IR 05000373/2007009

IR 05000373-07-009, 05000374-07-009, on 08/27/07 - 09/28/07, LaSalle County Station, Units 1 and 2; Component Design Basis Inspection

ML073130611
Person / Time
Site:	LaSalle
Issue date:	11/09/2007
From:	Ann Marie Stone NRC/RGN-III/DRS/EB2
To:	Crane C Exelon Generation Co, Exelon Nuclear
References
IR-07-009
Download: ML073130611 (42)

Text

ber 9, 2007

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2 NRC COMPONENT DESIGN BASIS INSPECTION REPORT 05000373/2007009(DRS); 05000374/2007009(DRS)

Dear Mr. Crane:

On September 28, 2007, the U. S. Nuclear Regulatory Commission (NRC) completed a biennial component design basis baseline inspection at your LaSalle County Station, Units 1 and 2. The enclosed report documents the inspection findings, which were discussed on September 28, 2007, with the Site Engineering Director, Mr. J. Bashor and other members of your staff.

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

The inspectors reviewed selected calculations, design bases documents, procedures, and records; observed activities; and interviewed personnel. Specifically, this inspection focused on the design of components that were risk significant and had low margin.

Based on the results of this inspection, four NRC-identified findings of very low safety significance were identified, all of which involved violations of NRC requirements. However, because these violations were of very low safety significance and because they were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRCs Enforcement Policy.

If you contest any finding or the subject or severity of any Non-Cited Violation in this report, 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 copies 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 NRC Resident Inspector Office at the LaSalle County Station. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any), will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRCs Agencywide Documents Access and Management System (ADAMS),

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

Sincerely,

/RA/

Ann Marie Stone, Chief Engineering Branch 2 Division of Reactor Safety Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Enclosure: Inspection Report 05000373/2007009(DRS);

05000374/2007009(DRS)

w/Attachment: Supplemental Information cc w/encl: Site Vice President - LaSalle County Station LaSalle County Station Plant Manager Regulatory Assurance Manager - LaSalle County Station Chief Operating Officer Senior Vice President - Nuclear Services Senior Vice President - Mid-West Regional Operating Group Vice President - Mid-West Operations Support Vice President - Licensing and Regulatory Affairs Director Licensing - Mid-West Regional Operating Group Manager Licensing - Clinton and LaSalle Senior Counsel, Nuclear, Mid-West Regional Operating Group Document Control Desk - Licensing Assistant Attorney General Illinois Emergency Management Agency State Liaison Officer Chairman, Illinois Commerce Commission

SUMMARY OF FINDINGS

IR 05000373/2007009, 05000374/2007009; 08/27/07 - 09/28/07; LaSalle County

Station, Units 1 and 2; Component Design Basis Inspection.

The inspection was a 3-week onsite baseline inspection that focused on the design of components that are risk significant and have low design margin. The inspection was conducted by regional engineering inspectors and two consultants. Four findings of very low safety significance were identified, all with associated Non-Cited Violations (NCVs).

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 NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649,

Reactor Oversight Process, Revision 3; dated July 2000.

A. Inspector-Identified and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of the LaSalle County Station Facility Operating License associated with the Fire Protection Program for failure to ensure that all necessary testing was identified and performed. Specifically, the licensee failed to periodically test remote-local keylock control switches on the switchgear for the emergency buses which are required to implement a safe shutdown for a plant fire in accordance with the licensees Safe Shutdown Analysis described in Appendix H, Section H.4 of the Fire Protection Report.

This issue was entered into the licensees corrective action program, and as a compensatory measure, the licensee implemented procedure changes to the safe shutdown procedures that gave direction to manually close a breaker if the breaker failed to close using the remote-local keylock switch. The licensee also successfully tested a portion of the remote-local switches and initiated efforts to determine a schedule for testing of the remaining keylock switches.

The finding was more than minor because the licensee did not ensure the operability and functional performance of the remote-local keylock control switches to perform satisfactorily in service. The finding was of very low safety significance based on the results of a Phase 1 screening completed in accordance with IMC 0609, Appendix F,

Fire Protection Significant Determination Process. The inspectors determined that there was no cross-cutting aspect to this finding. (Section 1R21.3.b.1)

Green.

The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, in that, the design bases for the manual backwash valve position values for the Diesel Generator Cooling Water (DGCW) backwash strainers were not correctly translated into procedures and instructions. Specifically, the manual backwash valve positions derived from flow test surveillance procedures based on hydraulic calculation models were not translated into operations procedures for manual operation of the DGCW strainer backwash valves. This issue was entered into the licensees corrective action program, and the licensee updated the applicable operating procedure to reflect the correct manual settings for the DGCW strainer backwash valves.

This issue was more than minor because the DGCW backwash valves could be manually opened more than required during a loss of power event, and thus divert some cooling flow from post accident required equipment. The finding was of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, because on re-evaluation, the design function was maintained. The cause of the finding is related to the cross-cutting element of Human Performance, Resources, because the licensee failed to have complete, accurate, and up-to-date procedures (H.2(c)). (Section 1R21.3.b.2)

Green.

A finding of very low safety significance was identified by the inspectors associated with a Non-Cited Violation of 10 CFR 50.63, Loss of All Alternating Current Power.

Specifically, the licensee did not have an appropriate analysis to determine the capability of coping with a station blackout, in that, it had no analysis that verified the proper operation of the reactor core isolation cooling (RCIC) turbine at the elevated suppression pool temperatures encountered during a station blackout event. This issue was entered into the licensees corrective action program. The licensee obtained additional information and performed a preliminary analysis which showed that the RCIC turbine would operate as required.

This finding was more than minor because the licensee did not have an analysis that demonstrated the availability and reliability of the RCIC turbine at the elevated suppression pool temperatures encountered during a station blackout event. The issue was of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situation, because the licensee obtained additional data from the RCIC turbine manufacturer and performed a functionality analysis which demonstrated the pump turbine could operate at heightened suppression pool temperatures. The inspectors determined that there was no cross-cutting aspect to this finding. (Section 1R21.3.b.3)

• Severity Level IV. The inspectors identified an NCV of 10 CFR Part 50.59, Changes,

Tests, and Experiments, which had very low safety significance. Specifically, the licensee failed to complete a 50.59 evaluation for removing main control room lake level instrumentation from service. Although the UFSAR stated that the lake level was continuously monitored in the main control room, the level instrument had not functioned reliably for several years and was removed from the plant maintenance schedule in December 2005. At the time of the inspection, control room monitoring of the lake level was not available. The licensee entered the issue into their corrective action program and initiated more frequent operator rounds as a compensatory measure.

