IR 05000424/2011002

IR 0500424-11-002, and 05000425-11-002, on 03/31/2011, Vogtle Electric Generating Plant - NRC Inspection Report

ML111220555
Person / Time
Site:	Vogtle
Issue date:	04/29/2011
From:	Scott Shaeffer NRC/RGN-II/DRP/RPB2
To:	Tynan T Southern Nuclear Operating Co
References
IR-11-002
Download: ML111220555 (41)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ril 29, 2011

SUBJECT:

VOGTLE ELECTRIC GENERATING PLANT - NRC INTEGRATED INSPECTION REPORT 05000424/2011002 AND 05000425/2011002

Dear Mr. Tynan:

On March 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Vogtle Electric Generating Plant, Units 1 and 2. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 22, 2011, with you and other members of your staff.

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

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

This report documents one NRC-identified finding and one self-revealing finding of very low safety significance (Green) which were determined to be violations of regulatory requirements.

In addition, one licensee-identified violation which was determined to be of very low safety significance, is listed in the enclosed inspection report. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCV) consistent with the NRC Enforcement Policy. If you contest any NCV, 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 Vogtle Electric Generating Plant. In addition, if you disagree with the cross-cutting aspect assigned to 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 Senior Resident Inspector at the Vogtle facility. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

SNC 2 In accordance with the Code of Federal Regulations 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosures, 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 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/

Scott M. Shaeffer, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Nos.: 50-424, 50-425 License Nos.: NPF-68 and NPF-81

Enclosures:

Inspection Report 05000424/2011002 and 05000425/2011002 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-424, 50-425 License Nos.: NPF-68, NPF-81 Report Nos.: 05000424/2011002 and 05000425/2011002 Licensee: Southern Nuclear Operating Company, Inc. (SNC)

Facility: Vogtle Electric Generating Plant, Units 1 and 2 Location: Waynesboro, GA 30830 Dates: January 1, 2011 through March 31, 2011 Inspectors: M. Cain, Senior Resident Inspector T. Chandler, Resident Inspector R. Hamilton, Senior Health Physicist (Sections 2RS6, 2RS7, 4OA1)

A. Nielsen, Senior Health Physicist (Section 2RS8)

J. Rivera-Ortiz, Senior Reactor Inspector (Section 1R08)

R. Kellner (Section 2RS7)

A. Sengupta, Reactor Inspector (Section 1R08)

Approved by: Scott M. Shaeffer, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000424/2011-002, 05000425/2011-002; 1/01/2011 - 3/31/2011; Vogtle Electric Generating

Plant, Units 1 and 2; Containment Integrity and Fire Protection The report covered a three-month period of inspection by two resident inspectors, two senior health physicists, a senior reactor inspector, and a reactor inspector. Two non-cited violations (NCV) with very low safety significance (Green) were identified. The significance of most findings is indicated by their color (great than Green, or Green, White, Yellow, Red); the significance was determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP); the cross-cutting aspect was determined using IMC 0310,

Components Within The Cross-Cutting Areas; and that findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

Cornerstone: Barrier Integrity

Green.

The NRC identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, for the licensees failure to conduct a general visual examination of the Units and 2 containment metallic liner around the reactor cavity underneath the reactor vessel. The licensee took corrective actions to conduct the required visual examinations in Unit 1, including ultrasonic testing (UT) thickness measurements to evaluate the condition of the liner, and initiated action items to examine the same area in Unit 2 during the next refueling outage. The licensee initiated Condition Report (CR)2011104688 to address the issue through the Corrective Action Program (CAP) and conducted the required general visual inspection in Unit 1 containment and found no pitting or cracking in the area examined. In addition, the licensee performed UT thickness measurements in affected areas of the metallic liner to evaluate the liner thickness against the design criteria The licensees failure to conduct a general visual examination of the containment metallic liner in the reactor cavity area underneath the reactor vessel in accordance with the American Society of Mechanical Engineers (ASME) Code,Section XI, Subsection IWE was a performance deficiency. The finding was more than minor because it was associated with the Design Control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective in that visual inspections of the containment metallic liner were not performed to provide reasonable assurance that the liner remained capable of performing its intended safety function. The finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of the reactor containment. The finding has a cross-cutting aspect in the operating experience (OE) component of the area of problem identification and resolution because OE was not implemented and institutionalized through station procedures. P.2.b] (Section 1R08)

Cornerstone: Mitigating Systems

Green.

A self-revealing NCV of Vogtle Unit 1 operating license condition 2.G. and Vogtle Unit 2 operating license condition 2.G. was identified for failure to maintain the main firewater header pressurized. Specifically, in response to two firewater header low pressure alarms, operations personnel failed to perform the steps listed in the alarm response procedure. This led to the inadvertent depressurization of the main firewater header. Once the licensee became aware of the system depressurization, the shift supervisor directed an operator to start the available jockey pump, and within a few minutes system pressure was restored. This event was entered into the licensees corrective action program as CR 2010113782.

The finding is considered more than minor because it is associated with external events attribute of the Mitigating Systems cornerstone. Specifically, the performance deficiency adversely affected the protection against external events (fire) attribute of the Mitigating Systems cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Both the Phase 1 and Phase 2 screening worksheets of IMC 0609, Appendix F, indicated that the violation was potentially greater-than-green. The regional Senior Reactor Analyst completed a Phase evaluation. This evaluation concluded that the violation was of very low safety significance (Green). The inspectors determined that the cause of this finding was related to the Decision-Making component of the Human Performance cross-cutting area due to operators using non-conservative assumptions in their decision making. H.1(a)

(Section 4OA5.2)

Violations of very low safety significance, which were identified by the licensee, have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees CAP. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at essentially full RTP from January 1 until March 6, when it was shut down for a planned refueling outage. Unit 1 remained shut down for the remainder of the inspection period.

