IR 05000424/2010007

IR 05000424-10-007 & 05000425-10-007 on 06/14/10 - 07/16/10 for Vogtle Electric Generating Plant, Units 1 and 2; Component Design Basis Inspection

ML102310602
Person / Time
Site:	Vogtle
Issue date:	08/17/2010
From:	Binoy Desai NRC/RGN-II/DRS/EB1
To:	Tynan T Southern Nuclear Operating Co
References
IR-10-007
Download: ML102310602 (36)

Text

UNITED STATES ust 17, 2010

SUBJECT:

VOGTLE ELECTRIC GENERATING PLANT - NRC COMPONENT DESIGN BASIS INSPECTION REPORT 05000424/2010007 AND 05000425/2010007

Dear Mr. Tynan:

On July 16, 2010, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your Vogtle Electric Generating Plant, Units 1 and 2. The enclosed inspection report documents the inspection findings which were discussed on July 16, 2010 with Mr. Russ Dedrickson, Plant Manager, and on August 9, 2010, via telephone, with Mr. Tom Petrak, Engineering Support Manager as well as other members of your staff.

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 Vogtle Electric Generating 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 Vogtle Electric Generating Plant.

The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

SNC 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.: 50-424, 50-425 License Nos.: NPF-68, NPF-81

Enclosure:

Inspection Report 05000424/2010007, 05000425/2010007 w/Attachment:

Supplemental Information

REGION II==

Docket Nos.: 50-424, 50-425 License Nos.: NPF-68, NPF-81 Report No.: 05000424/2010007, 05000425/2010007 Licensee: Southern Nuclear Operating Company, Inc. (SNC)

Facility: Vogtle Electric Generating Plant, Units 1 and 2 Location: Waynesboro, GA 30830 Dates: June 14, 2010 through July 16, 2010 Inspectors: R. Berryman, P.E., Senior Reactor Inspector (Lead)

S. Walker, Senior Reactor Inspector D. Mas-Penaranda, Reactor Inspector J. Eargle, Reactor Inspector S. Kobylarz, Contractor S. Spiegelman, Contractor Accompanying Personnel: M. King, Senior Reactor Inspector (Team Leader)

Approved by: Binoy B. Desai, Chief Engineering Branch 1 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000424/2010007, 05000425/2010007; 06/14/10 - 07/16/10; Vogtle Electric Generating

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

This inspection was conducted by a team of four NRC inspectors, one NRC inspector who was in training, 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 inspectors identified a Severity Level (SL) IV non-cited violation (NCV) of 10 CFR 50.71(e)(4) for the failure to reflect all changes made in the facility or procedures as described in the updated final safety analysis report (UFSAR) up to a maximum of six months prior to the date of filing of periodic updates to the UFSAR with the NRC. Licensee procedure NMP-ES-022, DCP Site Approval, Implementation and Closure, Ver. 7.0 addressed the processing of documentation regarding design change packages (DCPs). Step 6.7.2.3 of this procedure required the modification engineer to assign an action item to the licensing document owner identified in the licensing document change request (LDCR). Licensee procedure NMP-AD-009, Licensing Document Change Requests, Ver. 8.0 addressed the processing of LDCRs. NMP-AD-009 included updates to the UFSAR in the scope of LDCRs. This procedure did not contain any timeliness guidance regarding the completion of LDCRs which impacted the UFSAR to ensure compliance with the requirements of 10 CFR 50.71(e)(4). The licensee submitted Revision 15 of the UFSAR to the NRC on April 16, 2009. The inspectors identified five instances where DCPs were implemented which made changes to the facility or procedures as described in the UFSAR more than six months prior to the April 16, 2009 submittal. This finding was entered into the licensees corrective action program as condition report (CR) 2010109181.

The failure to reflect all changes made in the facility or procedures as described in the UFSAR up to a maximum of six months prior to the date of filing of periodic updates to the UFSAR with the NRC is a performance deficiency. Traditional enforcement applies since this finding reflects an impact on the regulatory process in the form of timely and accurate reports to the NRC. This finding is more than minor consistent with Section XIII, Supplement I, D.6 of the NRC Enforcement Policy. This section of the enforcement policy states, in part, that a failure to update the FSAR as required by 10 CFR 50.71(e) in cases where the information is not used to make an unacceptable change to the facility or procedures is a SL IV violation. The team reviewed the five DCPs which were implemented greater than six months prior to the submission of Revision 15 of the UFSAR to the NRC and conducted focused queries of licensee CRs dating back to the implementation of the oldest of the five affected DCPs. The team was not able to find any occurrences where the lack of timely updates to the UFSAR resulted in an unacceptable change to the facility or procedures.

