IR 05000302/2010007

IR 05000302-10-007; 5/24/2010 - 9/09/2010; Crystal River Nuclear Plant; Component Design Bases Inspection

ML102730597
Person / Time
Site:	Crystal River
Issue date:	09/28/2010
From:	Binoy Desai NRC/RGN-II/DRS/EB1
To:	Franke J Progress Energy Florida
References
IR-10-007
Download: ML102730597 (32)

Text

UNITED STATES tember 28, 2010

SUBJECT:

CRYSTAL RIVER NUCLEAR PLANT - NRC COMPONENT DESIGN BASES INSPECTION - INSPECTION REPORT 05000302/2010007

Dear Mr. Franke:

On September 9, 2010, U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Crystal River Nuclear Plant. The enclosed inspection report documents the inspection results, which were discussed on September 9, 2010, with Mr. S. Cahill 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 team reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents three NRC-identified findings of very low safety significance which were determined to be violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy because of their very low safety significance and because they were entered into your corrective action program. If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Crystal River Nuclear Plant. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the Crystal River Nuclear Plant. The information you provide will be considered in accordance with the Inspection Manual Chapter 0305.

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 (PARS) component of

FPC 2 the NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Binoy B. Desai, Chief Engineering Branch 1 Division of Reactor Safety Docket Nos.: 50-302 License Nos.: DPR-72

Enclosure:

Inspection Report 05000302/2010007, w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-302 License Nos.: DPR-72 Report Nos.: 05000302/2010007 Licensee: Florida Power Corporation Facility: Crystal River Nuclear Plant Location: Crystal River, FL Dates: May 24 - September 9, 2010 Inspectors: D. Jones, Senior Reactor Inspector (Lead)

S. Even, Reactor Inspector R. Patterson, Reactor Inspector W. Deschaine, Project Engineer J. Montgomery, Reactor Inspector (Trainee)

J. Dymek, Reactor Inspector (Trainee)

O. Mazzoni, Contractor M. Shlyamberg, Contractor Approved by: Binoy B. Desai, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000302/2010007; 5/24/2010 - 9/09/2010; Crystal River Nuclear Plant; Component

Design Bases Inspection.

This inspection was conducted by a team of six NRC inspectors from the Region II office, and two NRC contract inspectors. Three findings of very low significance (Green)were identified during this inspection and were classified as non-cited violations (NCV).

The significance of most findings is indicated by their color (Green, White, Yellow, Red)using 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, (ROP) Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

Green.

The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion XI, Test Control for preconditioning of a safety-related air operated valve prior to surveillance testing. The licensee entered this deficiency into their corrective action program for resolution.

The licensees preconditioning of air operated valves prior to performing as-found testing is a performance deficiency. This finding is more than minor because if left uncorrected the performance deficiency has the potential to lead to a more significant safety concern in that safety-related valve performance deficiencies could be masked. The finding is of very low safety significance (Green) using the SDP because it did not represent a loss of system or safety function. The finding involved the cross-cutting aspect of complete and accurate procedures under the Resources component of the Human Performance area H.2(c). [Section 1R21.2.2]

Green.

The team identified a non-cited violation of 10 CFR 50.63, Loss of all alternating current power, for failure to ensure Regulatory Guide 1.155, Station Blackout commitments were implemented in calculations for restoring off-site power. The licensee entered this deficiency into their corrective action program for resolution.

The licensees failure to maintain calculations to assure adequate voltage for the remote closing of switchyard breakers during a station blackout event is a performance deficiency. The team determined that the finding is more than minor because it adversely affected the design control attribute of the mitigating reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance (Green)using the SDP because it did not represent a loss of system or safety function. A cross-cutting aspect was not identified because the finding does not represent current performance. [Section 1R21.2.13]

Green.

The team identified a non-cited violation of 10 CFR 50.65(a)(1) for the licensees failure to monitor service water and decay heat cooling expansion tank level indicator check valves. In response to this concern, the licensee closed the isolation valves as an interim action, performed an in situ check valve test with satisfactory results, and entered the deficiency into their corrective action program for resolution.