Unit 2 operated at essentially full RTP for the entire inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

a. Inspection Scope

==

Impending Adverse Weather Condition Review. On March 9th, the inspectors reviewed licensee procedures 11889-C, Severe Weather Checklist, and 18017-C, Abnormal Grid Disturbances/Loss of Grid, to verify the licensee had implemented actions to prepare the plant site for predicted severe weather conditions of heavy thunderstorms and possible tornadoes. The inspectors walked down various safety-significant areas of the plant to verify the licensees ability to respond to the predicted adverse weather conditions.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

a. Inspection Scope

==

Partial System Walkdown. The inspectors performed partial walkdowns of the following three systems to verify correct system alignment. The inspectors checked for correct valve and electrical power alignments by comparing positions of valves, switches, and breakers to the documents listed in the Attachment. Additionally, the inspectors reviewed the condition report database to verify that equipment alignment problems were being identified and appropriately resolved.

• Unit 2 train A&C auxiliary feedwater systems while the train B motor-driven auxiliary feedwater pump was out of service due to a planned maintenance outage

• Unit 1 train B essential chilled water system during the train A essential chilled water system maintenance outage

• Unit 1 train B residual heat removal (RHR) system while the train A RHR system was out of service due to a planned maintenance outage Complete System Walkdown. The inspectors performed a complete walkdown of the Unit 2 B train emergency diesel generator (EDG) system. The inspectors performed a detailed check of valve positions, electrical breaker positions, and operating switch positions to evaluate the operability of the redundant trains or components by comparing the required position in the system operating procedure to the actual position. The inspectors also reviewed control room logs, condition reports, and system health reports to verify that alignment and equipment discrepancies were being identified and appropriately resolved. The documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

==1R05 Fire Protection

a. Inspection Scope

==

Fire Drill Observation. On February 7, inspectors observed a fire drill from the control room, the primary fire brigade locker, and the fire scene. The fire was simulated to be in the Unit 1 Normal HVAC room (R403) located on the fourth floor of the Auxiliary Building, in the Fuel Handling Building normal purge supply unit heater panel. The inspectors assessed the adequacy of the fire drill and fire brigade response using licensee procedures 92000-C, Fire Protection Program; 92005-C, Fire Response Procedure; NMP-TR-425, Fire Drill Program; and 17103A-C, Annunciator Response Procedures for the Fire Alarm Computer. The inspectors evaluated the fire brigade performance to verify that they responded to the fire in a timely manner, donned proper protective clothing, used self-contained breathing apparatus, and had the equipment necessary to control and extinguish the fire. The inspectors assessed the adequacy of the fire brigades fire fighting strategy including entry into the fire area, communications, search and rescue, and equipment usage.

Fire Area Tours. The inspectors walked down the following five plant areas to verify the licensee was controlling combustible materials and ignition sources as required by procedures 92015-C, Use, Control, and Storage of Flammable/Combustible Materials, and 92020-C, Control of Ignition Sources. The inspectors assessed the observable condition of fire detection, suppression, and protection systems and reviewed the licensees fire protection Limiting Condition for Operation log and condition report (CR)database to verify that the corrective actions for degraded equipment were identified and appropriately prioritized. The inspectors also reviewed the licensees fire protection program to verify the requirements of Updated Final Safety Analysis Report Section 9.5.1, Fire Protection Program, and Appendix 9A, Fire Hazards Analysis, were met.

Documents reviewed are listed in the Attachment.

• Unit 2 A train and B train cable spreading rooms

• Unit 1 component cooling water (CCW) pump rooms

• Unit 1 control building level B reactor trip switchgear room

• Unit 2 control building level B reactor trip switchgear room

• Unit 1 containment building

b. Findings

No findings were identified.

==1R07 Heat Sink Performance

a. Inspection Scope

==

Annual Review. The inspectors observed the licensees conduct of the performance tests on the Unit 1, B train component cooling water (CCW) and auxiliary component cooling water (ACCW) heat exchangers. Following the test, the inspectors reviewed the completed data sheets and calculations. The inspectors also reviewed EPRI NP-7552, Heat Exchanger Performance Monitoring Guidelines, to ensure that the licensees testing procedures were appropriate. Additionally, the inspectors reviewed the licensees corrective action program (CAP) for heat exchanger performance issues to ensure that discrepancies were being identified and appropriately resolved. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

==1R08 Inservice Inspection (ISI) Activities (Unit 1)

=

.1 Non-Destructive Examination (NDE) Activities and Welding Activities===

a. Inspection Scope

The inspectors reviewed the implementation of the licensees Risk Informed In-service Inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS)boundary and risk significant piping boundaries. The inspectors activities consisted of an on-site review of NDE and welding activities to evaluate compliance with the applicable edition of the ASME Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 2000 Edition through the 2001 Addenda), and that indications and defects (if present) were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI acceptance standards.

The inspectors directly observed the NDE activities listed below and reviewed examination procedures, NDE reports, equipment and consumables certification records, personnel qualification records, and calibration reports (as applicable) for the following examinations:

• UT examination (phased array) of weld 11201-V6-001-W38, RCS Cold Leg Nozzle (ASME Class 1)

• UT examination (conventional automated UT) of weld 11201-V6-001-W37, RCS Hot Leg Nozzle (ASME Class 1)

• Liquid Penetrant Testing (PT) of weld fabricated under Work Order 109009003, half-coupling to 6 in. pipe, Emergency Core Cooling System (ECCS) (ASME Class 2)

The inspectors also reviewed documentation for the following NDE activities:

• Visual Inspection (VT-2) of reactor vessel bottom head interior and bottom mounted instrumentation performed in the Unit 1 2009 refueling outage (augmented ISI exam per Code Case N-722)

• VT-2 of reactor vessel closure head interior surface, exterior surface, and control rod drive mechanisms (augmented ISI exam per Code Case N-729-1)

• VT-2 of ASME Class 1 pressure retaining bolting, Steam Generator and Pressurizer primary manways

• UT examination of Steam Generator upper shell barrel to transition cone weld

• UT examination of tube side shell to flange weld, Residual Heat Removal heat exchanger

• Magnetic particle testing (MT) of Pressurizer upper head to 6 in. safety nozzle weld

• UT examination of Cold Leg safety injection line in RCS Intermediate Leg loop drain line (augmented ISI exam for thermal fatigue)

With regard to the dispositions of relevant NDE indications since the last Unit 1 outage, the licensee did not identify any NDE indications that were analytically evaluated for accepted continued service.

