IR 05000327/2010007

IR 05000327-10-007, 05000328-10-007; on 03/15/10 - 04/16/10; Sequoyah Nuclear Plant, Units 1 and 2; Component Design Basis Inspection

ML101450460
Person / Time
Site:	Sequoyah
Issue date:	05/24/2010
From:	Binoy Desai NRC/RGN-II/DRS/EB1
To:	Krich R Tennessee Valley Authority
References
IR-10-007
Download: ML101450460 (31)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION May 24, 2010

SUBJECT:

SEQUOYAH NUCLEAR PLANT - NRC COMPONENT DESIGN BASIS INSPECTION REPORT 05000327/2010007, 05000328/2010007

Dear Mr. Krich:

On April 16, 2010, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Sequoyah Nuclear Plant, Units 1 and 2. The enclosed inspection report documents the inspection findings which were discussed on April 16, 2010 with Mr. Ken Langdon, Plant Manager.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, the inspectors identified one finding of very low safety significance (Green), which involved a violation of NRC requirements. However, because of the very low safety significance and because it is entered into your corrective action program, the NRC is treating this finding as a Non-Cited Violation (NCV) consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you contest this NCV you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U. S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Sequoyah 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 Sequoyah Nuclear Plant. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

TVA 2 In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of 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.: 50-327, 50-328 License Nos.: DPR-77, DPR-79

Enclosure:

Inspection Report 05000327/2010007, 05000328/2010007 w/Attachment:

Supplemental Information

REGION II==

Docket Nos.: 50-327, 50-328 License Nos.: DPR-77, DPR-79 Report No.: 05000327/2010007, 05000328/2010007 Licensee: Tennessee Valley Authority (TVA)

Facility: Sequoyah Nuclear Plant, Units 1 and 2 Location: Sequoyah Access Road Soddy-Daisy, TN 37379 Dates: March 15, 2010 through April 16, 2010 Inspectors: R. Berryman, P.E., Senior Reactor Inspector (Lead)

R. Aiello, Senior Operations Engineer D. Mas-Penaranda, Reactor Inspector R. Patterson, Reactor Inspector C. Baron, Contractor G. Skinner, Contractor Approved by: Binoy B. Desai, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000327/2010007, 05000328/2010007; 03/15/10 - 04/16/10; Sequoyah Nuclear Plant,

Units 1 and 2; Component Design Basis Inspection.

This inspection was conducted by a team of four NRC inspectors and two NRC contract inspectors. One Green finding, which was a non-cited violation (NCV), was identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process (SDP). Finding for which the SDP does not apply may be Green or is 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 Green non-cited violation (NCV) of 10 CFR 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to properly maintain the vendor contact program for safety-related components.

The team identified 37 examples of vendor technical manuals where the associated vendor had not been contacted in over three years. Procedure SPP-2.5, Vendor Manual Control, required contact to be made with the vendors of safety-related components every three years to ensure that technical manuals and vendor documents contained the most current and applicable information consistent with the guidance of Generic Letter (GL) 90-03. The team identified 37 examples of vendor manuals and technical documents where the associated vendor had not been contacted in more than three years with several examples extending to almost six years. The licensee entered this issue into their corrective action program with actions to make contact with the vendors for all documents identified as having not been verified with the vendor in over the required three years. This finding was entered into the licensees corrective action program as problem evaluation reports (PERs) 224364 and 224975. As an immediate corrective action, the licensee is ensuring that the vendor manuals and documents associated with safety-related components are being verified as most current with the respective vendors.

This finding is more than minor because it affected the Mitigating Systems Cornerstone objective of ensuring the availability and reliability of safety systems, is related to the attribute of Procedure Quality (i.e., Maintenance and Testing (Pre-Event) Procedures) and represented a programmatic break-down which if left uncorrected, could become a more significant safety concern. The team assessed this finding using the SDP and determined that the finding was of very low safety significance (Green) because the inspectors found no documented occurrences where the lack of vendor contact ultimately resulted in the inability of a safety-related component to perform the intended safety function and will be treated as an NCV.

The inspectors determined that the thorough evaluation of problems such that the resolutions address problems and extent of conditions, as necessary was a significant cause if this performance deficiency. The plant experienced a reactor trip in 2009 which was determined to have been caused, in part, by a vendor manual associated with a feedwater regulating valve (FRV) not being updated.