The licensees failure to perform appropriate maintenance on the check valves was a performance deficiency. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is of very low safety significance (Green) using the SDP because it did not represent a loss of system or safety function. A cross-cutting aspect was not identified because the finding does not represent current performance. [Section 1R21.2.17]

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R21 Component Design Bases Inspection

.1 Inspection Sample Selection Process

The team selected risk significant components and operator actions for review using information contained in the licensees Probabilistic Risk Assessment (PRA). In general, this included components and operator actions that had a risk achievement worth factor greater than 1.3 or Birnbaum value greater than 1 X10-6. The sample included seventeen components, four operator actions, and three operating experience items.

The team performed a margin assessment and detailed review of the selected risk-significant components to verify that the design bases had been correctly implemented and maintained. This design margin assessment considered original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for detailed review. These reliability issues included items related to failed performance test results, significant corrective action, repeated maintenance, maintenance rule (a)1 status, Regulatory Issue Summary (RIS)05-020 (formerly GL 91-18) conditions, NRC resident inspector input of problem equipment, System Health Reports, industry operating experience and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, operating experience, and the available defense-in-depth margins. An overall summary of the reviews performed and the specific inspection findings identified is included in the following sections of the report.

.2.1 Diesel Driven Emergency Feedwater Pump (EFP-3)

a. Inspection Scope

The team reviewed the updated final safety analysis report (UFSAR), technical specifications (TS), applicable plant calculations, and drawings to identify the design bases requirements of EFP-3, diesel support fuel system including the fuel oil tank (DFT-4) and the diesel support cooling system including jacket water expansion tank (DJT-7).

The team also reviewed operating procedures to verify correct implementation of design bases. The team examined system health reports, records of surveillance testing and maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team investigated EFP-3 building internal and external flooding potential. The team reviewed the plants evaluation of RIS 2006-23, Post-Tornado Operability of Ventilating And Air-Conditioning Systems Housed In Emergency Diesel Generator Rooms to determine if it was reviewed for EFP-3 building applicability. The team reviewed the EFP-3 hydraulic calculations to verify that the pump degradation assumed in the in-service testing (IST) surveillances would not prevent EFP-3 from performing its safety-related function and that design flow and pressure requirements were correctly translated into IST surveillances acceptance criteria. The team also reviewed the EFP-3 hydraulic calculations to verify that runout flow was acceptable. The team reviewed the EFP-3 pump net positive suction head (NPSH) design and vortexing calculations to verify the pumps would have adequate suction head and not ingest air under accident conditions. The team also reviewed DFT-4 sizing calculations to verify the tank was correctly sized to provide its required TS volume including instrument error and vortexing considerations. Additionally, the team reviewed calculations for battery capacity to verify that components would have sufficient direct current (DC) power during accident conditions. The team also reviewed setpoint bases and calibration data for air tank and fuel level setpoints to verify that the components could perform their design basis function. The team also interviewed plant personnel and performed walkdowns of EFP-3 and associated support systems to assess visible material condition and to verify the installation was consistent with design documentation.

b. Findings

No findings of significance were identified.

.2.2 Letdown Isolation Boundary Valve (MUV-49)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of MUV-49. The team performed interviews with plant personnel and examined system health reports, records of surveillance testing, maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team also reviewed preventative maintenance records of eight additional air operated valves (AOV) to determine the extent of condition in regards to preconditioning before surveillance testing.

b. Findings

Introduction:

The team identified a Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XI, Test Control, for preconditioning of a safety-related air operated valve (AOV) prior to surveillance testing.

Description:

Letdown valve (MUV-49) is an air operated containment isolation valve. The valves safety function is to close, thus isolating reactor coolant system letdown during various accident conditions. Valve MUV-49 is tested on a 24 month frequency.

On December 6, 2009, the licensee performed surveillance test, SP-435 Valve Testing During Cold Shutdown which performed stroke time testing of MUV-49. On the day prior to the surveillance test, the licensee performed maintenance procedures, MP-147D Air Actuator Maintenance and MP-543 Air Operated Valve Diagnostic Testing which resulted in rebuilding, retorqueing, repacking and manual stroking of the valve.