The inspectors review of welding activities specifically covered the welding sample listed below in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed work orders, repair and replacement plans, weld data sheets, welding procedures, procedure qualification records, welder qualification records, and NDE reports.

• Direct observation of in-process welding and review of welding package for a half-coupling to 6 in. ECCS pipe weld, Work Order 109009003 (ASME Class 2)

• Welding package for seal weld on a valve bonnet (Work Order 1081437401)

b. Findings

Introduction:

The NRC identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, for the licensees failure to conduct a visual examination of the Units 1 and 2 containment metallic liners in the area of the reactor cavity underneath the reactor vessel.

Description:

10 CFR 50.55a, Codes and Standards, requires the licensee to follow the in-service inspection requirements in ASME Section XI. The Code of record for the current containment ISI Program interval at Vogtle Units 1 and 2 is the 2001 Edition with 2003 Addenda of ASME Section XI. In addition, the Code of record for the previous containment ISI Program interval was the 1992 Edition with 1992 Addenda of Section XI.

Subsection IWE, Table IWE-2500-1 of both editions of Section XI required a general visual inspection of 100 percent of the containment accessible surface areas during each inspection period. The containment metallic liner in the area of the reactor cavity underneath the reactor vessel is an accessible area within the scope of the general visual examination required by Subsection IWE.

The inspectors determined that the licensee had not inspected the containment liner in the area of reactor cavity underneath the reactor vessel since the beginning of the containment ISI program in 1998. The inspectors also noted that previous operating experience information existed in NRC Information Notices (IN) 2004-09, Corrosion of Steel Containment and Containment Liner, and IN 2010-12, Containment Liner Corrosion, relating to material degradation issues of reactor containment building structures. The inspectors determined that this OE was not utilized to ensure adequate procedures were performed to address the necessary inspections. The inspectors identified that licensee procedure 84303-C, Containment Liner General Visual Examination, Revision 2.0, did not include the reactor cavity area as part of the checklist of areas to be inspected by general visual examination inside the containment.

The licensee initiated Condition Report (CR) 2011104688 to address the issue through the CAP and conducted the required general visual inspection in Unit 1 containment and found no pitting or cracking in the area examined. In addition, the licensee performed UT thickness measurements in affected areas of the metallic liner to evaluate the liner thickness against the design criteria. The visual and UT examinations indicated that the containment metallic liner was acceptable for continuous operation in accordance with the applicable acceptance criteria in ASME Section XI. The licensee developed a plan to recoat the affected area during the upcoming Unit 1 outage and perform a similar visual inspection in the Unit 2 containment during the next refueling outage.

Analysis:

The failure to conduct a general visual examination of 100 percent of the accessible surface areas in the reactor cavity area underneath the reactor vessel in accordance with the ASME BPVC,Section XI, Subsection IWE was a performance deficiency. The finding was more than minor because it was associated with the Design Control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, visual inspections of the containment metallic liner provide assurance that the liner remains capable of performing its intended safety function. The inspectors used Inspection Manual Chapter 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding was of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment.

This finding has a cross-cutting aspect in the operating experience (OE) component of the area of problem identification and resolution because OE was not implemented and institutionalized through station procedures. P.2.b]

Enforcement:

10 CFR Part 50.55a, Codes and Standards, states in part, that the examination of metallic liners in concrete containments shall satisfy the requirements of ASME Section XI, Subsection IWE of the 1992 Edition with the 1992 Addenda or the 1998 Edition through the latest edition and addenda incorporated by reference in paragraph 10CFR50.55a(b)(2). The 1992 Edition with the 1992 Addenda of ASME Section XI, Subsection IWE; as well as the 2001 edition with 2003 addenda required a general visual examination of 100 percent of the accessible surface areas in concrete containments.

Contrary to the above, from 1998 to 2011, the licensee failed to perform a general visual examination of 100 percent of the containment metallic liner in the reactor cavity area underneath the reactor vessel, an accessible surface area inside the containment, in accordance with the applicable code of record for the first and second containment ISI Program intervals. The licensee took corrective actions to conduct the required visual examinations in Unit 1, including UT thickness measurements to evaluate the condition of the liner, and initiated action items to examine the same area in Unit 2 during the next refueling outage. Because this finding is of very low safety significance and has been entered into the licensees CAP as CR 2011104688, this violation is being treated as an NCV, consistent with the NRC Enforcement Policy: NCV 05000424, 425/2011002-01, Failure to Perform General Visual Examination of Containment Metallic Liner in Reactor Vessel Cavity underneath the Reactor Vessel.

.2 PWR Vessel Upper Head Penetration (VUHP) Inspection Activities

a. Inspection Scope

The licensee completed a direct visual examination of the bare-metal outer surface of the Unit 1 reactor vessel upper head in the 2008 refueling outage. The inspectors reviewed visual examination records to evaluate if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). Specifically, the inspectors evaluated if the required visual examination scope and coverage was achieved and limitations (if applicable) were recorded in accordance with the licensee procedures. The inspectors also evaluated if the licensees criteria for visual examination quality and instructions for resolving interference and masking issues were consistent with the regulatory requirements.

The licensee did not identify any indications that required weld repair in the vessel upper head penetrations since the beginning of the last Unit 1 outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control (BACC) Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walk-down inspections performed during the Unit 1 spring 2011 outage. The inspectors also interviewed the BACC program owner and conducted an independent walk-down of the reactor building to evaluate compliance with licensees BACC program requirements and verify that degraded or non-conforming conditions, such as boric acid leaks identified during the containment walk-down, were properly identified and corrected in accordance with the licensees BACC and CAP.