The finding was more than minor because the inspectors could not reasonably determine that this change would not have ultimately required prior approval from the NRC. This finding was categorized as Severity Level IV because the underlying technical issue for the finding was determined to be of very low safety significance based on a Phase 1 screening in accordance with IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situation. The inspectors concluded that this finding was cross-cutting in the area of Human Performance, Resources, because the licensee failed to effectively address a long standing equipment issue (H.2(a)). (Section 1R21.3.b.4)

Licensee-Identified Violations

None

REPORT DETAILS

1R21 Component Design Bases Inspection

.1 Introduction

The objective of the component design bases inspection is to verify that design bases have been correctly implemented for the selected risk significant components and that operating procedures and operator actions are consistent with design and licensing bases. As plants age, their design bases may be difficult to determine and an important design feature may be altered or disabled during a modification. The Probabilistic Risk Assessment (PRA)model assumes the capability of safety systems and components to perform their intended safety function successfully. This inspectible area verifies aspects of the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for which there are no indicators to measure performance.

Specific documents reviewed during the inspection are listed in the attachment to the report.

.2 Inspection Sample Selection Process

The inspectors selected risk significant components and operator actions for review using information contained in the licensees 2006B PRA Model. In general, the selection was based upon the components and operator actions having a risk achievement worth of greater than 2.0. The operator actions selected for review included actions taken by operators both inside and outside of the control room during postulated accident scenarios.

The inspectors performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases have been correctly implemented and maintained. This design margin assessment considered original design reductions caused by design modification, or power uprates, or reductions due to degraded material condition. Equipment reliability issues were also considered in the selection of components for detailed review. These included items such as performance test results, significant corrective action, repeated maintenance activities, maintenance rule (a)(1) status, components requiring an operability evaluation, NRC resident inspector input of problem areas/equipment, and system health reports. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense in depth margins. A summary of the reviews performed and the specific inspection findings identified are included in the following sections of the report.

.3 Component Design

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specifications (TS), design basis documents, drawings, calculations and other available design basis information, to determine the performance requirements of the selected components. The inspectors used applicable industry standards, such as the American Society of Mechanical Engineers (ASME) Code, Institute of Electrical and Electronics Engineers Standards and the National Electric Code, to evaluate acceptability of the systems design. The NRC also evaluated licensee actions, if any, taken in response to NRC issued operating experience, such as Bulletins, Generic Letters (GLs) and Information Notices (INs). The review was to verify that the selected components would function as designed when required and support proper operation of the associated systems. The attributes that were needed for a component to perform its required function included process medium, energy sources, control systems, operator actions, and heat removal.

The attributes to verify that the component condition and tested capability was consistent with the design bases and was appropriate may include installed configuration, system operation, detailed design, system testing, equipment and environmental qualification, equipment protection, component inputs and outputs, operating experience, and component degradation.

For each of the components selected, the inspectors reviewed the maintenance history, system health reports, operating experience-related information and licensee corrective action program documents. Field walkdowns were conducted for all accessible components to assess material condition and to verify that the as-built condition was consistent with the design. Other attributes reviewed are included as part of the scope for each individual component.

The following 17 Unit 1 and Unit 2 components were reviewed (17 inspection samples):

4160V Switchgear 241Y (2AP04E, Unit 2, Division 1): The inspectors reviewed selected calculations for electrical distribution system load flow/voltage drop, degraded voltage protection, short-circuit, and electrical protection and coordination.

The adequacy and appropriateness of design assumptions and calculations were reviewed to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions. The switchgears protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst-case short-circuit conditions. Automatic and manual transfer schemes between alternate offsite sources and the shared emergency diesel generator (i.e., Unit 0) were reviewed. To ensure that adequate margin existed for design basis events with a loss of offsite power, the emergency diesel generators steady-state loading calculations were reviewed. Voltage protection schemes were reviewed for degraded and loss of voltage relaying. The inspectors verified that degraded and loss of voltage relays were set in accordance with calculations, and that associated calibration procedures were consistent with calculation assumptions, associated time delays and set-point accuracy calculations. In addition, the latest surveillance was reviewed. The inspectors evaluated selected portions of the licensee response to NRC Generic Letter (GL) 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power, dated February 1, 2006. The stations interface and coordination with the transmission system operator for plant voltage requirements and notification set-points were reviewed. The inspectors reviewed the adequacy of instrumentation/alarms available. To ensure that breakers were maintained in accordance with industry and vendor recommendations, the inspectors reviewed the preventive maintenance inspection and testing procedures. Switchgear and breaker failure history was also reviewed. The inspectors reviewed the operating procedures for normal, abnormal, and emergency conditions. The breaker closure and opening control logic diagrams and the 125Vdc voltage calculations were reviewed to ensure adequate voltage would be available for the control circuit components and the breaker spring charging motors. The inspectors performed a visual non-intrusive inspection of observable portions of the safety-related 4160V switchgear to assess the installation configuration, material condition, and potential vulnerability to hazards.

2. 480V Switchgear 235X (2AP19E, Unit 2, Division 1): The inspectors reviewed

selected calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination. The adequacy and appropriateness of design assumptions and calculations were reviewed to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions. The switchgears protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst-case short-circuit conditions. The inspectors reviewed the voltage protection scheme and the adequacy of instrumentation/alarms available. To ensure that breakers were maintained in accordance with industry and vendor recommendations, the inspectors reviewed the preventive maintenance inspection and testing procedures.

Switchgear and breaker failure history was also reviewed. The inspectors reviewed the operating procedures for normal, abnormal, and emergency conditions. The breaker closure and opening control logic diagrams and the 125Vdc voltage calculations were reviewed to ensure adequate voltage would be available for the control circuit components. The inspectors performed a visual non-intrusive inspection of observable portions of the safety-related 480Vac switchgear to assess the installation configuration, material condition, and potential vulnerability to hazards.

3. 4160/480V Stepdown Transformer 235X (Unit 2, Division 1): The inspectors

assessed the sizing, loading, protection, and voltage taps for the 4160V/480V transformer 235X to ensure adequate voltage to the 480V Switchgear 235X.