The inspectors determined that the thorough evaluation of problems such that resolutions address causes and extent of conditions, as necessary was a significant cause of this performance deficiency. The licensee generated CR 2007107068 in June 2007 in response to a discovery that the FSAR did not reflect the changes associated with a DCP. The extent of condition of the corrective actions associated with this failed to identify that the LDCR procedure did not contain any timeliness guidance to ensure compliance with 10 CFR 50.71(e)(4). This is directly related to the Corrective Action Program component of the cross-cutting area of Problem Identification and Resolution (P.1.(c)).

(Section 1R21.2.08)

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 residual heat removal (RHR) system, safety injection (SI) system, primary safety valves (PSVs), pressurizer power-operated relief valves (PORVs), steam generator (SG) atmospheric relief valves (ARVs), 4160 VAC electrical system,480 VAC electrical system, 120 VAC electrical system, and the reactor trip breakers (RTBs). 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, 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 are included in the following sections of the report.

.2.1 4160 VAC Switchgear Bus 1BA03

a. Inspection Scope

The inspectors reviewed the one-line diagrams, the short-circuit and load-flow calculations, and the switchgear vendor specifications and drawings to determine maximum load, interrupting duty and bus bracing requirements for design basis conditions. This review was also conducted to verify conformance with the switchgear equipment vendor ratings. The breaker coordination calculation was reviewed to verify selective coordination for the reserve auxiliary transformer and load center 1BB16 feeder breakers. Switchgear and circuit breaker maintenance results were reviewed for indications of adverse conditions. The inspectors reviewed the modification history to verify that modifications did not adversely impact the design basis. The inspectors also reviewed the corrective maintenance and condition report history to verify that there were no recurring issues affecting reliability. An inspector walkdown of the switchgear was performed to observe the visible material condition of components to verify that any potentially degraded conditions were appropriately addressed.

b. Findings

No findings were identified.

.2.2 4160/480 VAC Transformer 1BB16X and Load Center 1BB16

a. Inspection Scope

The inspectors reviewed one-line diagrams, transformer vendor test results, and the transformer model in the load study calculation to confirm that correct transformer impedance values were utilized. The inspectors confirmed the adequacy of the overcurrent relay settings for design-basis loading requirements and for selected load center breaker coordination, including motor control center (MCC) thermal overload relay heater selection methodology for degraded voltage conditions. The inspectors reviewed the modification history to verify that modifications did not adversely impact the design basis. The inspectors also reviewed the corrective maintenance and condition report history for recurring issues which could have impacted reliability. An inspector walkdown of the load center and transformer was performed to assess observable material conditions and to verify that any potentially degraded conditions were appropriately addressed.

b. Findings

No findings were identified.

.2.3 Safeguards Driver Cards A516 and A517

a. Inspection Scope

The inspectors reviewed schematic diagrams and the vendor manual to identify key circuit card components. The inspectors also reviewed vendor recommendations and industry operating experience on card refurbishment and preventive maintenance and compared them to licensee programs to verify that actions were appropriate. The inspectors reviewed the corrective maintenance and condition report history to verify that any reliability issues were appropriately addressed. The inspectors reviewed the preventive maintenance procedures to verify that components that affected solid-state protection system (SSPS) reliability were replaced periodically in accordance with industry recommendations. An inspector walkdown of the SSPS was performed to assess observable material condition and to verify that any potentially degraded conditions were appropriately addressed.

b. Findings

No findings were identified.

.2.4 Reactor Trip Breakers

a. Inspection Scope

The team reviewed the maintenance manuals and vendor technical manuals for the reactor trip breakers to verify that vendor requirements had been incorporated into station maintenance and surveillance procedures. The inspectors reviewed station procedures and records to verify that 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 potentially degraded conditions were properly documented and resolved.

Maintenance and surveillance schedules were reviewed to verify that vendor and TS periodicity requirements were being satisfied. Maintenance and corrective action documentation was reviewed to verify that potentially degraded conditions were being appropriately addressed.

b. Findings

No findings were identified.