The FRVs are components with both safety-related and non-safety-related features. The extent of condition of the corrective actions associated with this failed to identify the programmatic breakdown of the TVA vendor contact program for safety-related components. This is directly related to the Corrective Action Program component of the cross-cutting area of Problem Identification and Resolution (P.1.(c)). (Section 1R21.2.3)

Licensee-Identified Violations

None.

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 two or Birnbaum value greater than 1 X10-6. The components selected were located within the main steam isolation valves (MSIVs), steam generator safety relief valves (SRVs), pressurizer power-operated relief valves (PORVs), emergency diesel generator (EDG) support and electrical subsystems, 6900 VAC electrical system, common station service transformers (CSSTs), 250 VDC battery system, control air system, reactor trip breakers, anticipated transient without SCRAM (ATWS) mitigating system actuation circuitry (AMSAC), and the containment spray (CS) system. The sample selection included 15 components, five operator actions, and five 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 modification, 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 included items such as failed performance test results, significant corrective action, repeated maintenance, maintenance rule (a)1 status, Regulatory Issue Summary (RIS)05-020 (formerly Generic Letter (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 are included in the following sections of the report.

.2.1 6900 VAC Shutdown Board 1A-A

a. Inspection Scope

The team reviewed bus loading calculations to determine whether the 6900 VAC system had sufficient capacity to support its required loads under worst case accident loading and grid voltage conditions. The team reviewed the design of the 6900 VAC bus degraded voltage protection scheme to verify that it could provide adequate voltage to safety-related devices at all voltage distribution levels. This included a review of the degraded voltage relay setpoint calculations, motor starting and running voltage calculations, and motor control center (MCC) control circuit voltage-drop calculations.

The team reviewed procedures and completed surveillance tests for calibration of the degraded voltage relays to determine whether acceptance criteria was consistent with the design calculations, and to determine whether the relays were capable of performing the intended safety functions. The team reviewed operating procedures to determine whether the limits and protocols for maintaining offsite voltage were consistent with design calculations. The team reviewed the Sequoyah Nuclear Plant response to NRC GL 2006-02 to determine whether current procedures for maintaining the availability of offsite power were consistent with the licensees response to the GL. The team reviewed corrective action documents and maintenance records to determine whether there were any adverse operating trends. In addition, the team performed a visual inspection of the 6900 VAC safety buses to assess the material condition and the presence of hazards.

b. Findings

Introduction.

The team indentified an Unresolved Item (URI) regarding calculations that supported the degraded voltage protection scheme. The calculations that analyzed the Class 1E 6900 VAC and 480 VAC motor loads took credit for using administrative controls for limiting the minimum 161kV offsite power supply bus voltage and credited performance of the non-safety-related automatic load tap changers on the CSSTs to limit the minimum voltage on the Class 1E 6900 VAC and 480 VAC buses. The calculations did not evaluate the Class 1E 6900 VAC and 480 VAC motor loads at the worst case possible low voltages which could drop as low as the bottom end of the acceptable tolerance band of the degraded voltage relays.

Description.

Offsite power is normally provided to the Class 1E 6900 VAC buses from the 161kV offsite power system through the CSSTs. The CSSTs have automatic load tap changers which are designed to maintain approximately 6900 VAC on the Class 1E buses through a dynamic range of 161kV offsite power supply voltages. The Class 1E 480 VAC buses are then powered from fixed-tap 6900/480VAC transformers powered from the respective Class 1E 6900 VAC buses.

NUREG-0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants, Appendix 8-A, Branch Technical Position PSB-1: Adequacy of Station Electric Distribution System Voltages, Rev. 2 (07/1981) is part of the licensing basis for the Sequoyah Nuclear Plant. This document states, in part, that the selection of under-voltage and time-delay setpoints shall be determined from an analysis of the voltage requirements of the Class 1E loads at all onsite distribution levels. Calculation SQNETAPAC, AC Auxiliary Power System Analysis, Rev. 36 evaluated transient motor starting voltages at the beginning of a design basis loss of coolant accident (LOCA) and was based on the voltages where the minimum 161kV offsite power supply bus voltage was limited by taking credit for administrative controls rather than assuming a worst-case 161kV offsite power supply voltage drop which would still allow voltage recovery to the degraded voltage relay reset setpoint (minus setpoint tolerance) before the expiration of the degraded voltage relay nominal 9.5 second time delay and thereby leave the Class 1E 6900 VAC buses connected to the offsite power supply. In addition, calculations for motor starting during steady-state conditions credited voltage improvement based on performance of the non-safety related CSST automatic load tap changers instead of being based on worst-case conditions.