The inspectors reviewed the ampacity for the source and load side feeder cables.

The inspectors reviewed the protective device settings to ensure that the feeder cables and transformer was protected in accordance with industry standards. A review of the testing requirements, preventive maintenance, failure history, and instrumentation/alarms was performed. The inspectors performed a visual non-intrusive inspection of observable portions of the transformer to assess the installation configuration, material condition, and potential vulnerability to hazards.

4. Battery 2DC07E (Unit 2, Division 1): The inspectors reviewed electrical calculations

including battery sizing, duty cycle, voltage drop calculations, short-circuit fault current calculation, breaker interrupting ratings and electrical coordination, battery float and equalizing voltages. In addition, the voltage drop calculations for safety-related dc loads and dc control power to 4160V and 480V switchgear were evaluated to verify that adequate voltage was available at these loads during a design bases event with loss of offsite power and for a station blackout event. The inspectors verified minimum and maximum battery room temperatures and hydrogen buildup calculations for consistency with design basis requirements. The inspectors reviewed the 125Vdc ground detection system including the ground sensitivity and basis for alarms and action levels. The operating procedures for normal, abnormal, and emergency conditions were reviewed. The inspectors reviewed WO 00620342, Replace Unit 2 Div 1 Battery During L2R10, dated July 29, 2004, to ensure that the installation was consistent with vendor recommendations and design bases requirements, including post-modification testing. A review of the testing requirements, preventive maintenance, failure history, and instrumentation/alarms was performed. The inspectors also reviewed the overall battery capacity, latest modified performance discharge test and service test, and quarterly battery surveillance tests required by technical specifications.

The inspectors performed a visual non-intrusive inspection of observable portions of the batteries to assess the installation configuration, material condition, and potential vulnerability to hazards.

5. Battery Charger 2DC09E (Unit 2, Division 1): The inspectors reviewed electrical

calculations for the 125Vdc battery charger 2DC09E, including sizing calculation, contribution to short-circuit fault current, and breaker sizing. The operating procedures for normal, abnormal, and emergency conditions were reviewed. In addition, the test procedures were reviewed to determine if maintenance and testing activities for the battery chargers were in accordance with UFSAR requirements and vendor recommendations. The inspectors reviewed engineering change EC 333821, Installation of new backup battery chargers for the 125Vdc Division 1 and 2 batteries, Revision 0, to ensure technical adequacy and consistency with design requirements. The inspectors performed a visual non-intrusive inspection of the battery chargers to assess the installation configuration, material condition, and potential vulnerability to hazards.

6. Diesel Generator Cooling Water Pump 0DG01P (Non-unitized, Division 1): The

inspectors reviewed calculations to verify net positive suction head requirements to ensure the pump was capable of performing its safety functions. Hydraulic calculations were reviewed to ensure design requirements for flow and pressure were appropriately translated into acceptance criteria used in pump surveillances and to verify the pump would perform under worst case design conditions. The inspectors reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed.

A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The inspectors reviewed the breaker closure and opening control logic diagrams and the control circuit voltage calculations to ensure adequate voltage would be available for the control circuit components. Design change history and surveillance results were reviewed to assess potential component degradation and impact on design margins. The ultimate heat sink condition was also reviewed (temperature limits and water volume requirements including silt levels) and the associated flow paths to ensure that the water source design basis was maintained.

7. Diesel Generator Cooling Water Strainer 0DG01F (Non-unitized, Division 1): The

inspectors reviewed set-point and set-point basis for strainer delta-P alarm and auto-backwash initiation to ensure unimpeded flow. Corrective actions, surveillance results, and trending data were reviewed to assess potential component degradation and impact on design margins. Operating procedures for manual strainer backwash were also reviewed to ensure unimpeded flow following a loss of power. Particle retention capability was verified to meet design basis.

8. Northwest Room Cooler 2VY01C (Unit 2, Division 1): The inspectors reviewed

thermal performance analysis for room cooler with maximum water temperature and post-accident room temperature calculations to ensure the cooler was capable of performing its required function under worst case design conditions. This review included fouling, heat transfer capacity, heat load, and process medium (air and water). The inspectors reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The inspectors reviewed the breaker closure and opening control logic diagrams and the control circuit voltage calculations to ensure adequate voltage would be available for the control circuit components. Corrective actions and surveillance results were reviewed to verify acceptance criteria were met and performance degradation would be identified.

9. Residual Heat Removal Service Water (RHRSW) Pumps 2E12-C300A & B (Unit 2,

Division 1): The inspectors reviewed piping and instrumentation diagrams, pump line up, and pump capacities for the RHRSW pumps, specifically 2E12-C300A & B.

Design calculations related to pump head, minimum required flow, and net positive suction head were reviewed to ensure the pumps were capable of providing their accident mitigation function during all ambient conditions. The inspectors reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The inspectors reviewed the breaker closure and opening control logic diagrams and the 125Vdc voltage calculations to ensure adequate voltage would be available for the control circuit components. Design change history, corrective actions, surveillance results, and trending data were reviewed to assess potential component degradation and impact on design margins including water-hammer, cavitation, and vibration. The ultimate heat sink condition was also reviewed (temperature limits and water volume requirements including silt levels) and the associated flow paths to ensure that the water source design basis was maintained.

10. RHRSW Strainer 2E12-D300A (Unit 2, Division 1): The inspectors reviewed setpoint and set-point basis for strainer delta-P alarm and auto-backwash initiation to ensure unimpeded flow. Corrective actions, surveillance results, and trending data were reviewed to assess potential component degradation and impact on design margins. Operating procedures for manual strainer backwash were also reviewed to ensure unimpeded flow following a loss of power. Particle retention capability was verified to meet design basis.

11. Residual Heat Removal (RHR) Pump 2E12-C002A (Unit 2, Division 1): The inspectors reviewed piping and instrumentation diagrams, pump line up, pump capacities, and surveillance procedures and data for the RHR pumps. Design calculations related to pump head, minimum required flow, net positive suction head (NPSH) were reviewed to ensure the pumps were capable of providing their accident mitigation function during all ambient conditions. The inspectors reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. For the RHR pump motor, the inspectors assessed the bases for brake horsepower values used as design inputs to the licensees electrical calculations. The inspectors reviewed the breaker closure and opening control logic diagrams and the 125Vdc voltage calculations to ensure adequate voltage would be available for the control circuit components. Design change history was also reviewed to assess potential component degradation and impact on design margins.