.2.5 Loss of Offsite Power (LOSP) Relay K158

a. Inspection Scope

The inspectors reviewed the LOSP and degraded voltage relay setpoint calculations, motor starting and running voltage calculations, and MCC control circuit voltage-drop calculations to verify that adequate voltage would be provided to safety-related devices at required design voltage levels. In addition, the inspectors reviewed procedures and completed surveillance tests for relay calibration to verify that acceptance criteria was consistent with the design calculations and the relays were capable of performing the intended safety functions. The team also reviewed operating procedures to determine whether the limits and protocols for maintaining offsite voltage were consistent with the design calculations. The team interviewed the system engineer and performed a non-intrusive visual inspection of the relays to assess the installation configuration and material condition to verify that potentially degraded conditions were being appropriately addressed.

b. Findings

No findings were identified.

.2.6 120 VAC Instrument Panel 1BY2B

a. Inspection Scope

The inspectors reviewed loading and sizing calculations for the Inverter and transformer connected to instrument panel 1BY2B to verify whether the panel would have sufficient capacity to support its required loads under worst-case accident loading conditions. The inspectors reviewed degraded voltage calculations to verify that the cumulative effects were appropriately considered in determining that supplied voltage would be adequate during worst-case design conditions. The inspectors also reviewed installed panel circuit breaker ratings to verify that the interrupting capability was appropriate given potential short-circuit currents. The inspectors interviewed the system engineer and performed a non-intrusive visual inspection of the transformer, inverter and panel 1BY2B to assess the installation configuration and verify that degraded material conditions were being appropriately addressed. A review of associated corrective action history was also performed to verify that potentially degraded conditions were being appropriately addressed.

b. Findings

No findings were identified.

.2.7 RHR Pump 1A, 1B, 2A, and 2B Motors

a. Inspection Scope

The inspectors reviewed control diagrams to verify that the controls of the RHR pump motors were consistent with the design basis and operational requirements. The inspectors reviewed voltage calculations to verify that adequate voltage to the motors would be available under worst-case accident conditions. The inspectors reviewed the results of the load-flow and voltage calculations to verify that sufficient power would be available to start the motors during worst-case degraded voltage and service conditions.

Additionally, the inspectors reviewed the motor protection setting calculations to verify that there was adequate overcurrent protection during degraded voltage conditions. The inspectors reviewed the pump performance and brake horsepower requirements to verify that the motor was adequately sized for the worst-case load conditions. The inspectors reviewed maintenance and corrective action documents to verify that potentially degraded conditions were being appropriately addressed. The inspectors performed a non-intrusive visual inspection of the RHR pump motors to assess the installation configuration and verify that degraded material conditions were being appropriately addressed.

b. Findings

No findings were identified.

.2.8 RHR Pumps 1A, 1B, 2A, and 2B

a. Inspection Scope

The inspectors reviewed the design basis documents, net positive suction head (NPSH)calculations, heat transfer calculations, and system flow calculations to verify that required flow could be supplied by the pumps for required functions. The inspectors also compared the design flow with the values and functions specified in the updated final safety analysis report (UFSAR) and TS to verify that acceptance criteria were appropriate. The inspectors interviewed design and systems engineers and reviewed pump test results, trending data, and corrective actions over the past three years of operation to verify that any potentially degraded conditions were addressed promptly and in a comprehensive manner. Finally, the inspectors walked down the RHR pumps to evaluate the physical condition of the pumps and adjacent equipment to verify that degraded material conditions were being appropriately addressed.

b. Findings

Introduction:

The inspectors identified a Severity Level (SL) IV non-cited violation (NCV)of 10 CFR 50.71(e)(4) for the failure to reflect all changes made in the facility or procedures as described in the UFSAR up to a maximum of six months prior to the date of filing of periodic updates to the UFSAR with the NRC.

Description:

Licensee procedure NMP-ES-022, DCP Site Approval, Implementation and Closure, Version (Ver.) 7.0 addressed the processing of documentation regarding design change packages (DCPs). Step 6.7.2.3 of this procedure required the modification engineer to assign an action item to the licensing document owner identified in the licensing document change request (LDCR). Licensee procedure NMP-AD-009, Licensing Document Change Requests, Ver. 8.0 addressed the processing of LDCRs.