The inspectors determined that rebuilding the actuator and cycling the valve as part of the preventative maintenance (PM) masked the as-found condition of the valve during the performance of the surveillance test. NRC Inspection Manual Part 9900 Technical Guidance, Maintenance - Preconditioning of Structures, Systems, and Components Before Determining Operability, states, in part that the NRC expects surveillance and testing processes of structures, systems and components (SSCs) to be evaluated in an as-found condition. It also defines preconditioning of SSCs as the alteration, variation, manipulation or adjustment of the physical condition of an SSC before technical specification (TS) surveillance or American Society Mechanical Engineers (ASME) code testing. It also states, in part, that influencing test outcome by performing valve stroking, PM, pump venting or draining, or manipulating SSCs does not meet the intent of the as-found testing expectations. The inspectors conducted an extent of condition review by evaluating the testing history for valves MSV-10, MSV-26, MSV-412, MUV-253, SWV-47, SWV-49 and SWV-110, which account for 25 percent of the AOVs that are tested on a cold shutdown frequency. The inspectors found that 75 percent of the sampled population was preconditioned prior to TS required testing. The licensee initiated NCR 404042 to address this issue.

Analysis:

The inspectors determined that the preconditioning of valve MUV-49 and associated AOVs prior to performing surveillance testing is a performance deficiency.

This finding is more than minor because if left uncorrected the finding has the potential to lead to a more significant safety concern in that safety-related valve performance deficiencies could be masked. Masked performance deficiencies in AOVs could adversely impact the Mitigating Systems cornerstone objective of ensuring the reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The team determined the finding is of very low safety significance (Green) using the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter 0609 because it did not represent a loss of system or safety function. The finding involved the cross-cutting aspect of complete and accurate procedures under the Resources component of the Human Performance area.

Specifically, the licensee failed to provide their employees with adequate procedures, administrative controls and processes to preclude the act of preconditioning prior to conducting technical specification required surveillance testing. H.2(c)

Enforcement:

10 CFR Part 50 Appendix B, Criterion XI, Test Control states, 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 is identified and performed in accordance with written test procedures which incorporate the requirements and acceptable limits contained in applicable design documents. Contrary to the above, the licensee failed to establish a surveillance testing program that incorporated appropriate requirements to assure that as-found conditions were documented prior to the performance of maintenance activities. Specifically, on December, 2009, the licensee performed maintenance and diagnostic testing on valve MUV-49 prior to recording the as-found stroke time. Because this finding is of very low safety significance and it was entered in the licensees corrective program as NCR 404042, this violation is treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 0500302/2010007-01, Preconditioning of Safety-Related Air Operated Valves.

.2.3 4160 V Engineered Safeguard Diesel Bus 3B

a. Inspection Scope

The team reviewed the one-line diagram to assess the main electrical features and connections; the loading calculations to ensure that the rated ampacity of bus 3B North and bus 3B South was not exceeded; and the protective relaying for the bus to ensure that protection was in accordance with requirements. The team reviewed the short circuit calculation to ascertain that duties were within ratings. Additionally, the team reviewed protective relaying, relay settings, and the control and instrumentation for the main bus breaker to ascertain compliance with requirements. Switchgear purchase specifications were reviewed to verify ratings, and the maintenance and test procedures were reviewed to verify proper supervision of the main breaker. Additionally, the team performed a plant walk down of bus 3B switchgear to assess physical and environmental conditions.

b. Findings

No findings of significance were identified.

.2.4 Decay Closed Loop Cooling Heat Exchanger (DCHE 1A)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of DCHE 1A. Maintenance history, as demonstrated by system health reports, preventive and corrective maintenance, and corrective action documents were reviewed to verify that degradation was appropriately monitored and addressed. The team conducted interviews and walkdowns with the system engineer to obtain additional information regarding the licensees response to Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety-Related Equipment and verified that the stations implementation and analysis was appropriate.

b. Findings

No findings of significance were identified.

.2.5 DHR Drop Line and Injection Lines (DHV-3 and DHV-4)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of valves DHV-3 and DHV-4 and associated piping. The team also reviewed operating procedures to verify correct implementation of design bases. The team examined system health reports, records of surveillance testing, maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team also performed a walkdown of DHV-3 and DHV-4 to assess visible material condition and to verify that the installation was consistent with design documentation. The team also performed interviews with plant personnel to discuss the history of valve testing, maintenance activities, and completed corrective actions. Additionally, the team reviewed motor operated valve (MOV) terminal voltage at degraded voltage conditions; reviewed instrumentation and control logic diagrams; and reviewed motor torque calculations to verify that the motor operators would function during worst case accident conditions.