The inspectors reviewed a sample of engineering evaluations completed for evidence of boric acid found on systems containing borated water to verify that the minimum design code required section thickness had been maintained for the affected components. The inspectors selected the following evaluations for review:

• Evaluation No. 1204-2010-007, Evaluation performed on ECCS flow line, February 28, 2011

• Evaluation No. 1208-2011-001, Evaluation performed on single body to bonnet connection bolt, March 14, 2011

b. Findings

No findings were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The inspectors reviewed the Unit 1 eddy current (EC) examination activities in SGs 1, 2, 3, and 4 to evaluate the inspection activities against the licensees Technical Specifications (TS), NRC commitments, ASME Section XI, and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines. The inspectors reviewed the scope of the EC examinations to verify it included the applicable potential areas of tube degradation. The inspectors also verified that appropriate inspection scope expansion criteria were planned based on inspection results. Additionally, the inspectors reviewed EC examination status reports to ensure that all tubes with relevant indications were appropriately screened for in-situ pressure testing. Based on the EC examination results, no new degradation mechanisms were identified, no EC scope expansion was required, and none of the SG tubes examined met the criteria for in-situ pressure testing.

The inspectors reviewed the last Condition Monitoring and Operational Assessment report to assess the licensees prediction capability for maximum tube degradation. The inspectors review also included the licensees repair criteria and repair process to ensure they were consistent with plant TS and industry guidelines. This included direct observation of tube plugging activities in SGs 1 and 4. The inspectors also reviewed the primary to secondary leakage (e.g., SG tube leakage) history for the last operating cycle.

The inspectors noted that primary to secondary leakage was below the detection threshold during the previous operating cycle.

Additionally, the inspectors reviewed documentation to ensure that data analysts, EC probes, and equipment configurations were qualified to detect the existing and potential SG tube degradation mechanisms. The inspectors review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) to ensure that their qualification was consistent with Appendix H or I of the Electric Power Research Institute Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7. The inspectors also directly observed a sample of EC data acquisition in SGs 1 and 4 (Cold Leg and Hot Leg sides). Furthermore, the inspectors reviewed a sample of EC data with a qualified data analyst for the following tubes: SG 1 (R26C110, R57C45, R39C100, and R41C100); and SG 4 (R8C57 and R30C18). Finally, the inspectors reviewed the licensees corrective actions for indications (either from EC or secondary side visual inspections) of potential loose parts on the SG secondary side, including direct observation of Foreign Object Search and Retrieval (FOSAR) activities.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems, including welding, BACC, and SG ISI that were identified by the licensee and entered into the CAP as CRs. The inspectors reviewed the CRs to confirm that the licensee had appropriately described the scope of the problem and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant. The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the report Attachment.

b. Findings

No findings were identified

==1R11 Licensed Operator Requalification

a. Inspection Scope

==

Resident Quarterly Observation. The inspectors observed operator performance on February 14, during licensed operator simulator training described in simulator exercise guide V-RQ-SE-11101-1.0. The scenario observed consisted of a steam generator tube rupture followed by a failed code safety valve on the ruptured steam generator.

Documents reviewed are listed in the Attachment. The inspectors specifically assessed the following areas:

• Correct use of the abnormal and emergency operating procedures

• Ability to identify and implement appropriate actions in accordance with the requirements of the TS

• Clarity and formality of communications in accordance with procedure 10000-C, Conduct of Operations

• Proper control board manipulations including critical operator actions

• Quality of supervisory command and control

• Effectiveness of the post-evaluation critique

b. Findings

No findings were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

The inspectors reviewed the following two condition reports and applicable safety-significant systems to evaluate the effectiveness of the licensees handling of equipment performance problems and to verify the licensees maintenance efforts met the requirements of 10 CFR 50.65 (the Maintenance Rule) and licensee procedure 50028-C, Engineering Maintenance Rule Implementation. The reviews included adequacy of the licensees failure characterization, establishment of performance criteria or 50.65(a)(1)performance goals, and adequacy of corrective actions. Other documents reviewed during this inspection included control room logs, system health reports, the maintenance rule database, and maintenance work orders (WO). Also, the inspectors interviewed system engineers and the maintenance rule coordinator to assess the accuracy of identified performance deficiencies and extent of condition.

• CR 2010101780

• CR 2011101187

b. Findings

No findings were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

==

The inspectors reviewed the following five work activities to verify plant risk was properly assessed by the licensee prior to conducting the activities. The inspectors reviewed risk assessments and risk management controls implemented for these activities to verify they were completed in accordance with procedure 00354-C, Maintenance Scheduling, and 10 CFR 50.65(a)(4). The inspectors also reviewed the CR database to verify that maintenance risk assessment problems were being identified at the appropriate level, entered into the corrective action program, and appropriately resolved.

• Extending the Unit 2 train A EDG outage 3 days past the originally scheduled end date

• Maintenance outages on multiple Unit 1 train B NSCW tower fans

• Unit 2 A train solid state protection system (SSPS) salve time delay relay TD1 failure

• Unit 1 train B auxiliary feedwater system maintenance outage

• Week of March 7, 2011 Unit 1 hot mid-loop operations

b. Findings

No findings were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed the following five evaluations to verify they met the requirements of procedure NMP-GM-002, Corrective Action Program, and NMP-GM-002-001, Corrective Action Program Instructions. The scope of this inspection included a review of the technical adequacy of the evaluations, the adequacy of compensatory measures, and the impact on continued plant operation.

• CR 2011100022, EDG 2A has a jacket water leak on cylinder 2R

• CR 2011100576, On the 210 elevation near column 15, there is a leak from insulation surrounding AFW BFIV check valve 1-1302-U4-121

• CR 2011101080, Unit 2 B train sequencer processor failure

• CR 2011101977, Unit 2 A train SSPS slave relay TD1 failed to operate

• CR 2011102099 Top bolt in the number 7 right bank subcover support bracket on 1A EDG is sheared

b. Findings

No findings were identified.

==1R18 Plant Modifications

a. Inspection Scope

==

Temporary Modification. The inspectors reviewed temporary modification TM 1102377801 and associated 10CFR50.59 screening criteria against the system design bases documentation and procedure 00307-C, Temporary Modifications. The permanent magnet generator that provides power to the Unit 1 EHC cabinet failed. This temporary modification provides temporary 120v AC power to the Unit 1 EHC cabinet using power from a welding receptacle. The inspectors reviewed implementation, configuration control, post-installation test activities, drawing and procedure updates, and operator awareness for this temporary modification.

b. Findings

No findings were identified.