Summary. This issue is unresolved pending further inspection to determine

(1) the actual worst-case voltage required to be analyzed on the Class 1E 6900 VAC and 480 VAC buses for safety-related loads in accordance with the facility licensing basis; and (2)the impact of not using the worst-case bus voltage afforded by the degraded voltage protection scheme in safety-related 6900 VAC and 480 VAC motor starting studies.

(URI 05000327, 328/2010007-01, Worst Case 6900 VAC Bus Voltage in Design Calculations)

.2.2 Common Station Service Transformers (CSSTs)

a. Inspection Scope

The team reviewed load-flow calculations to determine whether the capacity of the CSSTs was adequate to supply the worst-case accident loads. The team reviewed calculations and operating procedures to determine whether bus voltages maintained by the automatic load tap changer were adequate to assure the availability of offsite power during low-voltage conditions. The team reviewed the sources of power for automatic control equipment to determine whether the automatic load tap changer would operate properly during low-voltage conditions. The team reviewed maintenance schedules, procedures, and completed work records to determine whether the transformer was being properly maintained. The team reviewed corrective action histories to determine whether there had been any adverse operating trends. In addition, the team performed a visual inspection of the CSSTs to assess the material condition and the presence of hazards.

b. Findings

No findings of significance were identified.

.2.3 Reactor Trip Breakers

a. Inspection Scope

The team reviewed the maintenance manual and vendor technical update information for the Westinghouse DB-50 reactor trip breakers to determine whether vendor requirements have been incorporated into station maintenance and surveillance procedures. The inspectors reviewed station procedures and records to determine whether periodic vendor contacts were performed as required to ensure up-to-date vendor information was being maintained in station technical files. The inspectors reviewed completed maintenance documentation to verify that anomalies were properly documented and resolved. Maintenance and surveillance schedules were reviewed to verify that vendor and Technical Specification (TS) periodicity requirements were being satisified. Maintenance and corrective action documentation was reviewed to verify that adverse conditions were being appropriately corrected.

b. Findings

Introduction.

The team identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to properly maintain the vendor contact program for safety-related components. The team identified 37 examples of vendor technical manuals where the associated vendor had not been contacted in over three years.

Description.

Procedure SPP-2.5, Vendor Manual Control, required contact to be made with the vendors of safety-related components every three years to ensure that technical manuals and vendor documents contained the most current and applicable information consistent with the guidance of GL 90-03. The team identified 37 examples of vendor manuals and technical documents where the associated vendor had not been contacted in more than three years with several examples extending to almost six years. The licensee entered this issue into their corrective action program with actions to make contact with the vendors for all documents identified as having not been verified with the vendor in over the required three years.

Analysis.

The failure to follow procedure for the vendor contact program for safety-related components is a performance deficiency. This finding is more than minor because it affected the Mitigating Systems Cornerstone objective of ensuring the availability and reliability of safety systems, is related to the attribute of Procedure Quality (i.e., Maintenance and Testing (Pre-Event) Procedures) and represented a programmatic break-down which if left uncorrected, could become a more significant safety concern. The team assessed this finding using the SDP and determined that the finding was of very low safety significance (Green) because the inspectors found no documented occurrences where the lack of vendor contact ultimately resulted in the inability of a safety-related component to perform the intended safety function and will be treated as an NCV.

The inspectors determined that the thorough evaluation of problems such that the resolutions address problems and extent of conditions, as necessary was a significant cause if this performance deficiency. The plant experienced a reactor trip in 2009 which was determined to have been caused, in part, by a vendor manual associated with a feedwater regulating valve (FRV) not being updated. The FRVs are components with both safety-related and non-safety-related features. The extent of condition of the corrective actions associated with this failed to identify the programmatic breakdown of the TVA vendor contact program for safety-related components. This is directly related to the Corrective Action Program component of the cross-cutting area of Problem Identification and Resolution (P.1.(c)).