12. RHR Suppression Pool Strainer 2E12-D301A (Unit 2, Division 1): The inspectors reviewed the design specifications preventive maintenance tasks, corrective maintenance history, problem history, including records of inspections of the drywell and the suppression pool. The inspectors also reviewed procedures, surveillances, operating history and differential pressure and debris loading calculations to ensure the strainers were capable of performing their required functions under required conditions.

13. High Pressure Core Spray (HPCS) Pump 2E22-C001 (Unit 2, Division 1): The inspectors reviewed the system hydraulic and NPSH analysis, the basis for the pump inservice test acceptance criteria, and a sample of actual inservice test results to verify the capability of the pump to perform its design function under accident conditions. The inspectors reviewed the input to the accident analyses regarding the performance of the HPCS system to verify the system performance was bounding. The inspectors reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The inspectors reviewed the breaker closure and opening control logic diagrams and the 125Vdc voltage calculations to ensure adequate voltage would be available for the control circuit components. In addition, the inspectors performed a walkdown of the HPCS pump and reviewed the pump control logic including the automatic initiation logic and the control of the associated automatic injection valve.

Both normal and emergency operating procedures associated with the pump were also reviewed. Both normal and emergency operating procedures associated with the pump were also reviewed.

14. High Pressure Core Spray Minimum Flow Valve 2E22-F012 (Unit 2, Division 1):

The inspectors reviewed the motor operated valve analysis and testing, the basis for the valve test acceptance criteria, and a sample of actual test results to verify the capability of the valve to perform its design function under accident conditions.

The bases for the setpoints to open and close the valve during pump operation were reviewed. The inspectors reviewed the one line and schematic diagrams.

The inspectors reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The inspectors reviewed the breaker closure and opening control logic diagrams and the control circuit voltage calculations to ensure adequate voltage would be available for the control circuit components. The inspectors performed a walkdown of the valve.

The inspectors reviewed the licensees response to NRC Bulletin 88-04, regarding minimum HPCS flow. The inspectors also reviewed a modification which affected the valve gear ratio and stroke time. In addition, the inspectors reviewed the valve control logic. Both normal and emergency operating procedures associated with the pump were also reviewed.

15. Inboard Main Steam Isolation Valves 1B21-FO22A & D (Unit 1, Division 1 & 2): The inspectors reviewed the preventive maintenance tasks, corrective maintenance history, problem history, and operating history to ensure the valves were capable of performing their required functions under required conditions. The inspectors reviewed the motor-operated valve (MOV) calculations, including required thrust, accumulator sizing and maximum differential pressure, to ensure the valve was capable of functioning under design conditions. Functional test and leak rate test results were reviewed to verify acceptance criteria were met and performance degradation would be identified. The inspectors also reviewed operational procedures, the control logic schematic diagrams, the system description, and flow control diagrams to verify the adequacy of valve control logic design and to ensure that the valve was capable of functioning under design conditions.

16. Reactor Building Closed Cooling Water (RBCCW) Outboard Containment Isolation Valve 2WR040 (Unit 2, Division 1): The inspectors reviewed the licensing basis for this RBCCW containment isolation valve. The review included the motor operated valve analysis and testing, the basis for the valve test acceptance criteria, including leakage limits, and a sample of actual test results to verify the capability of the valve to perform its design function under accident conditions. The inspectors reviewed the one-line and schematic diagrams. The inspectors reviewed associated electrical calculations to confirm that the design basis minimum voltage at the motor terminals would be adequate for starting and running the motor under design basis conditions. The protective device/thermal overload relay settings were reviewed to ensure that adequate margin existed. A review of the cables ampacity was performed and evaluated to determine if adequate margin was available for all motor operating conditions. The inspectors reviewed the breaker closure and opening control logic diagrams and the control circuit voltage calculations to ensure adequate voltage would be available for the control circuit components. The inspectors performed a walkdown of the valve. In addition, the inspectors reviewed the valve control logic. Both normal and emergency operating procedures associated with the pump were also reviewed.

17.

Circulating Water System Discharge Aramco Gate 2CW082 (Unit 2, Nondivisional): The inspectors reviewed the function of the circulating water system discharge gate with regard to its function to terminate a potential internal plant flood. The inspectors review included the operating procedures associated with operating the gate under both normal and abnormal conditions. The inspectors also performed a walkdown of the gate including the actions that would be required if electrical power was not available. The inspectors also reviewed the maintenance procedures and motor operator setting information associated with the gate.

1. Failure to Periodically Test Keylock Switches

Introduction:

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XI, Test Control for failure to ensure that all testing, necessary to demonstrate that components required to implement a safe shutdown for a plant fire would perform satisfactorily in service, was identified and performed. Specifically, the licensee failed to periodically test remote-local keylock control switches on the switchgear for the emergency buses which could be required to implement a safe shutdown for a plant fire in accordance with the licensees Safe Shutdown Analysis described in Appendix H, Section H.4 of the Fire Protection Report.

Description:

On August 27, 2007, during a plant walkdown of selected plant components, the inspectors questioned whether the remote-local keylock control switches on the switchgear for the emergency buses were periodically tested per station procedures.

The response obtained was that no testing of the switchgear remote-local keylock control switches was periodically performed and that cycling of the switches was not routinely performed.

The inspectors determined that procedures LOA-FX-101, Unit 1 Safe Shutdown with a Loss of Offsite Power AND a Fire in the Control Room or AEER [Auxiliary Electrical Equipment Room], and LOA-FX-201, Unit 2 Safe Shutdown with a Loss of Offsite Power AND a Fire in the Control Room or AEER, required the use of the remote-local keylock control switches. In addition, certain support procedures referenced from LOA-FX-101 and LOA-FX-201 required the use of the remote-local keylock control switches.

The inspectors reviewed the licensees post-fire safe shutdown analysis (SSA) described in Appendix H, Section H.4 of the Fire Protection Report (FPR). The SSA credits local control capability (e.g., local pump starts or local switchgear breaker closures for certain switchgear breakers), since fires in the Main Control Room or Division 1 or Division 2 AEER could affect certain equipment (e.g., auxiliary control panels 1(2) PM01J in the Main Control Room) required for safe shutdown of the reactor during a loss of offsite power event.