==1R19 Post-Maintenance Testing

a. Inspection Scope

==

The inspectors either observed post-maintenance testing or reviewed the test results for the following seven maintenance activities to verify that the testing met the requirements of procedure 29401-C, Work Order Functional Tests, for ensuring equipment operability and functional capability was restored. The inspectors also reviewed the test procedures to verify the acceptance criteria were sufficient to meet the TS operability requirements.

• Unit 2 A train EDG allowed outage time (AOT)

• Unit 1 A train NSCW tower fan #4 breaker maintenance

• Unit 2 B train EDG allowed outage time (AOT)

• Unit 1 B train NSCW tower fan #3 outage

• Unit 2 A train SSPS slave relay TD1

• Unit 2 B train sequencer processor failure

• Unit 1 B train RHR maintenance outage

b. Findings

No findings were identified.

==1R20 Refueling and Other Outage Activities

a. Inspection Scope

==

The inspectors performed the inspection activities described below for the Unit 2 refueling outage that began on March 06, 2011. The inspectors confirmed when the licensee removed equipment from service, the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TS and that configuration changes due to emergent work and unexpected conditions were controlled in accordance with the outage risk control plan. Documents reviewed are listed in the Attachment. Inspection activities included:

• Prior to the outage, the resident inspectors reviewed the licensees integrated risk control plan to verify that activities, systems, and/or components which could cause unexpected reactivity changes were identified in the outage risk plan.

• Observed portions of the plant shutdown and cooldown to verify that the TS cooldown restrictions were followed.

• Reviewed reactor coolant system pressure, level, and temperature instruments to verify that the instruments provided accurate indication and that allowances were made for instrumentation errors.

• Verified that outage work did not impact the operation of the spent fuel cooling system.

• Reviewed the status and configuration of electrical systems to verify that those systems met TS requirements and the licensees outage risk control plan.

• Observed decay heat removal parameters to verify that the system was properly functioning and providing cooling to the core, specifically during hot mid-loop operations.

• Reviewed system alignments to verify that the flow paths, configurations and alternative means for inventory addition were consistent with the outage risk plan.

• Reviewed selected control room operations to verify that the licensee was controlling reactivity in accordance with the TS.

• Observed the licensees control of containment penetrations to verify that the requirements of the TS were met.

• Reviewed the licensees plans for changing plant configuration to verify that TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites were met prior to changing plant configuration.

• Observed refueling activities for compliance with TS, to verify proper tracking of fuel assemblies from the spent fuel pool to the core, and to verify foreign material exclusion was maintained.

b. Findings

No findings were identified.

==1R22 Surveillance Testing

a. Inspection Scope

==

The inspectors reviewed the following seven surveillance test procedures and either observed the testing or reviewed test results to verify that testing was conducted in accordance with the procedures and that the acceptance criteria adequately demonstrated that the equipment was operable. Additionally, the inspectors reviewed the CR database to verify that the licensee had adequately identified and implemented appropriate corrective actions for surveillance test problems.

Surveillance Tests

• 24812-2 Rev 32.2, Delta T/Tavg Loop 3 Protection Channel III 2T 431 Channel Operational Test and Channel Calibration

• 24806-1 Rev. 22, Refueling Water Storage Tank Level 1L-990 Channel Calibration Test and Channel Calibration

• 14545B-2 Rev. 1, Motor Driven Auxiliary Feedwater Pump B Operability Test

• 24995-1 Rev.16, Nuclear Instrumentation System (NIS) Source/Intermediate Range Channel 1RE-13135A (1N31/1N35) Channel Calibration In-Service Tests (IST)

• 14802B-1 Rev 4, Train B NSCW Pump/Check Valve IST and Response Time Test

• 14808B-2 Rev. 2.1, Train B Centrifugal Charging Pump and Check Valve IST and Response Time Test Containment Isolation Valve (CIV)

• 14378-1 Rev. 8.1, Containment Penetration No. 78 Containment Sump Pumps Discharge Local Leak Rate Test

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors reviewed the facility activation exercise guide and observed the following emergency response activity to verify the licensee was properly classifying emergency events, making the required notifications, and making appropriate protective action recommendations in accordance with procedures 91001-C, Emergency Classifications, and 91305-C, Protective Action Guidelines.

• On February 22, the licensee conducted an emergency preparedness drill involving an earthquake, subsequent Unit 1 reactor trip, followed by a loss of all AC electrical power due to a loss of both reserve auxiliary transformers. The technical support center, emergency operations facility and operations support center were activated and the site participated in the exercise.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

Event and Effluent Program Reviews The inspectors reviewed the 2008 and 2009 Annual Radiological Effluent Release Report (ARERR) documents for consistency with requirements in the Offsite Dose Calculation Manual (ODCM) and TS. The inspectors reviewed and discussed a proposed change to the ODCM. Routine and abnormal effluent release results and reports, as applicable, were reviewed and discussed with responsible licensee representatives. Status of the radioactive gaseous and liquid effluent processing and monitoring equipment, and applicable equipment changes, as described in the Updated Final Safety Analysis Report (UFSAR) and current ODCM were discussed with responsible staff.

Equipment Walk downs The inspectors walked-down and discussed selected components of gaseous processing systems, and selected Unit 1 (U1) and Unit 2 (U2)liquid waste processing and discharge systems to ascertain material condition, configuration and alignment. To the extent practical, the inspectors observed and evaluated the material condition of in-place liquid waste processing equipment for indications of degradation or leakage that could constitute a possible release pathway to the environment. The walk-downs were accompanied by Radiation Protection personnel and included discussion and evaluation of observed leaks, degraded material condition, status of in-place plant work order tags, and configuration control associated with the waste monitor tanks and pumps, laundry tank, gas decay tanks, and associated piping and valves. The inspectors observed that there was ongoing work on the heat tracing on the unit vent monitor sampling lines and discussed the operability of the particulate and iodine monitors with plant personnel.