Enforcement.

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Contrary to the above, the licensee did not adequately follow the vendor manual control program to ensure that instructions, procedures, and drawings for safety-related components were the most current and applicable information. This condition had existed since at least 2007. Because this finding was of very low safety significance and was entered into the TVA corrective action program as problem evaluation reports (PERs) 224364 and 224975, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy. (NCV 05000327, 328/2009007-01, Violation of 10CFR50, Appendix B, Criterion V for Failure to Follow Procedure for Vendor Contact Program)

.2.4 Emergency Diesel Generator 1A-A (Electrical)

a. Inspection Scope

The team performed a limited review of EDG1A-A. The team reviewed battery sizing and voltage drop calculations for diesel generator battery DGS 1A-A to determine whether it had sufficient capacity and capability to perform its required functions during both accident and Station Blackout scenarios. The team also reviewed maintenance and corrective action documents to determine whether there were any adverse operating trends. In addition, the team performed a visual inspection of EDG1A-A to assess material conditions and the presence of hazards

b. Findings

No findings of significance were identified.

.2.5 Station Batteries I, II, III, and IV

a. Inspection Scope

The team reviewed electrical documents for station batteries I,II,III and IV including battery duty-cycle and voltage-drop calculations, overall battery capacity, five-year performance discharge test results, and quarterly battery surveillance test results. In addition, the voltage-drop calculations for safety-related DC loads and DC control power to 480V and 6900V switchgear was evaluated to determine if adequate voltage was available at these loads during station blackout (SBO) and LOCA events. The team performed walk-downs of the station batteries to assess the material condition. The team also reviewed the system health reports and selected PERs initiated over the past two years to verify that the licensee was adequately identifying, evaluating, and addressing adverse conditions

b. Findings

No findings of significance were identified.

.2.6 Anticipated Transient Without Scram (ATWS) Mitigating System Actuation Circuitry

(AMSAC)

a. Inspection Scope

The team reviewed system instrumentation and control drawings; electrical elementary and schematic diagrams; and calibration procedures and test records to verify that the instrumentation and controls for the AMSAC system were consistent with the design basis requirements. The team also reviewed instrument setpoint calculations to verify that the calculations included appropriate instrument uncertainties. The last two completed calibration tests results were reviewed to verify that instrument setpoints were consistent with setpoint calculations and to verify that equipment performance was appropriately monitored and maintained consistent with the design and licensing basis.

In addition, the team reviewed the system health reports and selected PERs initiated over the past two years to confirm that the licensee was adequately identifying, evaluating, and addressing any adverse conditions.

b. Findings

No findings of significance were identified.

.2.7 EDGs - Mechanical

a. Inspection Scope

The team inspected the mechanical aspects of the EDGs to verify the capability to perform the required design functions. This inspection included a review of the design and capacity of the fuel oil tanks and fuel oil transfer pumps. Applicable calculations and tests were reviewed to verify the capability of the EDGs to operate for the required mission time. The team reviewed station applicable procedures associated with the use of ultra-low sulfur diesel (ULSD) and bio-diesel fuels to ensure that the correct fuel was being used. This review included an evaluation of ULSD and procedures to prevent the acceptance of bio-diesel fuels for use in the EDGs. The team reviewed the design and supporting calculations of the EDG air start system to verify that the required capability to start the EDGs under design basis conditions could be satisfied.

The team inspected the EDG area ventilation system to verify that the system was capable of providing the EDGs with adequate cooling and that any vulnerabilities during a design basis tornado event were appropriately addressed. This review included applicable design calculations and walk-downs of the system components. The team also reviewed the capability of the block walls in the EDG area to withstand the pressure differentials associated with a tornado depressurization event.

In addition, the team performed interviews with the EDG system engineer, reviewed applicable corrective action documents, and performed an extensive walk-down of the EDGs and associated equipment. The walk-down included verification of the material condition of equipment and verification that the vents associated with the EDG fuel tanks were adequately protected from intrusion of foreign materials

b. Findings

No findings of significance were identified.