The existing circuitry for the 23 remote-local keylock control switches associated with the FPR SSA was installed and tested as modifications in October and November 1989 for Unit 1 and in April 1990 for Unit 2. The switches allow local control of the associated safe shutdown equipment, independent of the Main Control Room, in the event of a fire in the Main Control Room, Division 1 AEER, or Division 2 AEER.

Following completion of the modifications, the switches were tested using modification tests. However, the inspectors determined that no subsequent periodic testing of the remote-local keylock control switches had been performed since the performance of the modification tests.

To provide a measure of assurance that the remote-local keylock control switches would operate satisfactorily if required, the licensee initiated testing of the keylock switches that could be tested with the Units at power. The licensee satisfactorily tested 5 of the keylock switches prior to the end of the inspection, and initiated efforts to determine a schedule for testing of the remaining 18 keylock switches, some of the which could not be tested with the Units at power.

Analysis:

The inspectors determined that failure to periodically test these remote-local keylock control switches was a performance deficiency warranting a significance evaluation. The inspectors determined the finding was more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening because the finding was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the licensee did not ensure the operability and functional performance of the remote-local keylock control switches to perform satisfactorily in service.

The inspectors completed a significance determination of this issue using IMC 0609, Appendix F, Fire Protection Significant Determination Process. The inspectors determined that the finding screened as having very low safety significance (Green) during the Fire Protection SDP Phase 1 screening, because the issue had a LOW degradation rating, since the performance and reliability of the affected post-fire safe shutdown equipment was expected to be minimally impacted by the lack of periodic testing of the remote-local keylock control switches due to successful completion of a sample of the keylock switches (5 of 23), and compensatory measures instituted to provide direction on how to manual close a breaker if the local control device failed to close the breaker. The inspectors determined that there was no cross-cutting aspect to this finding.

Enforcement:

Facility Operating License condition 2.C.(25) for Unit 1 and Facility Operating License condition 2.C.(15) for Unit 2, required, in part, that the licensee implement and maintain all provisions of the approved Fire Protection Program as described in the Final Safety Analysis Report for the facility, and as approved in NUREG-0519, Safety Evaluation Report (SER) related to the operation of LaSalle County Station, Units 1 and 2, dated March 1981. Section 17, Quality Assurance, of the SER, stated, in part, that the quality assurance (QA) program for the operations phase of the facility was described in Section 17 of the Final Safety Analysis Report, and that the quality assurance program for the operations phase complied with 10 CFR Part 50, Appendix B.

Chapter 17, Quality Assurance, of the Updated Final Safety Analysis Report (UFSAR),stated, in part, that the Exelon Generation Company (EGC) Quality Assurance Topical Report is the basis for the QA Program at LaSalle County Station. Section 2.4 of the EGC Quality Assurance Topical Report stated, in part, that routine testing of fire protection systems assures reliability and that the QA program for the fire protection structures, systems, and components ensures that testing meets the applicable QA guidelines described in the applicable Branch Technical Position (BTP) 9.5-1. Section C.4 of BTP

.5 -1

stated, in part, that the licensees QA program for the fire protection program be part of the overall plant QA program and that it satisfies the criterion for Test Control.

Title 10 CFR Part 50, Appendix B, Criterion XI, Test Control requires, in part, that a test program shall be established to assure that all testing required to demonstrate that structures, systems, and components will perform satisfactorily in service be identified and performed.

Contrary to 10 CFR Part 50, Appendix B, Criteria XI, Test Control, from November 1989 for Unit 1, and from April 1990 for Unit 2, following modification installation of the revised circuitry for the remote-local keylock control switches, to August 28, 2007, the licensees test program failed to ensure that all testing, necessary to demonstrate that certain Unit 1 and 2 components required to implement a safe shutdown for a plant fire would perform satisfactorily in service, was identified and performed. Specifically, the licensee failed to periodically test remote-local keylock control switches on the switchgear for the emergency buses required to implement a safe shutdown for a plant fire in accordance with the licensees Safe Shutdown

Analysis.

This finding applies to both units. However, because this violation was of very low safety significance and because the issue was entered into the licensees corrective action program (IR 00666945), this violation is being treated as a NCV consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000373/2007009-01, NCV 05000374/2007009-01)

2. Failure to Translate Backwash Valve Settings into Procedures

Introduction:

The inspectors identified an NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, having very low safety significance (Green), in that, the design bases for the required manual setting for the Diesel Generator Cooling Water (DGCW) backwash valves were not correctly translated into procedures and instructions. Specifically, the manual backwash valve positions derived from flow test surveillance procedures based on hydraulic calculation models were not correctly translated into operations procedures for manual operation of the DGCW strainer backwash valves.

Description:

On August 28, 2007, the inspectors identified inconsistencies in the manual backwash valve positions for the DGCW strainers listed in operating procedure LOP-DG-04, Diesel Generator Special Operations, and quarterly operations surveillance procedures LOS-DG-Q1, 0 Diesel Generator Auxiliaries Test, LOS-DG-Q2, 1A(2A) Diesel Generator Auxiliaries Test, and LOS-DG-Q3, 1B(2B)

Diesel Generator Auxiliaries Test. The manual backwash valve positions were to be derived from the flow test surveillance procedures LOS-DG-SR5, 0 DG Cooling Water System Flow Test, LOS-DG-SR6, Division 2 Cooling Water System Test, and LOS-DG-SR7, Division 3 Cooling Water System Test. If the backwash flow was found outside the acceptable flow band, a limit switch adjustment was made to the motor-operated backwash valve. The limit switch set-point should be converted into the number of hand turns open on the strainer backwash valve, and procedures LOP-DG 04, and LOS-DG-Q1, LOS-DG-Q2, and LOS-DG-Q3 updated as necessary to ensure that the correct valve position value was used when manually backwashing the strainers.

However, there was no process to ensure that, following an adjustment of a limit switch to a backwash valve, the required changes to procedures LOP-DG-04, and LOS-DG-Q1, LOS-DG-Q2, and LOS-DG-Q3 were actually performed.