b. Findings

No findings of significance were identified

.2.6 Make-Up Valve (DHV-11 and 12)

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of DHV-11 and DHV-12. The team examined system health reports, records of surveillance testing, maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team also performed several interviews with plant personnel to discuss the history of valve testing, maintenance, and details of the corrective actions that had been completed. The team conducted a visual inspection of DHV-11 and DHV-12 to verify that degraded conditions were being addressed. In addition, the team verified that the power demand requirements for the valves were captured in electrical load and degraded voltage calculations. The team also verified that the highest differential pressure was used to determine the maximum valve opening and/or closing requirements to ensure that the valve would perform its intended safety-related design basis function. The team reviewed testing procedures and diagnostic valve test results to verify the MOV was tested in a manner that would detect a malfunctioning valve.

Additionally, the team reviewed MOV terminal voltage at degraded voltage conditions; reviewed instrumentation and control logic diagrams; and reviewed motor torque calculations to verify that the motor operators would function during worst case accident conditions.

b. Findings

No findings of significance were identified.

.2.7 Sump/Containment Isolation Valves (DHV-42 and DHV-43)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of the DHV-42 and DHV-43. The team also reviewed operating procedures to verify correct implementation of design bases. The team examined system health reports, records of surveillance testing, maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team also performed a walkdown on DHV-42 and DHV-43 to assess visible material condition and to verify that the installation was consistent with design documentation. The team also performed interviews with plant personnel to discuss the history of the valve testing, maintenance, and details of completed corrective actions. Additionally, the team reviewed MOV terminal voltage at degraded voltage conditions; reviewed instrumentation and control logic diagrams; and reviewed motor torque calculations to verify that the motor operators would function during worst case accident conditions.

b. Findings

No findings of significance were identified.

.2.8 Decay Heat Sea Water Pump (RWP-3B)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of the diesel driven emergency feedwater pump (RWP-3). The team also reviewed operating procedures to verify correct implementation of design bases. The team examined system health reports, records of surveillance testing and maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team inspected the sea water room (area housing RWP-3) to examine internal and external flooding potential. The team also reviewed applicable elements of implementation of GL 89-13, Service Water System Problems Affecting Safety-Related Equipment. The team reviewed hydraulic calculations to verify that the pump degradation assumed in the IST surveillances would not prevent RWP-3 from performing its safety-related function and that design flow and pressure requirements were correctly translated into IST acceptance criteria. The team also reviewed the hydraulic calculations to verify that runout flow was acceptable. The team reviewed the RWP-3 pump net positive suction head NPSH design and vortexing calculations to verify the pumps would have adequate suction head and not ingest air under accident conditions. Additionally, the team reviewed calculations for brake horsepower, and relay settings to verify that components would be able to perform their function during accident conditions. The team also performed a walkdown to assess visible material condition and verify that the installation was consistent with design documentation. The team also performed interviews with plant personnel to discuss the condition of RWP-3.

b. Findings

No findings of significance were identified.

.2.9 Decay Closed Loop Cooling Pump (DCP 1B)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of the DCP 1B. The team examined system health reports, records of surveillance testing and maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team reviewed the NPSH design calculation to verify the pumps would have adequate suction head under accident conditions. The team also interviewed plant personnel to discuss the history of vibration issues and the status of associated corrective actions and performed walkdowns to observe material conditions.

b. Findings

No findings of significance were identified.

.2.10 DC Bus DPDP-5A

a. Inspection Scope

The team reviewed the UFSAR, TS, and drawings to identify the design bases requirements of the DC bus DPDP-5A. The team reviewed the system health reports and maintenance activities to verify that potential degradation was being monitored and prevented or corrected. The team reviewed design calculations for battery capacity and voltage drop to verify that components would have sufficient DC power to perform their function during accident conditions. The team also performed a walkdown of DPDP-5A to verify that the correct fuses were installed as described in design documentation.

b. Findings

No findings of significance were identified.

.2.11 Post Accident Monitoring Instrumentation (PAM)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant documents, and drawings to identify the design bases requirements of the PAM System. In addition, the team verified that selected PAM instrumentation (Containment Sump Water Level, Containment Pressure, Containment Area Radiation, Emergency Feedwater Flow, Degrees of Subcooling, and DHV-42 and DHV-43 Valve Position) met the requirements of RG 1.97, Criteria for Accident Monitoring Instrumentation for Nuclear Power Plants.