.2.8 Pressurizer Power Operated Relief Valves (PORVs)

a. Inspection Scope

The team inspected the pressurizer PORVs to verify the capability to perform the required design functions. This inspection included an interview with the system engineer; a review of applicable PERs; and a review of the valve test procedures and a summary of recent test results to identify any adverse trends. The team also reviewed operating procedures associated with the use of the PORVs under design basis conditions and the isolation of a stuck open PORV to verify that the operating procedures adequately addressed these conditions.

b. Findings

No findings of significance were identified.

.2.9 Steam Generator (SG) Safety Relief Valves (SRVs)

a. Inspection Scope

The team inspected the SG SRVs to verify the capability to perform the required design functions. This inspection included interviews with the system engineer and operations personnel; a review of applicable PERs; and a review of the valve test procedures and a summary of recent test results to identify any adverse trends. The team reviewed operating procedures associated with postulated SG tube rupture (SGTR) events to verify that the operating procedures adequately addressed these conditions and to verify the capability of the plant to mitigate this event in accordance with the licensing and design basis. The team also observed a SGTR event with a loss of a train of the instrument air system in the simulator to verify that sufficient time would be available to perform required manual operator actions.

In addition, the team performed walk-downs of the SG SRV areas to assess the material condition of the equipment and the capability of operators to access the areas if required.

b. Findings

No findings of significance were identified.

.2.10 Containment Spray (CS) Pumps

a. Inspection Scope

The team inspected the CS pumps to verify their capability to perform the required design functions. This inspection included interviews with the system engineer; a review of applicable PERs; and a review of the pump surveillance test procedures and a summary of recent test results to identify any adverse trends. The team reviewed operating procedures associated with CS pump operation for both testing and accident conditions to verify that the operating procedures adequately addressed these conditions and to verify that CS system was capable of mitigating required postulated accidents in accordance with the licensing and design basis. The team reviewed CS flow and net positive suction head (NPSH) calculations to verify that the CS pumps could perform the required functions under the most limiting postulated accident conditions. The team also reviewed the bases for the CS pump surveillance test acceptance criteria to verify that appropriate margins were included.

In addition, the team performed walk-downs of the CS pump areas to assess the material condition of the equipment and the capability of operators to access the areas if required.

b. Findings

No findings of significance were identified.

.2.11 Main Steam Isolation Valves (MSIVs)

a. Inspection Scope

The team reviewed applicable portions of the UFSAR, TS, calculations, and drawings to verify the capability of the MSIVs to perform the required functions during design basis events. The inspectors interviewed the system engineer to discuss the overall health of the MSIVs and associated PERs to assess the material conditions of the valves. The inspectors also reviewed design change notice (DCN) M-11705A Removal of Check Valve Internals Downstream of the MSIV to verify that the MSIVs were not adversely affected. MSIV stroke-timing test results were also reviewed to verify that any degradation was being appropriately monitored and addressed.

b. Findings

No findings of significance were identified.

.2.12 Control Air System Supply Valves (32-450, 451, 544, 545, and 546)

a. Inspection Scope

The team reviewed the system design criteria documents (DCDs), related design basis support documentation, drawings, TS, and the UFSAR to identify design, maintenance, and operational requirements for the Control Air System. The team reviewed selected preventative work orders to verify that degraded conditions were being appropriately monitored and addressed. A field walk-down was performed with the system engineer to assess observable material conditions and verify that the system configuration was consistent with the design basis assumptions, system operating procedures, and plant drawings

b. Findings

No findings of significance were identified.

.2.13 Auxiliary Control Air Receiver Relief Valve (32-319 and 259)

a. Inspection Scope

The team reviewed the system DCD, related design basis support documentation, drawings, TS, and the UFSAR to identify design, maintenance, and operational requirements for the auxiliary control air safety relief valves. Maintenance history and associated PERs were reviewed to verify that potential degradation was being monitored and appropriately addressed. Setpoint procedures were reviewed to verify that appropriate design inputs and vendor tolerances were appropriately incorporated into testing acceptance criteria. The team conducted a field walk-down of the relief valves to verify that the installed configuration was consistent with the design basis and plant drawings and to assess any observable material conditions.

b. Findings

No findings of significance were identified.