The licensee initiated IR 00665626 and performed a prompt operability assessment of the discrepancies. Based on the test case evaluation using a hydraulic model, with an increase in backwash flow by a factor of two, the impact on Diesel Generator (DG) coolers was approximately a 20 gpm reduction in flow, and the impact on the Emergency Core Cooling System (ECCS) cubicle room coolers (i.e., VY coolers) was approximately a 5 gpm reduction. Based on operability limits specified in engineering calculation EC 360691, Revision 0, CSCS Cooling Water Flow Margins for Operability of the ECCS Cubicle Room Coolers and DG Coolers, there was at least a 400 gpm margin for the 1A (2A) DG coolers, and at least a 50 gpm margin for the 1(2)VY03A coolers. Therefore, the licensee concluded that adequate margin existed to ensure that the DG and VY system heat exchangers were capable of performing their design function even with the increased strainer backwash flows produced by manual backwash.

The licensee updated procedure LOP-DG-04, Diesel Generator Special Operations, on August 29, 2007, to Revision 43, to reflect the correct manual settings for the DGCW strainer backwash valves. The licensee planned to update the quarterly operations surveillance procedures prior to the next scheduled surveillance which uses these procedures.

Analysis:

The inspectors determined that failure to control the manual setting for the DGCW backwash valves to ensure their design function during accident conditions was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening. This issue was more than minor because the finding was associated with the procedure quality attribute of the Mitigating System cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of the DGCW system to respond to initiating events to prevent undesirable consequences. Specifically, the DGCW backwash valves could be manually opened more than required during a loss of power event, and thus divert some cooling flow from post accident required equipment.

The inspectors evaluated the finding using IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, Phase 1 screening.

The inspectors answered No to all the screening questions because re-evaluation confirmed the operability of the system. Therefore, the finding screened as having very low safety significance (Green). The inspectors also determined that this finding was cross-cutting in the area of Human Performance, resources in that the licensee failed to have complete, accurate, and up-to-date procedures (H.2(c)). Specifically, several operating and quarterly surveillance procedures were not updated when adjustments were made to the DGCW backwash valves limit switches during performance of the system flow tests.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control requires, in part, that measures be established to assure that applicable regulatory requirements and the design basis are correctly translated into procedures and instructions.

Contrary to this requirement, prior to August 28, 2007, the licensee had not established effective measures to ensure that the design basis for the required manual setting for the DGCW backwash valves was correctly translated into procedures and instructions.

Specifically, the manual backwash valve positions derived from flow test surveillance procedures based on hydraulic calculation models were not translated into operations procedures for manual operation of the DGCW strainer backwash valves. This finding applies to both units. However, because this violation was of very low safety significance and because the issue was entered into the licensees corrective action program (IR 00665626), this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000373/2007009-02, NCV 05000374/2007009-02)

3. Lack of Station Blackout Analysis for Reactor Core Isolation Cooling (RCIC)

Introduction:

The inspectors identified an NCV of 10 CFR 50.63, Loss of All Alternating Current Power having very low safety significance (Green). Specifically, the licensee did not have an appropriate analysis to determine the capability of coping with a station blackout in that it had no analysis that verified the proper operation of the RCIC turbine at the elevated suppression pool temperatures encountered during a station blackout event.

Description:

While reviewing the engineering evaluation for the effect of power uprate on the Station Blackout Coping Assessment (NDIT No. LAS-ENDIT-1255), the inspectors observed that the peak suppression pool temperature predicted during a station blackout event was 196°F. The inspectors noted that emergency operating procedure LGA-001, RPV Control, Revision 7 had the following caution statement regarding RCIC CAUTION:

Exceeding 180°F lube oil temperature may cause system damage. Since the RCIC lube oil temperature would be higher than the suppression pool temperature (as it is cooled by the suppression pool), the inspectors were concerned that the RCIC turbine would not be able to perform its required function during a station blackout at these heightened suppression pool temperatures, such that the RCIC turbine could fail during a station blackout leaving the plant without its primary means of maintaining reactor coolant inventory.

Based upon the inspectors concerns, the licensee further researched the issue and discovered that the licensee did not have an established basis for the operation of the RCIC turbine above 180°F. The issue was entered into the licensees corrective action program as Issue Report (IR) 00673099. The licensee performed a prompt operability assessment and also addressed the availability and reliability of the RCIC turbine during station blackout conditions. This condition was also applicable to an Appendix R event.

However, since the Appendix R event duration was shorter than the assumed duration for the station blackout event, the suppression pool temperature evaluation for station blackout was found to be more limiting than that of the Appendix R event.

The licensee contacted the original equipment manufacturer for the LaSalle RCIC turbine (now Dresser-Rand). Dresser-Rand provided a letter dated September 21, 2007 that gave temperature limits for short time operation (approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />) for the RCIC turbine supplied to the station. The licensee used the letter from Dresser-Rand regarding the temperature limits for the RCIC turbine, and performed a preliminary analysis that concluded that the RCIC turbine would operate properly for the heightened suppression pool temperatures achieved during station blackout conditions. The licensee planned to perform a more detailed analysis to calculate the maximum suppression pool temperature that would limit the oil temperature to the bearing temperature limit.

While the licensee was ultimately able to determine the availability and reliability of the RCIC turbine during the elevated suppression pool temperatures encountered during a station blackout, the licensees existing design basis had not been adequate. Prior to the inspectors questioning the operation of the RCIC turbine above 180°F lube oil temperature, the licensee did not have an analysis that supported the proper operation of the RCIC turbine at elevated suppression pool temperatures during a station blackout event.

Analysis:

The team determined that the failure to have an appropriate analysis to determine the capability of coping with a station blackout was a performance deficiency warranting a significance evaluation in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening. The cause was reasonably within the licensees ability to foresee and correct and it could have been prevented because the licensee had an opportunity to identify the issue in 2000 when reviewing calculations for the power uprate amendment.

The issue was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone. Specifically, the licensee did not have an analysis that demonstrated the availability and reliability of the RCIC turbine at the elevated suppression pool temperatures encountered during a station blackout event. The inspectors evaluated the finding using IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, Phase 1 screening. The inspectors answered No to all the screening questions in the Mitigating System Cornerstone Column because the licensee obtained additional data from the RCIC turbine manufacturer and performed a functionality analysis which demonstrated the pump turbine could operate at heightened suppression pool temperatures. The finding screened as having very low safety significance (Green). The inspectors determined that there was no cross-cutting aspect to this finding.

Enforcement:

Title 10 CFR 50.63, Loss of All Alternating Current Power, Paragraph (a)(2)requires, in part, that licensees provide sufficient capacity and capability to ensure the core is cooled in the event of a station blackout for the specified duration. It further requires that the capability for coping with a station blackout of specified duration shall be determined by an appropriate coping analysis. Finally, it requires that licensees have the baseline assumptions, analyses, and related information used in their coping evaluations available for NRC review.