The team examined system health reports, surveillance test records, maintenance records, and applicable corrective actions to verify that potential degradation was being monitored and prevented, or corrected. Inspectors also verified that power would be available to PAM System components during accident conditions. The team ensured that the equipment qualification of PAM System instrumentation is suitable for the environment expected under accident conditions.

b. Findings

No findings of significance were identified.

.2.12 Off-Site Power Source

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant documents, and drawings to identify the design bases requirements of the off-site power system. The team reviewed the one-line diagram to verify that the main electrical features, separation, operating conditions, and connections met design requirements. The review included the evaluations of grid stability, reliability, and the effects on the plant offsite power source. The team reviewed protective relaying and surge and lightning protection to ensure that protection was in accordance with requirements. The team reviewed evaluations for medium voltage bus transfers to verify that design requirements were met. The team reviewed operating procedures to verify the adequacy of procedural guidance for transferring power to and from the offsite system, including backfeeding the plant from the 500 kV system. The team reviewed maintenance and test procedures to verify that proper supervision of the two offsite power transformers was implemented. High voltage breaker control and instrumentation was reviewed to ascertain compliance with design and operating criteria.

Additionally, the team performed a plant walk down of the 230 kV and the 500 kV switchyards to assess physical conditions.

b. Findings

No findings of significance were identified.

.2.13 Control Power for Switchyard Breakers 4900, 4902, 1691, and 1692

a. Inspection Scope

The team reviewed the UFSAR, TS and drawings to identify the design bases requirements of the DC power that feeds the switchyard breakers for off-site power. The team reviewed the system health reports and maintenance documentation to verify that potential degradation was being monitored and prevented or corrected. The team reviewed design calculations for battery capacity and voltage drop to verify that the breakers close coil would have sufficient DC power. The team performed interviews with plant personnel and reviewed docketed licensing correspondence about the transition of Crystal River Units 1 and 2 (fossil units) station batteries out of the Crystal River Unit 3 TS. The team also performed a walkdown of the switchyard breakers and Crystal River Units 1, 2, and 3 station batteries to assess visible material condition and to verify that the installation was consistent with design documentation.

b. Findings

Introduction:

The team identified a Green non-cited violation (NCV) of 10 CFR 50.63, Loss of all alternating current power, for failure to ensure Regulatory Guide (RG) 1.155, Station Blackout commitments were implemented in calculations for restoring off-site power.

Description:

Crystal Rivers SBO coping duration is four hours The recovery actions necessary to energize an emergency safeguards (ES) bus within four hours requires one offsite or one onsite power source. To energize an ES bus upon restoration of offsite power, the closure of at least one 230kV breaker from either of two offsite power supplies is required. The 230kV breakers (1691, 1692, 4900 and 4902) receive control power from different batteries in the Crystal River complex. CR3 (nuclear unit) station batteries provide control power for breakers 4900 and 4902 which serve one offsite power circuit; and CR1&2 (fossil units) station batteries provide control power for breakers 1691 and 1692 which serve the other offsite power circuit. The availability of control power allows plant operators to remotely close the breakers from the control room. Inadequate control power to the breakers would delay restoring offsite power because transmission personnel would be required to enter the switchyard to locally operate the breakers. Plant personnel are not qualified to locally operate the breakers.

The licensee did not include the 230kV switchyard breakers 4900 and 4902 close coils in calculations, E90-0100, Electrical DC System Revalidation System Voltage Profile Calculations, and E90-0103, Electrical DC System Revalidation Control Circuit Calculation. The team noted the licensee did not include the 4900 and 4902 closing coils because the licensee assumed that the site would recover power to the ES bus from an onsite emergency diesel generator before an offsite power circuit was available.

The team determined that the assumption is non-conservative because the licensee is required to restore offsite power should it become available first. The licensee entered this into their corrective action program (CAP) as NCR 406661, and took immediate actions to verify that adequate voltage would exist at the terminals of the close coils for breakers 4900 and 4902.