.2.14 Reactor Coolant System (RCS) Safety Injection (SI) Cold Leg Injection Inlet Check Valve

63-561

a. Inspection Scope

The team reviewed the system DCD, related design basis support documentation, drawings, TS, and the UFSAR to identify design, maintenance, and operational requirements for selected SI cold leg injection check valves. Maintenance history, as demonstrated by system health reports, preventative and corrective maintenance, and PERs, were reviewed to assess material conditions. The team conducted interviews with the system engineer to obtain additional information regarding the sites response to GL 2008-01 and to verify that the implementation and analysis of industry operating experience related to check valves was appropriate.

b. Findings

No findings of significance were identified.

.2.15 Boric Acid Transfer Pumps

a. Inspection Scope

The team reviewed portions of the DCD, TS, and UFSAR to verify the capability of the pumps to perform the required function under required conditions. Calculations establishing pump performance requirements were reviewed to verify that the assumptions and conclusions were appropriate. In-service testing (IST) results were reviewed to assess the potential pump degradation and to verify that pump performance was sufficient to satisfy pump requirements. In addition, the team reviewed the system health reports and corrective action documentation to assess material conditions.

Additionally, the inspectors interviewed the system engineer to assess the overall health and performance history of the system. The inspectors also conducted a walk-down of the pumps and associated piping and valves to verify that any adverse material conditions were being appropriately addressed.

b. Findings

No findings of significance were identified.

.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 and performance times documented by job performance measures (JPMs). For the selected components and operator actions, the team performed an assessment of the Emergency Operating Procedures (EOPs), Abnormal Operating Procedures (AOPs), Annunciator Response Procedures (APPs), and other operations procedures to determine the adequacy of the procedures and availability of equipment required to complete the actions. Operator actions were observed on the plant simulator and during plant walk downs using JPMs.

The following operator actions were observed on the licensees operator training simulator:

• Actions to address an anticipated transient without SCRAM including in-plant walkdown of JPM to remotely open reactor trip breakers per FR-S.1, Nuclear Power Generation/ATWS, Rev. 23.

• Actions to address a stuck open PORV after SI per E-1, Loss of Reactor or Secondary Coolant, Rev. 24.

• Actions to address a LOOP concurrent with the failure of all EDGs leading to SBO per ECA 0.0, Loss of All AC Power, Rev. 23.

• Actions to verify the ability to transfer containment spray suction to the containment sump (within 13 minutes) given a failure of the auto-swap of the RHR suction fails per ECA 1.1, Loss of RHR Sump Recirculation, Rev. 11

• Actions to address a steam generator tube rupture given failure of three of four SG atmospheric relief valves to open remotely from the control room per E-3, Steam Generator Tube Rupture, Rev. 17.

b. Findings

No findings of significance were identified.

.4 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 Sequoyah Nuclear Plant. The issues that received a detailed review by the team included:

• IN 95-037, Inadequate Offsite Power System Voltages During Design-Basis Events

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

• IN 2007-014, Loss of Offsite Power and Dual-Unit Trip at Catawba Nuclear Generating Station

• IN 92-06 and 92-06 Supplement 1, Reliability of ATWS Mitigation System and Other NRC Required Equipment Not Controlled by Plant Technical Specifications

• RIS 06-023, Post-tornado Operability of Ventilating and Air-conditioning Systems Housed in Emergency Diesel Generator Rooms

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 16, 2010, the team presented the inspection results to Mr. Ken Langdon, Sequoyah Nuclear Plant Manager, and other members of the licensee staff. The team returned all proprietary information examined to the licensee. No proprietary information is documented in the report.

ATTACHMENTS:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Baese, Electrical Engineering Design (contractor)

G. Bell, I&C Engineering Design

E. Craig, Mechanical Engineering Design

D. Hawes, Operations Training Supervisor

D. Porter, Operations Supervisor

R. Proffitt, Licensing Manager

K. Pulliam, Mechanical Engineering Design

M. Shlyamberg, Consultant

D. Sutton, Licensing Engineer

N. Thomas, Licensing Engineer

J. Wilson, Systems Engineer

B. Zeik, Engineering Design Manager

NRC

C. Young, Senior Resident Inspector, Sequoyah Nuclear Plant

LIST OF ITEMS

OPENED, CLOSED, AND REVIEWED

Opened

05000327, 328/2010007-01 NCV Violation of 10 CFR 50, Appendix B, Criterion V for Failure to Follow Procedure for Vendor Contact Program (Section 1R21.2.3)

05000327, 328/2010007-01 URI Degraded Voltage Relay Issue (Section 1R21.2.1)