Contrary to the above, as of September 19, 2007, the licensee failed to have an appropriate coping analysis which determined the capability of the RCIC turbine to operate during a station blackout event. Specifically, the licensee failed to have an analysis which verified that the appropriate operation of the RCIC turbine at the elevated suppression pool temperatures encountered during a station blackout. However, because this violation was of very low safety significance and because the issue was entered into the licensees corrective action program (IR 00673099), this violation is being treated as a NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000373/2007009-03; 05000374/2007009-03).

4. Lake Level Instrumentation Removed from Service without 10 CFR 50.59 Evaluation

Introduction:

The inspectors identified an NCV of 10 CFR 50.59, Changes, Tests, and Experiments, which had very low safety significance. Specifically, the licensee failed to complete a 50.59 evaluation for removing main control room lake level instrumentation from service. Although the UFSAR stated that the lake level was continuously monitored in the main control room, the inspectors determined that the instrument had been abandoned, and that an evaluation had not been completed as required by 10 CFR 50.59.

Description:

The inspectors reviewed UFSAR section 2.4.8.1, which stated in part, Lake level is continuously monitored in the main control room of the power plant. The inspectors questioned the status of the main control room lake level instrumentation and determined that it had been problematic for several years and had not functioned since 2005. The inspectors questioned how the operators would detect a failure of the dike, resulting in a loss of lake level, with sufficient time to shut-off non-safety related pumps and preserve the required ultimate heat sink inventory.

In response to these questions, the licensee provided calculation WR-LS-UH-2, Revision 0, which concluded that the failure of a large dike section could result in the ultimate heat sink level being reached in approximately 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The licensee also stated that the lake level was locally verified by operator rounds once per shift (8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />). In addition, the licensee stated that it was likely that they would be informed of a major dike failure by other means.

The inspectors determined that these were not adequate measures to ensure a timely response to a potential loss of the ultimate heat sink.

The licensee stated that in September 2003, a Reasonable Assurance of Safety evaluation had been performed for continued operation with the main control room instrumentation not functional. The licensees review of plant maintenance records indicated that the last time the lake level instrument was functional was in June 2005, and that the instrument was removed from the plant maintenance schedule in December 2005. In April 2006, the Plant Health Committee recommended abandoning the instrument and initiated engineering change EC 360580. At the time of the inspection, EC 360580 was in progress, and no 10 CFR 50.59 evaluation had yet been completed.

During the inspection, the licensee initiated IR 00674071 to address this condition.

The recommended actions included compensatory measures to verify lake level every 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />, a work request to repair the instrument, and actions to prevent a similar condition in the future. The compensatory measures to verify lake level every 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> were implemented on September 24, 2007.

Analysis:

The inspectors determined that removing the lake level instrument from service without a 10 CFR 50.59 evaluation was a performance deficiency. The inspectors concluded that the violation was reasonably within the licensees ability to foresee and correct based on the procedures in effect at the time.

Because violations of 10 CFR 50.59 are considered to be violations that potentially impede or impact the regulatory process, they are dispositioned under the traditional enforcement process instead of the SDP. However, if possible, the underlying technical issue is evaluated under the SDP to determine the severity of the violation. The finding was determined to be more than minor because the inspectors could not reasonably determine that this change would not have ultimately required prior approval from the NRC. The inspectors completed a significance determination of the underlying technical issue using IMC 0609, Appendix A. The inspectors determined the finding impacted the Mitigating System cornerstone and using the Phase 1 screening worksheet, concluded the finding was of very low safety significance (green) because it did not result in a loss of functionality of any mitigating systems.

The inspectors concluded that this finding was cross-cutting in the area of Human Performance, Resources, because the licensee failed to effectively address a long standing equipment issue (H.2(a)). Specifically, the lake level instrumentation was non-functional for an extended period of time and this degraded condition was accepted by the licensee.

Enforcement:

Title 10 CFR 50.59 stated, in part, that a licensee shall obtain a license amendment pursuant to Section 50.90 prior to implementing a proposed change, test, or experiment if the change, test, or experiment would create a possibility for a malfunction of a component important to safety with a different result than any previously evaluated in the final safety analysis report (as updated). Contrary to the above, in December 2005, the licensee abandoned instrumentation described in the safety analysis report without a 10 CFR 50.59 evaluation. The failure to maintain this instrument could have affected licensees ability to ensure a timely response to a potential loss of the ultimate heat sink. In accordance with the Enforcement Policy, the violation was classified as a Severity Level IV violation because the underlying technical issue was of very low risk significance. Because this non-willful violation was non-repetitive and was captured in the licensees corrective action program as IR 00674071, this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000373/2007009-04; 05000374/2007009-04).

5. Exclusion of Potential Internal Flood Sources Under 10 CFR 50.59

Introduction:

The inspectors identified an Unresolved Item (URI) concerning changes to the licensees flooding analyses.

Description:

The original licensing basis assumed all gravity fed flood sources were installed within watertight barriers. In 1995, the licensee determined that several non-safety related, non-seismically designed piping sections in the turbine building had the potential of allowing a gravity fed internal flood from the lake. This flood could potentially communicate with vital areas in the auxiliary building and reactor building, affecting multiple trains of safety related equipment required for safe shutdown. The licensee performed evaluations of these piping sections and determined that their failure was not credible.

Based on these evaluations, the licensee revised the UFSAR without prior NRC approval under 10 CFR 50.59.

The inspectors reviewed documentation associated with the crack exclusion of sections of moderate energy piping in the turbine building. An Operability Assessment Process Form (PIF 373-201-95-00260), dated March 21, 1995, addressed a non-conformance with UFSAR Section 3.4.1.4.a, which stated that gravity flooding due to pipe rupture in the turbine building would be confined to watertight enclosures. Walkdowns had identified several sections of non-safety related, non-seismically designed piping that were not within watertight enclosures. A gravity fed flood from the lake could potentially result in flooding of the turbine building up to the maximum lake level of 701 feet. This flood level could potentially communicate with vital areas in the auxiliary building and reactor building, affecting multiple trains of safety related equipment required for safe shutdown.