CR1&2 batteries are not controlled under the same program as CR3 batteries, and as a result do not have any supporting calculations to show that the batteries could supply adequate terminal voltage to the close coils of breakers 1691 and 1692. Additionally, the inspectors determined that CR3 was not monitoring the availability of the batteries.

For example, CR3 was not informed of CR1&2 battery replacements performed in 2009 and 2010. The licensee entered the issue into their corrective action program as NCRs 402629, 404939, 406661 and 406668.

Analysis:

The licensees failure to maintain calculations to assure adequate voltage for the remote closing of the switchyard breakers during a SBO event is a performance deficiency. The team determined that the finding is more than minor because it adversely affected the design control 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.

Specifically, because there were no supporting calculations for the recovery of an offsite power supply, design changes and operational decisions could have negatively impacted the ability of the breakers to perform their function or could have caused a delay in restoring power to the ES bus. The team determined the finding is of very low safety significance (Green) using the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter 0609 because it did not represent a loss of system or safety function. A cross-cutting aspect was not identified because the finding does not represent current performance.

Enforcement:

10 CFR 50.63, Loss of all alternating current power, states, in part that light-water-cooled nuclear power plants must be able to withstand and recover from a station blackout. Also, RG 1.155, Station Blackout, Appendix A, Quality Assurance Guidance for Non-Safety Systems and Equipment, of which Crystal River is committed, states, in part, that measures should be established to ensure that all design-related guidelines used in complying with 50.63 are included in design and procurement documents. Contrary to the above, the licensee failed to incorporate the commitments of RG 1.155 needed to assure recovery from a SBO into calculations and therefore, failed to meet the requirement of being able to recover from a SBO. Specifically, the licensee failed to incorporate electrical requirements into calculations to assure the ability to remotely energize safety-related buses from offsite during a SBO event.

Because this finding is of very low safety significance and because it was entered into the licensees corrective action program as NCR 402629, 404939, 406661 and 406668, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000302/2010007-02, Failure to Incorporate Requirements of Recovering from a Station Blackout into Calculations.

.2.14 High Pressure Injection Throttle Valves (MUV-590, MUV-591, MUV-592, and MUV-593)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of MUV-590, MUV-591, MUV-592, and MUV-593. The team also reviewed operating procedures to verify correct implementation of design bases. The team examined system health reports, records of surveillance testing, maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team also performed a walkdown to assess visible material condition and verify that the installation was consistent with design documentation. The team also performed interviews with plant personnel to discuss the history of the valve testing, maintenance, and details of completed corrective actions.

b. Findings

No findings of significance were identified.

.2.15 Nuclear Services and Decay Heat Seawater System Check Valve (RWV-36)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations and drawings to identify design basis requirements of RWV-36. The team reviewed engineering changes and associated valve modifications to determine the impact of the changes on the valves functions. The team examined records of surveillance testing, maintenance work orders, and corrective actions to verify that degradation was being monitored and prevented, or corrected. The team reviewed corrective action documents to verify the adequacy of actions taken. The team reviewed surveillance procedures and operating procedures to verify the adequacy of procedural guidance to detect and mitigate a stuck open check valve. Additionally, the team reviewed a calculation that determined an acceptable leakage limit for the check valve to verify the adequacy of this limit under the most limiting accident conditions. The team performed interviews with plant personnel to discuss the surveillance history, maintenance records, corrective actions, and valve modifications.

b. Findings

No findings of significance were identified.

.2.16 Letdown Isolation Boundary Valve (MUV-567)

a. Inspection Scope

The team reviewed the UFSAR, TS, applicable plant calculations, and drawings to identify the design bases requirements of MUV-567. The team examined system health reports, records of surveillance testing, maintenance activities, and applicable corrective actions to verify that potential degradation was being monitored and prevented or corrected. The team also performed several interviews with plant personnel to discuss the history of the valve testing, maintenance, and details of the corrective actions that had been completed. The team also conducted a visual inspection of MUV-567 to verify that any degraded material conditions were being appropriately addressed. In addition, the team verified that the power demand requirements for the valves were captured in electrical load and degraded voltage calculations. The team also verified that the worst case/highest differential pressure was used to determine the maximum valve opening and/or closing requirements to ensure that the valve would perform its intended safety-related design basis function. A review was conducted of the licensees testing procedures and diagnostic valve test results to verify the MOV was tested in a manner that would detect a malfunctioning valve.

b. Findings

No findings of significance were identified.