NMP-AD-009 included updates to the UFSAR in the scope of LDCRs. This procedure did not contain any timeliness guidance regarding the completion of LDCRs which impacted the UFSAR to ensure compliance with the requirements of 10 CFR 50.71(e)(4).

The licensee submitted Revision 15 of the UFSAR to the NRC on April 16, 2009. The inspectors identified five instances where DCPs were implemented which made changes to the facility or procedures as described in the UFSAR more than six months prior to the April 16, 2009 submittal yet the UFSAR was not updated to reflect the changes.

Analysis:

The failure to reflect all changes made in the facility or procedures as described in the UFSAR up to a maximum of six months prior to the date of filing of periodic updates to the UFSAR with the NRC is a performance deficiency. The inspector determined that traditional enforcement per NRC Enforcement Policy was applicable since this finding reflects an impact on the regulatory process in the form of timely and accurate reports to the NRC. This finding is more than minor consistent with Section XIII, Supplement I, D.6 of the NRC Enforcement Policy. This section of the enforcement policy states, in part, that a failure to update the FSAR as required by 10 CFR 50.71(e) in cases where the information is not used to make an unacceptable change to the facility or procedures is a SL IV violation. The team reviewed the five DCPs which were implemented greater than six months prior to the submission of Revision 15 of the UFSAR to the NRC and conducted focused queries of licensee condition reports (CRs) dating back to the implementation of the oldest of the five affected DCPs. The team did not identify any occurrences where the lack of timely updates to the UFSAR resulted in an unacceptable change to the facility or procedures.

The inspectors determined that the lack of s thorough evaluation of problems such that the resolution address causes and extent of conditions, as necessary was a significant cause of this performance deficiency. The licensee generated CR 2007107068 in June 2007 in response to a discovery that the UFSAR did not reflect the changes associated with a DCP. The extent of condition of the corrective actions associated with this failed to identify that the LDCR procedure did not contain any timeliness guidance to ensure compliance with 10 CFR 50.71(e)(4). 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 50.71(e)(4) states, in part, that periodic revisions to the UFSAR submitted to the NRC must reflect all changes made in the facility or procedures as described in the UFSAR up to a maximum of six months prior to the date of filing.

Contrary to the above, Vogtle submitted Revision 15 of the UFSAR to the NRC on April 16, 2009 with five DCPs implemented in the plant which were greater than six months old and affected the facility or procedures as described in the UFSAR. Because this is a non-willful SL IV violation and was entered into the licensees corrective action program as CR 2010109181, this finding is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000424 and 425/2010007-01, Violation of 10 CFR 50.71(e)(4) for Failure to Reflect Changes to Facility and Procedures in Final Safety Analysis Report Periodic Revisions)

.2.9 Nuclear Service Cooling Water (NSCW) Pumps

a. Inspection Scope

The inspectors walked down accessible areas of the NSCW pumps and the tower basins to verify that any potentially degraded material conditions were being appropriately addressed. The inspectors evaluated selected condition reports, operability determinations, and apparent cause reports to verify that appropriate and timely corrective actions were implemented. In-service testing (IST) results were reviewed to verify that adequate flow was available in accordance with design calculations to achieve the system requirements identified in the UFSAR, TS, and design-basis requirements.

Interviews were conducted with the system engineer and design engineers to discuss the system health and any plans for system modifications. NPSH and system resistance calculations were reviewed and compared with test results and regulatory commitments to verify that the pumps could provide required flow during design-basis conditions.

b. Findings

No findings were identified.

.2.10 High Pressure Recirculation Suction Valve from RHR Heat Exchanger A (HV8804A)

a. Inspection Scope

The inspectors conducted a non-intrusive visual inspection of HV8804A to verify that potentially degraded material conditions were being appropriately addressed. The inspectors compared valve testing data with the design opening and closing time requirements to verify that valve performance was adequate. The inspectors reviewed calculations that determined required valve actuator torque and thrust limits and traced these requirements to the vendor-supplied data. The inspectors interviewed the systems engineer and corporate valve engineers to discuss the valve analysis as well as operational and maintenance history to verify that potentially degraded conditions were being appropriately addressed.

b. Findings

No findings were identified.