Effluent Processing The inspectors discussed ongoing processing of a waste monitoring tank and plans to close out release permit and start another release on a different tank with Chemistry and Operations personnel. The reviews included review and discussion of selected dose calculation summaries. Release quantities and dose impacts were reviewed and discussed. The inspectors reviewed 10 CFR 61 analysis data for expected nuclide distributions used to quantify effluents, treatment of hard to detect nuclides, and determination of appropriate calibration nuclides for effluent analysis instruments. The inspectors followed up on an unplanned but monitored release from a Waste Gas Decay tank. The inspectors reviewed the calculated public dose results for any indications of higher than anticipated or abnormal releases.

Ground Water Protection The inspectors reviewed the current groundwater sample results. The inspectors discussed changes in the groundwater program that have resulted from the ongoing Unit 3 and 4 construction efforts to include the loss of a few sampling points and the creation of additional points to compensate. The groundwater program was discussed with both Chemistry and Radiation Protection representatives as well as a corporate representative.

Problem Identification and Resolution The inspectors reviewed selected CAP Condition Report (CR) documents in the areas of gaseous and liquid effluent processing and release activities. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure NMP-GM-002, Corrective Action Program, Rev. 11. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

Effluent process and monitoring activities were evaluated against details and requirements documented in UFSAR Sections 11 and 12; ODCM; 10 CFR Part 20; Appendix I to 10 CFR Part 50; and approved licensee procedures. In addition, ODCM and UFSAR changes since the last onsite inspection were reviewed against the guidance in NUREG-1301 and Regulatory Guide (RG) 1.109, RG 1.21, and RG 4.1.

Records reviewed are listed in Sections 2RS6 and 2RS7.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program (REMP)

a. Inspection Scope

REMP Status and Results The inspectors reviewed and discussed changes to the ODCM and results presented in the Annual Environmental Radiological Environmental Operating Report (AREOR) documents issued for 2008 and 2009. The REMP contract laboratory (Georgia Power Environmental Laboratory) cross-check program results, and current procedural guidance for offsite collection, processing and analysis of airborne particulate and iodine, broadleaf vegetation, and surface water samples were reviewed and discussed. The AREOR environmental measurement results were reviewed for consistency with licensee effluent data and evaluated for radionuclide concentration trends. The inspectors reviewed and discussed detection level sensitivity requirements and results for selected environmental media analyzed by the offsite environmental laboratory.

Equipment Walk-down The inspectors observed and discussed implementation of selected REMP monitoring and sample collection activities for atmospheric, broadleaf vegetation samples, and water and milk samples as specified in the current ODCM and applicable procedures. The inspectors observed equipment material condition and verified operability, including verification of flow rates and total sample volume results for the weekly airborne particulate filter and iodine cartridge change-outs at six atmospheric sampling stations. In addition, the inspectors discussed broadleaf vegetation sampling for selected stations. Select surface water locations were verified and sample collection discussed. Thermo-luminescent dosimeter material condition and placement were verified by direct verification at select ODCM locations. Land use census results, actions for missed samples including compensatory measures, sediment sample collection/processing activities, and availability of replacement equipment were discussed with environmental technicians and knowledgeable licensee staff. In addition, sample pump calibration and maintenance records for selected environmental air samplers were reviewed.

Meteorological Monitoring Program The inspectors conducted a tour of the meteorological tower and observed local data collection equipment readouts. The inspectors observed the physical condition of the tower and associated instruments and discussed equipment operability, maintenance history, and backup power supplies with responsible licensee staff. The inspectors evaluated transmission of locally generated meteorological data from the meteorological tower to the main control room operators.

For the meteorological measurements of wind speed, wind direction, and temperature, the inspectors reviewed applicable tower instrumentation calibration records and evaluated meteorological measurement data recovery for 2008 and 2009.

Problem Identification and Resolution The inspectors reviewed selected CAP CR documents in the areas of environmental and meteorological monitoring. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with NMP-GM-002, Corrective Action Program, Rev. 11 and NMP-GM-002-001, Corrective Action Program Instructions, Rev. 20.

Procedural guidance, program implementation, quantitative analysis sensitivities, and environmental monitoring results were reviewed against 10 CFR Part 20; Appendix I to 10 CFR Part 50; TS Sections 5.4, 5.5, and 5.6; ODCM, Rev. 27; RG 4.15, Quality Assurance for Radiological Monitoring Programs (Normal Operation) - Effluent Streams and the Environment; and the Branch Technical Position, An Acceptable Radiological Environmental Monitoring Program - 1979. Licensee procedures and activities related to meteorological monitoring were evaluated against: ODCM; UFSAR Section 2; RG 1.23, Meteorological Monitoring Programs For Nuclear Power Plants, and ANSI/ANS-2.5-1984, Standard for Determining Meteorological Information at Nuclear Power Sites.

Documents reviewed are listed in Section 2RS07 of the Attachment.

b. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation

a. Inspection Scope

Waste Processing and Characterization During inspector walk-downs, accessible sections of the liquid and solid radioactive waste (radwaste) processing systems were assessed for material condition and conformance with system design diagrams.

Inspected equipment included radwaste storage tanks, resin transfer piping, resin and filter packaging components, and abandoned processing equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee staff.

The 2009 AREOR and radionuclide characterizations from 2009 - 2010 for each major waste stream were reviewed and discussed with radwaste staff. For primary resin and Dry Active Waste (DAW) the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream mixing and concentration averaging methodology for resin waste streams was evaluated and discussed with radwaste staff. The inspectors also reviewed the licensees procedural guidance for monitoring changes in waste stream isotopic mixtures.

Radioactive Material Storage During walk-downs of indoor and outdoor radioactive material storage areas, the inspectors observed the physical condition and labeling of storage containers and the posting of Radioactive Material Areas. The inspectors also reviewed licensee procedural guidance for storage and monitoring of radioactive material.