The licensee performed an evaluation to justify continued operation of the units. This evaluation determined that pipe cracks need not be postulated for any piping for which the normal operating pressure is less than 10 psig, based on Appendix J of the UFSAR (Appendix J defined moderate energy piping as being greater than 10 psig). The evaluation also determined that pipe cracks need not be postulated for any moderate energy piping that meet the pipe stress criteria of Standard Review Plan (SRP) 3.6.2.

An associated 10 CFR 50.59 evaluation, dated March 21, 1995, determined that no unreviewed safety question (USQ) existed.

A UFSAR change request (LU1999-032), dated May 26, 1999 was issued to revise the UFSAR to include both the 10 psig and SRP 3.6.2 crack exclusion criteria.

This change also included a 10 CRF 50.59 evaluation (L99-126), dated May 20, 1999, which concluded that no USQ existed. The inspectors also noted that both these 10 CFR 50.59 evaluations stated that if a pipe crack was to occur, sufficient time would be available to isolate the flood source. In response to the inspectors questions, the licensee stated that the capability to isolate these floods had not been verified.

The inspectors questioned if these 10 CFR 50.59 evaluations had been adequate to make these licensing basis changes without prior NRC approval. The original license was based on a determination that potential gravity flooding due to failure of non-safety related, non-seismically designed piping in the turbine building would be confined to watertight enclosures, and that safety related equipment was located above the maximum water level.

The inspectors were concerned that the identification of non-safety related, non-seismically designed piping outside of the watertight enclosures created the possibility for an accident or malfunction of a different type than any evaluated previously in the safety analysis report. Flooding from a potential rupture of this piping could affect safety-related equipment that is located below normal lake level.

In response to NRC concerns, the licensee documented this issue in IR 676923, CDBINRC Identified Flooding Methodology as URI. The licensee maintained that piping with an internal pressure less that 10 psi did not have to be evaluated, since it was not evaluated in the initial license application. This item is considered unresolved pending further NRC evaluation of the licensees licensing basis. (URI 05000373/2007009-05; 05000374/2007009-05).

.4 Operating Experience

a. Inspection Scope

The inspectors reviewed six operating experience issues (6 samples) to ensure that NRC generic concerns had been adequately evaluated and addressed by the licensee. The operating experience issues listed below were reviewed as part of this inspection:

• Bulletin 1988-04, Potential Safety-Related Pump Loss;

• GL 2006-02, Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power;

• IN 1996-48, Motor-Operated Valve Performance Issues;

• IN 2005-30, Safe Shutdown Potentially Challenged by Unanalyzed Internal Flooding Events and Inadequate Design;

• IN 2006-26: Failure of Magnesium Rotors in Motor Operated Valve Actuators; and

• IN 2006-31: Inadequate Fault Interrupting Rating of Breakers.

b. Findings

No findings of significance were identified.

.5 Modifications

a. Inspection Scope

The inspectors reviewed five permanent plant modifications related to selected risk significant components to verify that the design bases, licensing bases, and performance capability of the components had not been degraded through modifications. The modifications listed below were reviewed as part of this inspection effort:

• EC 333821 Install Backup Unit 2 Division 1 125VDC Battery Charger;

• EC 341950 Elimination of RHRSW Keepfill;

• EC 347065 RHRSW Orifice 1E12-D304B Resizing;

• EC 348851 Change Overall Gear Ratio for Valve 1E22-F012; and

• EC 359114 Replace Thermocouple with RTD on Temperature Elements 2TE-CW010 and 2TE-CW011.

b. Findings

No findings of significance were identified.

.6 Risk Significant Operator Actions

a. Inspection Scope

The inspectors performed a margin assessment and detailed review of five risk significant, time critical operator actions (5 samples). These actions were selected from the licensees PRA rankings of human action importance based on risk achievement worth values.

Where possible, margins were determined by the review of the assumed design basis and UFSAR response times and performance times documented by job performance measures results. For the selected operator actions, the inspectors performed a detailed review and walk through of associated procedures, including observing the performance of some actions in the stations simulator and in the plant for other actions, with an appropriate plant operator to assess operator knowledge level, adequacy of procedures, and availability of special equipment where required.

The following operator actions were reviewed:

• Operator Fails to Open 2-inch Vent to Maintain Drywell Pressure;

• Operator Fails to Shed 125V DC Non-Essential Loads;

• Operator Fails to Manually Initiate Suppression Pool Cooling and Manipulate Valves;

• Operator Fails to Bypass Emergency Diesel Generator 0 Output Breaker Interlocks; and

• Operator Fails to Throttle Operating Residual Heat Removal Service Water Pump Given Failure of Paired Pump.

b. Findings

No findings of significance were identified.

4OA6 Meeting(s)

Exit Meeting The inspectors presented the inspection results to Mr. J. Bashor and other members of licensee management at the conclusion of the inspection on September 28, 2007. The inspectors asked the licensee whether any of the material examined during the inspection should be considered proprietary. No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

D. Enright, Site Vice President

D. Rhoades, Plant Manager

J. Bashor, Site Engineering Director

R. Ebright, Training Director

H. Vinyard, Acting Operations Director

B. Ginter, Programs Engineering Manager

F. Gogliotti, Plant Engineering Manager

J. Rappeport, Nuclear Oversight Manager

J. Rommel, Design Engineering Manager

T. Simpkin, Regulatory Assurance Manager

V. Shah, Electrical Design Engineering Supervisor

P. Holland, Regulatory Assurance Engineer

Nuclear Regulatory Commission

A. M. Stone, Chief, Engineering Branch 2

D. Kimble, Senior Resident Inspector

LIST OF ITEMS

OPENED, DISCUSSED, AND CLOSED

Opened and Closed

05000373/2007009-01 NCV Failure to Periodically Test Keylock Switches (Section

05000374/2007009-01 1R21.3.b.1)

05000373/2007009-02 NCV Failure to Translate Backwash Valve Settings into

05000374/2007009-02 Procedures (Section 1R21.3.b.2)

05000373/2007009-03 NCV Lack of Station Blackout Analysis for RCIC (Section

05000374/2007009-03 1R21.3.b.3)

05000373/2007009-04 NCV Lake Level Instrumentation Removed from Service

05000374/2007009-04 without 10 CFR 50.59 Evaluation (Section 1R21.3.b.4)

Opened

05000373/2007009-05 URI Exclusion of Potential Internal Flood Sources Under

05000374/2007009-05 10 CFR 50.59

Discussed

None Attachment

Attachment