.2.11 SI Pump B Suction Motor-Operated Valve (MOV) (HV8923B)

a. Inspection Scope

The inspectors conducted a non-intrusive visual inspection of HV8923B to verify that potentially degraded material conditions were being appropriately addressed. The inspectors interviewed the systems engineer to verify that potentially adverse material conditions were being addressed appropriately. The inspectors reviewed the vendor data for valve design, including the valve manual and the design calculations to verify that calculations appropriately considered valve thrust and torque loads that the operator load limit was not exceeded. The inspectors reviewed calculations that determined required valve actuator torque and thrust limits and traced these requirements to the vendor-supplied data.

b. Findings

No findings were identified.

.2.12 Safety Injection Pumps - 1/2-1204-P6-003/4 & Mini-Flow Isolation MOVs 1/2HV8813

a. Inspection Scope

The inspectors reviewed applicable portions of the plant TS, UFSAR, design basis documents (DBDs), system descriptions, and system lesson plans to identify design basis requirements for the SI pumps. Design calculations (i.e., minimum flow, NPSH, minimum voltage, differential pressure, and required torque/thrust) and site procedures were reviewed to verify that the design basis and design assumptions had been appropriately translated into these documents. The inspectors reviewed the calculations for degraded voltage at the MOV terminals to verify that proper voltage was utilized in the torque calculations. Control logic diagrams were reviewed to verify that the mini-flow isolation logic was consistent with the protection of the pump. The licensee response to GL 88-04 was reviewed to verify that the mini-flow line provides adequate flow to ensure protection of the pump. The inspectors reviewed system modifications to verify that any modifications did not degrade the components performance capability and were appropriately incorporated into relevant drawings and procedures. Component walkdowns were conducted to verify that the installed configurations would support their design basis function under accident conditions and had been maintained to be consistent with design assumptions. Control panel indicators were observed and operating procedures reviewed to verify that component operation and alignments were consistent with design and licensing basis assumptions. Test procedures and recent test results were reviewed against design basis documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. External event analyses were reviewed against design specifications and requirements in order to verify that the equipment was adequately protected. The inspectors examined maintenance rule documentation to verify that the pumps were properly scoped, and monitored. Vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action system documents were reviewed in order to verify that potential degradation was monitored or prevented and that scheduled component replacements were consistent with vendor recommendations and equipment qualification life.

b. Findings

No findings were identified.

.2.13 Steam Generator ARVs (1/2PV3000, 3010, 3020, and 3030)

a. Inspection Scope

The inspectors reviewed applicable portions of the plant TS, UFSAR, DBDs, system descriptions, and system lesson plans to identify design basis requirements for the ARVs. Design calculations and site procedures were reviewed to verify that the design basis and design assumptions had been appropriately translated into these documents.

Control logic diagrams were reviewed to verify that controls and interlocks were consistent with the design-basis performance requirements and operating procedures.

The inspectors reviewed system modifications to verify that any modifications did not degrade the performance capability of the ARVs and were appropriately incorporated into relevant drawings and procedures. Component walkdowns were conducted to verify that the installed configurations would support the design basis function under accident conditions and had been maintained to be consistent with design assumptions. Control panel indicators were observed and operating procedures reviewed to verify that component operation and alignments were consistent with design and licensing basis assumptions. Test procedures and recent test results were reviewed against design basis documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. External event analyses were reviewed against design specifications and requirements in order to verify that the equipment was adequately protected. The inspectors examined maintenance rule documentation to verify that the valves were properly scoped, and monitored.

Vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action system documents were reviewed in order to verify that potential degradation was monitored or prevented and that scheduled component replacements were consistent with vendor recommendations and equipment qualification life.

b. Findings

No findings were identified.

.2.14 Pressurizer PORVs and Block Valves (1PV0455A, 1PV0456A, and 1HV8000A/B)

a. Inspection Scope

The inspectors reviewed applicable portions of the plant TS, UFSAR, DBDs, system descriptions, and system lesson plans to identify design basis requirements for the pressurizer PORVs and associated PORV block valves. Design calculations (i.e.,

minimum voltage, flow, differential pressure, and required torque/thrust) and site procedures were reviewed to verify the design basis and design assumptions were appropriately translated into these documents. The inspectors reviewed the calculations for degraded voltage at the MOV terminals to verify that proper voltage was utilized in the torque calculations. Control logic diagrams and single-line power supply drawings were reviewed to verify that any controls and interlocks were consistent with the design basis performance requirements and operating procedures. The inspectors reviewed system modifications to verify that any modifications did not degrade the performance capability and were appropriately incorporated into relevant drawings and procedures.