.2.17 Decay Heat (DC) and Service Water (SW) Expansion Tank (SWT-1, DCT-1A, and DCT-

1B) Level Indicators

a. Inspection Scope

The team reviewed the UFSAR, applicable plant calculations, and drawings to identify the design bases requirements for level indicators and associated ball/check valves mounted on the Decay Heat system and Service Water system expansion tanks. The team reviewed design documentation, conducted a walkdown, interviewed personnel and reviewed corrective action documents to verify that the level indicators would withstand a seismic event.

b. Findings

Introduction:

The team identified a non-cited violation of 10 CFR 50.65(a)(1) for the licensees failure to monitor service water (SW) and decay heat (DC) cooling expansion tank level indicator check valves.

Description:

SWT-1 is a pressurized expansion tank located at the same elevation as the SW circulating pumps and is common to all pumps. The cover gas of the tank is nitrogen. SWT-1 maintains adequate net positive suction head (NPSH) for the safety-related pumps. SW is a closed loop circulation water system with two safety-related pumps and a single non-safety related pump. All three pumps are networked in a common system that has no individual trains. In addition to providing cooling to safety related loads: Reactor Building cooling, MUP-1B cooling, and cooling of the dedicated raw water pumps, the SW system also cools a number of important to safety loads, such as: reactor coolant pump seals and motors, spent fuel pool, letdown heat exchanger, control rod drive mechanism, etc.

DCT-1A and DCT-1B are pressurized expansion tanks located at the same elevation as the DC circulating pumps. The cover gas of the tank is nitrogen. DC is a closed loop circulation water system with two safety-related trains; each train provides safety-related cooling to high and low pressure injection pumps and cooling to dedicated raw water pumps. DCT-1A and DCT-1B provides overpressure protection for their respective trains.

The level indicator for tanks SWT-1, DCT-1A, and DCT-1B are similar to the ones used for boilers - high-pressure prismatic glass encased in a metal housing. Each level indicator is approximately 7 feet long and is connected to the tank by an upper and lower isolation valves. A function of the isolation valves is to mitigate postulated breaks of the sight glasses. The isolation valve has an integrated ball/check valve that is designed to isolate at a differential pressure of 3 psid to prevent the loss of nitrogen pressure and inventory.

In response to an NRC inspection in 1987, the licensee evaluated the seismic adequacy of the level indicators. The licensee documented in Interoffice Correspondence, NEA87-1244 (dated December 16, 1987) that SWT-1 level indicator was not qualified and would fail during a seismic event. NEA87-1244 recommended isolating the level indicator from tank SWT-1. A similar recommendation for the DC tanks (DCT-1A, DCT-1B) level indicators was documented in Interoffice Correspondence, WPN88-0030 (dated June 22, 1988). In Interoffice Correspondence, OP88-140 (dated July 26, 1988)the Operations Department decided against manually isolating the level indicators when not in use because an isolation function was provided by the ball/check valves. A previous engineering evaluation, WPN88-0037 (dated July 15, 1988) stated that the ball/check valves would withstand a seismic event and perform its isolation function in the event of a level indicator failure.

The team determined that ball/check valves credited for isolation were not entered in the maintenance program and that the licensee did not have a record of any maintenance activities associated with these valves. The combination of a lack of seismic qualification for the level indicators and a lack of maintenance on the ball/check valves resulted in a reasonable doubt that the SW and DC systems would perform their design functions during a postulated seismic event or passive failure of a level indicator. In response to this concern, the licensee initiated NRC 404297, closed the isolation valves as an interim action, seismically qualified the level indicators using a finite element analysis conducted by a vendor (S10-0048, Seismic Qualification of SW-133-LI, SWT-1 Level Indicator) and performed an in situ check valve test (NCR 404297-18, SWV-275 &

276 Test Analysis) with satisfactory results.

Analysis:

The licensees failure to perform appropriate maintenance on the ball/check valves was a performance deficiency. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the failure to perform appropriate maintenance on the ball/check valves and the failure to either isolate or perform a seismic analysis of the SWT-1, DCT-1A and DCT 1B level indicator gages resulted in a lack of reasonable assurance that the SW and DC would provide adequate cooling to essential equipment used to mitigate design bases accidents. The team determined the finding is of very low safety significance (Green) using the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter 0609 because it did not represent a loss of system or safety function based on the teams review of the licensees seismic qualification and ball/check valve test results. The team determined that the finding does not represent current performance; therefore a cross-cutting aspect was not identified.

