering Supervisor - Mechanical/Structural

K. Ihnen, Nuclear Oversight Manager

A. Kochis, Inservice Inspection Engineer

R. Leasure, Radiation Protection Manager

S. Marik, Operations Director

J. Miller, NDE Level III

B. Rash, Maintenance Director

J. Rommel, Design Engineering Senior Manager

K. Rusley, Emergency Preparedness Manager

J. Shields, Inservice Inspection Program Supervisor

T. Simpkin, Regulatory Assurance Manager

H. Vinyard, Shift Operations Superintendent

G. Wilhelmsen, Design Manager

J. White, Site Training Director

C. Wilson, Station Security Manager

D. Amezaga, GL 89-13 Program Owner

J.C. Feeney, NOS Lead Assessor

D. Henly, Design Engineer

Nuclear Regulatory Commission

K. Riemer, Chief, Reactor Projects Branch 2

LIST OF ITEMS

Opened

05000373/2008005-01; NCV Failure to Incorporate Regulatory Guide 1.9 Testing

05000374/2008005-01 Methodology into Procedures (Section 4OA2.4)

Closed

05000373/2008005-01; NCV Failure to Incorporate Regulatory Guide 1.9 Testing

05000374/2008005-01 Methodology into Procedures (Section 4OA2.4)

05000373/2007004-03; URI State Of South Carolina Suspended Access To Barnwell

05000374/2007004-03 Disposal Facility On August 22, 2007 (Section 4OA5)

Attachment