Control panel indicators were observed and operating procedures reviewed to verify that component operation and alignments were consistent with design and licensing basis assumptions. Test procedures and recent test results were reviewed against design basis documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. External event analyses were reviewed against design specifications and requirements in order to verify that the equipment was adequately protected. The inspectors examined maintenance rule documentation to verify that the valves were properly scoped, and monitored.

Vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action system documents were reviewed in order to verify that potential degradation was monitored or prevented and that scheduled component replacements were consistent with vendor recommendations and equipment qualification life.

b. Findings

No findings were identified.

.2.15 Pressurizer Safety Valves (1/2PSV8010A, 1/2PSV8010B, and 1/2PSV8010C)

a. Inspection Scope

The inspectors reviewed applicable portions of the plant TS, UFSAR, DBDs, system descriptions, and system lesson plans to identify design basis requirements for the valves. Design calculations and site procedures were reviewed to verify the design basis and design assumptions were appropriately translated into these documents. The team reviewed system modifications to verify that any modifications did not degrade component performance capability and were appropriately incorporated into relevant drawings and procedures. Control panel indicators were observed and operating procedures reviewed to verify that component operation and alignments were consistent with design and licensing basis assumptions. Test procedures and recent test results were reviewed against design basis documents to verify that acceptance criteria for tested parameters were supported by calculations or other engineering documents and that individual tests and analyses served to validate component operation under accident conditions. External event analyses were reviewed against design specifications and requirements in order to verify that the equipment was adequately protected. The inspectors examined maintenance rule documentation to verify that the valves were properly scoped, and monitored. Vendor documentation, system health reports, preventive and corrective maintenance history, and corrective action system documents were reviewed in order to verify that potential degradation was monitored or prevented and that scheduled component replacements were consistent with vendor recommendations and equipment qualification life.

b. Findings

No findings 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 (ARPs), 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 as appropriate.

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

• Operator Initiates high pressure injection (HPI) after AC Recovered during station blackout (SBO)

• Operator response to an anticipate transient without SCRAM (ATWS)

• Operator Actions to Establish high pressure recirculation (HPR) for long-term feed and bleed

• Operator actions to depressurize steam generators during SBO

b. Findings

No findings 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 Vogtle Electric Generating Plant. The issues that received a detailed review by the team included:

• IN 2003-19, Unanalyzed Condition of Reactor Coolant Pump Seal Leakoff Line During Fire Scenarios or Station Blackout

• NRC Information Notice 2007-09, Equipment Operabilty Under Degraded Volatage Conditions.

• IN 2000-06, Offsite Power Inadequacies

• GL 91-07, GI-23 "Reactor Coolant Pump Seal Failures" and Its Possible Effect on Station Blackout

• IN 2006-029, Potential Common Cause Failure of Motor-operated Valves as a result of Stem Nut Wear

• IN 2006-026, Failure of Magnesium Rotors in Motor-operated Valve Actuators

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On July 16, 2010, the team presented the inspection results to Mr. Russ Dedrickson, Vogtle Electric Generating 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.

On August 9, 2010, a telephone exit was conducted with Mr. Tom Petrak, Vogtle Electric Generating Plant Engineering Support Manager, and other members of the licensee staff.

ATTACHMENTS:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

S. Ashworth, Principal Engineer - Mechanical Design Support

D. Bunch, Senior Engineer - Technical Support

G. Coady, Senior Engineer - Technical Support

N. Davis, Engineer - Electrical Design Support

W. Gover, Principal Engineer - Engineering Support

M. Hickox, Principal Engineer - Licensing

S. Kerstiens, Principal Engineer - Engineering Support

J. Olson, Senior Engineer - Site Design Mechanical

R. Reddy, Senior Engineer - Electrical Design Support

L. Smith, Principal Engineer - Site Design I&C

E. Sweat, Senior Engineer - Senior Engineer - PRA

J. Todd, Shift Manager - Operations

NRC

M. Cain, Senior Resident Inspector, Vogtle Electric Generating Plant

LIST OF ITEMS

OPENED, CLOSED, AND REVIEWED

Opened

05000424, 425/2010007-01 NCV Violation of 10 CFR 50.71(e)(4) for Failure to Reflect Changes to Facility and Procedures in Final Safety Analysis Report Periodic Revisions (Section 1R21.2.08)