Transportation Selected shipping records were reviewed for consistency with licensee procedures and compliance with NRC and Department of Transportation (DOT)regulations. The inspectors reviewed emergency response information, DOT shipping package classification, waste classification, radiation survey results, and evaluated whether receiving licensees were authorized to accept the packages. Licensee procedures for opening and closing Type A shipping casks were compared to manufacturer requirements. In addition, training records for selected individuals currently qualified to ship radioactive material were reviewed. The inspectors were unable observe shipment preparation activities due to a lack of outgoing shipments during the week of inspection.

Problem Identification and Resolution The inspectors reviewed CRs in the area of radwaste/shipping. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure NMP-GM-002, Corrective Action Program, version 11.0. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radwaste processing, radioactive material handling, and transportation activities were reviewed against the requirements contained in the licensees Process Control Program, UFSAR Chapter 11, 10 CFR Part 20, 10 CFR Part 61, 10 CFR Part 71, and 49 CFR Parts 172-178. Licensee activities were also evaluated against guidance provided in the Branch Technical Position on Waste Classification (1983) and NUREG-1608.

Documents reviewed during the inspection are listed in Section 2RS8 of the report

.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

.1 Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors sampled licensee submittals for the listed PIs during the period from January 1, 2010, through December 31, 2010, for Unit 1 and Unit 2. The inspectors verified the licensees basis in reporting each data element using the PI definitions and guidance contained in procedure 00163-C, NRC Performance Indicator and Monthly Operating Report Preparation and Submittal, and Nuclear Energy Institute document NEI 99-02, Regulatory Assessment Indicator Guideline.

• Unplanned Scrams per 7,000 Critical Hours

• Unplanned Scrams with Complications

• Unplanned Power Changes per 7,000 Critical Hours The inspectors reviewed Unit 1 and Unit 2 operator log entries, the Vogtle Electric Generating Plant Unit 1 and Unit 2 NRC Mitigating System Performance Index Basis Document, the monthly operating reports and monthly PI summary reports to verify that the licensee had accurately submitted the PI data.

b. Findings

No findings were identified.

.2 Public Radiation Safety Cornerstone

a. Inspection Scope

The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from January 1, 2010, through December 31, 2010. For the assessment period, the inspectors reviewed cumulative and projected doses to the public and CR documents related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues. The inspectors also reviewed licensee training and performance results of associated junior and senior HPT actions for evaluating the release of potentially contaminated material from onsite radiologically controlled area (RCA) locations. Documents reviewed are listed in section 4OA1 of the Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Condition Report Review. As required by Inspection Procedure 71152,

Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. This review was accomplished by either attending daily screening meetings that briefly discussed major CRs, or accessing the licensees computerized corrective action database and reviewing each CR that was initiated.

.2 Focused Review

a. Inspection Scope

The inspectors performed a detailed review of the following CR which addresses the failure of the Unit 2 B train NSCW tower fan #3 due to high vibration. The goal of the review was to verify that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors evaluated the CR against the licensee?s corrective action program as delineated in licensee procedure NMP-GM-002, Corrective Action Program, and 10 CFR 50, Appendix B. Documents reviewed are listed in the Attachment.

• CR 2011104185

b. Findings and Observations

No findings were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report 05000424/2010-001: Breaker Failure Results in 1B

Train Containment Cooling System Being Declared Inoperable On October 24, 2010, the licensee attempted to manually start Containment Cooling Unit

1. 8 in low speed during the performance of a Containment Cooling System Operability and Response Time Test and the cooling unit did not start. Work Order (WO)1102198301 investigation identified that the circuit breaker had two breaker cover mounting holes that were cracked. This allowed the top right hand side screw to come in contact with the breakers closing mechanism, thus preventing the breaker from closing. The inspectors reviewed the LER, the associated condition report and apparent cause determination, and subsequent action items. The enforcement aspects associated with this event were documented in NRC integrated inspection report 05000424,425/2010005 Section 4OA2. No other findings were identified. This LER is closed.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

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

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

b. Findings and Observations

No findings were identified.

.2 (Closed) URI 05000424,425/2010005-02: Depressurization of Main Firewater Header

a. Inspection Scope

The inspectors performed a detailed review of CR 2010113782 which addressed the inadvertent depressurization of the main firewater header. The goal of the review was to verify that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized.

b. Findings and Observations

Introduction:

A self-revealing, Green NCV of Vogtle Unit 1 operating license condition 2.G. and Vogtle Unit 2 operating license condition 2.G. was identified for failure to maintain the main firewater header pressurized. Specifically, in response to two firewater header low pressure alarms, operations personnel failed to perform the steps listed the alarm response procedure. This led to the inadvertent depressurization of the main firewater header. For a period of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> and 21 minutes, the facility lost all automatic sprinkler system and manual hose station capability. If there had been an automatic actuation of the sprinkler system or a demand from any of the hose stations in the facility during that time period, there would have been no water available for fire suppression.

Description:

At 0339 on November 1, 2010, both of the diesel firewater pumps and the north jockey pump were placed out of service and danger tagged to permit replacement of the relief valves on the diesel-driven pumps. As part of the tagout, the remote indicator in the control room for fire header pressure was also removed from service.

The licensee entered the appropriate 7-day fire protection LCO action statement at that time. When the operators secured the north jockey pump for the tagout, they incorrectly assumed that the south jockey pump was in operation. In reality, the south jockey pump was also not operating and its hand switch was in the off position. This was in accordance with the governing procedure as the facility only requires one of the two jockey pumps to maintain 120 psig in the firewater header. As pressure in the firewater header began to decrease, the motor-driven firewater pump failed to start automatically at 100 psig. It was later discovered that the auto-start pressure switch had failed on demand. Also as pressure decreased, two independent firewater header low pressure alarms were received in the control room. The operators incorrectly assumed that the alarms were due to the tagout of the diesel-driven pumps and therefore did not perform the actions listed in the alarm response procedure.

At approximately 1700 on November 1, a third party inspector, who was inspecting the fire protection system as part of an assistance team, noticed that several of the local firewater header pressure gauges were reading very low. He brought this fact to the attention of a system operator who immediately contacted the control room. The shift supervisor immediately dispatched an operator to the south firewater station, where he reported that the firewater header was depressurized, and neither the south jockey pump nor the motor-driven firewater pump were running. The shift supervisor directed that the operator start the jockey pump, and within a few minutes system pressure was restored. Several minutes after that, the shift supervisor directed that the motor-driven firewater pump be started manually to verify functionality. The motor-driven firewater pump was started and ran for several minutes while maintenance personnel tried to determine why the pump had failed to automatically start at 100 psig.