Enforcement:

10 CFR 50.65(a)(1) states, in part, that licensees shall monitor the performance or condition of structures, systems and components (SSCs) within the scope of the rule as defined by 10 CFR 50.65 (b), against licensee-established goals, in a manner sufficient to provide reasonable assurance that these SSCs are capable of fulfilling their intended function.

10 CFR 50.65(a)(2) states, in part, that monitoring as specified in (a)(1) is not required where it has been demonstrated that the performance or condition of a component is being effectively controlled through the performance of appropriate preventive maintenance such that the SSC remains capable of fulfilling its intended function.

Contrary to the above, the licensee failed to demonstrate that the performance or condition of the ball/check valves had been effectively controlled through the performance of appropriate preventive maintenance and did not monitor performance against licensee established goals. Specifically, since 1988, the licensee failed to perform preventative maintenance to assure the capability of the check valves to isolate the level indicators during a postulated break of a level indicator. Because this violation was determined to be of very low safety significance (Green) and was entered into the licensees corrective action program as NRC 404297, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy and is identified as NCV 05000302/2010007-03, Failure to Monitor the Service Water and Decay Cooling Expansion Tank Check Valves.

.3 Review of Low Margin Operator Actions

a. Inspection Scope

The team performed a margin assessment and detailed review of five risk significant and time critical operator actions. Where possible, margins were determined by the review of the assumed design basis and UFSAR response times. For the selected operator actions, the team performed a walkthrough of associated Emergency Operating Procedures (EOPs) Abnormal Operating Procedures (AOPs), Annunciator Response Procedures (ARPs), and other operations procedures with plant operators and engineers to assess operator knowledge level, adequacy of procedures, availability of special equipment when required, and the conditions under which the procedures would be performed. Detailed reviews were also conducted with operations and training department leadership, and through observation and utilization of a simulator training period to further understand and assess the procedural rationale and approach to meeting the design basis and UFSAR response and performance requirements.

Operator actions were observed on the plant simulator and during plant walk downs.

Operator actions associated with the following events/evolutions were reviewed:

• Operator actions for Inadequate Heat Transfer

• Operator actions for LOCA Cooldown

• Operator actions for HPI Cooldown

• Operator actions for Restoration of Off-site Power during a Station Blackout Event

b. Findings

No findings of significance were identified.

.1 Review of Industry Operating Experience

a. Inspection Scope

The team reviewed selected operating experience issues that had occurred at domestic and foreign nuclear facilities for applicability at the Crystal River Nuclear Plant. The team performed an independent applicability review for issues that were identified as applicable to the Crystal River Nuclear Plant and were selected for a detailed review.

The issues that received a detailed review by the team included:

• RIS 2006-23, Post-Tornado Operability of Ventilating and Air-Conditioning Systems Housed in Emergency Diesel Generating Rooms

• IN 2008-20, Failures of Motor Operated Valve Actuator Motors with Magnesium Alloy Rotors

• IN 83-77, Air/Gas Entrainment Events Resulting in System Failures

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On June 25, 2010, the team presented preliminary inspection results to members of the licensees staff. Proprietary information that was reviewed during the inspection was returned to the licensee.

A final exit was performed on September 9, 2010 and the results of open inspection items were presented to Mr. S. Cahill and other members of the licensees staff.

ATTACHMENT: SUPPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Herrin, Licensing

F. Prieto, Design Engineering Supervisor (Electrical / I&C)

NRC personnel

B. Desai, Chief, Engineering Branch Chief 1, Division of Reactor Safety, RII

LIST OF ITEMS

Opened and Closed

05000302/20100076-01 NCV Preconditioning of Safety-Related Air Operated Valves (Section 1R21.2.2)

05000302/20100076-02 NCV Failure to Incorporate Requirements of Recovering from a Station Blackout into Calculations (Section 1R21.2.13)

05000302/20100076-03 NCV Failure to Monitor the Service Water and Decay Cooling Expansion Tank Check Valves (Section 1R21.2.17)