Maintenance personnel discovered that the motor-driven firewater pump did not start due to a failed pressure switch. With all three firewater pumps inoperable, the licensee immediately entered the appropriate 24-hour fire protection shutdown LCO action statement. Within a few hours, one of the diesel-driven firewater pumps was restored and declared operable, and the shutdown LCO action statement was exited.

Analysis:

The failure of the licensee to properly respond to a firewater header low pressure alarms led directly to the depressurization of the main firewater header, and is considered a performance deficiency. The performance deficiency is considered more than minor because it is associated with the external events attribute and it adversely affected the objective of the Mitigating Systems cornerstone. Specifically, the performance deficiency adversely affected the protection against external events (fire)attribute of the Mitigating Systems cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences.

In accordance with IMC 0609.04, Phase 1 - Initial Screening and Characterization of Findings, this violation was assessed using the Phase 1 screening worksheets of IMC 0609, Appendix F. The results of the Phase 1 worksheets indicated that the CDF was greater than 1E-6, which indicated that a Phase 2 worksheet was required. The Phase 2 screening worksheet indicated that the violation was potentially greater-than-green (

CDF was greater than 1E-6), and the violation was forwarded to a Region II Senior Reactor Analyst (SRA) for a Phase 3 evaluation.

The regional SRA performed an evaluation under the Phase 3 protocol of the Significance Determination Process. This evaluation concluded that the violation was of very low safety significance (Green). The major assumptions of the evaluation included:

• an exposure time of less than fourteen hours

• the cables within the facility were thermo-set

• one train of safe shutdown equipment was free of fire damage for any compartment within the Auxiliary Building (excluding the Main Control Room and Cable Spread Rooms)

• there were no critical operator manual actions for fires in the Auxiliary Building compartments (excluding the Main Control Room and Cable Spread Rooms)

• all water suppression actions fail, due to the performance deficiency The dominant accident sequence was an unsuppressed electrical cabinet fire in the Auxiliary Building which induced a loss of offsite power. One emergency diesel generator failed to run and the other one was out of service for maintenance. Recovery actions for the emergency diesel generators and offsite power were unsuccessful and core damage ensued.

The inspectors determined that the cause of this finding was related to the Decision-Making component of the Human Performance cross-cutting area due to operators using non-conservative assumptions in their decision making. H.1(a)

Enforcement:

Vogtle Unit 1 operating license condition 2.G. and Vogtle Unit 2 operating license condition 2.G. requires the licensee to implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report (FSAR). Section 9.5.1.2.2 - Fire Protection (Active Systems) of the Vogtle FSAR requires the fire protection water system be kept continuously full and pressurized.

Contrary to the above operating license conditions, on November 1, 2010, the licensee inadvertently allowed the fire water header to be depressurized for a period of 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> and 21 minutes. If there had been an automatic actuation of the sprinkler system or a demand from any of the manual hose stations in the facility during that time period, there would have been no water available for fire suppression. Once the licensee became aware of the system depressurization, the shift supervisor directed an operator to start the available jockey pump, and within a few minutes system pressure was restored. The licensee then entered the appropriate 24-hour fire protection shutdown LCO action statement and remained there until operability of one diesel-driven firewater pump was restored a few hours later.

Because this violation was of very low safety significance and it was entered into the licensees corrective action program (ref. CR 2010113782), this violation is being treated as an NCV, consistent with the NRC Enforcement Policy. This finding is identified as NCV 05000424, 425/2011002-02, Depressurization of Main Firewater Header.

4OA6 Meetings, Including Exit

.1 Exit Meeting

On April 22, 2011, the resident inspectors presented the inspection results to you and other members of your staff, who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

4OA7 Licensee Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a NCV.

• Technical Specifications LCO 3.0.2 requires that Upon discovery of a failure to meet an LCO, the Required Actions of the associated Conditions shall be met, except as provided in LCO 3.0.5 and LCO 3.0.6. LCO 3.5.4 requires the RWST to be operable. On at least six occasions in the past 12 months, the licensee failed to enter LCO 3.5.4 condition B while performing testing that made the RWST sludge mixing pump isolation valves inoperable. The finding was determined to be of very low safety significance (Green) because the events did not represent in an actual loss of safety function of a single train for greater than its Technical Specification allowed outage time. The licensee has documented this event in their corrective action program (CR 2011100919), conducted a basic cause determination, and developed applicable corrective actions (AI 2011201473).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

R. Brigdon, Training and Emergency Preparedness Manager

C. Buck, Chemistry Manager

J. Churchwell, ISI Coordinator

D. Puckett, Performance Analysis Supervisor

R. Dedrickson, Plant Manager

K. Dyar, Security Manager

E. Groves, BACP Coordinator

M. Hickox, Licensing Engineer

I. Kochery, Health Physics Manager

D. McCary, Operations Manager

L. Mansfield, Site Engineering Director

S. Swanson, Site Support Manager

S. Stegall, SG Engineer

T. Smith, Lead Eddy Current Level III

T. Tynan, Site Vice-President

NRC personnel

S. Shaeffer, Chief, Region II Reactor Projects Branch 2

LIST OF ITEMS

OPENED AND CLOSED OPEN AND CLOSED

05000424, 425/2011002-01 NCV Failure to Perform General Visual Examination of Containment Metallic Liner in Reactor Vessel Cavity underneath the Reactor Vessel (Section 1R08)

05000424, 425/2011002-02 NCV Depressurization of Main Firewater Header (Section 4OA5.2)

CLOSED

05000424,425/2010005-02 URI Depressurization of Main Firewater Header (Section 4OA5.2)

05000424/2010-001 LER Breaker Failure Results in 1B Train Containment Cooling System Being Declared Inoperable (Section 4OA3.1)