IR 05000424/2010003

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IR 05000424-10-003, 05000425-10-003, on 04/01/2010 - 06/30/2010, Vogtle Electric Generating Plant, Units 1 and 2, Inservice Inspection Activities, Plant Modifications, Event Follow-up
ML102100182
Person / Time
Site: Vogtle  
Issue date: 07/29/2010
From: Scott Shaeffer
NRC/RGN-II/DRP/RPB2
To: Tynan T
Southern Nuclear Operating Co
References
IR-10-003
Download: ML102100182 (40)
v • d • e


Text

July 29, 2010

SUBJECT:

VOGTLE ELECTRIC GENERATING PLANT-NRC INTEGRATED INSPECTION REPORT 05000424/2010003 AND 05000425/2010003

Dear Mr. Tynan:

On June 30, 2010, 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 July 20, 2010, with Mr. R.

Dedrickson 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 self-revealing finding and one NRC identified finding which were determined to be of very low safety significance and were determined to be a violation of regulatory requirements. In addition, two licensee-identified violations, which were determined to be of very low safety significance, are 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 Section VI.A.1 of the NRCs 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.

SNC

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

Enclosure:

Inspection Report 05000424/2010003 and 05000425/2010003 w/Attachment: Supplemental Information

REGION II==

Docket Nos.:

50-424, 50-425

License Nos.:

NPF-68, NPF-81

Report Nos.:

05000424/2010003 and 05000425/2010003

Licensee:

Southern Nuclear Operating Company, Inc. (SNC)

Facility:

Vogtle Electric Generating Plant, Units 1 and 2

Location:

Waynesboro, GA 30830

Dates:

April 1, 2010 through June 30, 2010

Inspectors:

M. Cain, Senior Resident Inspector

T. Chandler, Resident Inspector

R. Chou, Senior Reactor Inspector (Section 1R08)

B. Collins, Reactor Inspector (Section 1R08.4OA5)

Approved by:

Scott Shaeffer, Chief Reactor Projects Branch 2 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000424/2010-003, 05000425/2010-003; 04/01/2010 - 06/30/2010; Vogtle Electric

Generating Plant, Units 1 and 2; Inservice Inspection Activities, Plant Modifications,

Event Follow-up

The report covered a three-month period of inspection by two resident inspectors, a senior reactor inspector and a reactor inspector. One self-revealing and one NRC identified Green NCV were identified. The significance of most findings is indicated by their color (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: Initiating Events (IE)

Criterion V, Instructions, Procedures, and Drawings, was identified for failure to adhere to steam generator eddy current examination procedures during the 2007 Unit 2 refueling outage. As a result, a tube inspection was missed. The missed tube inspection was completed during a March 2010 inspection and was found to be without significant degradation. The licensee entered the issue into their corrective action program as CR 2010103680.

The inspectors determined that the finding was more than minor because it was associated with the human performance attribute of the Initiating Events cornerstone and affected the cornerstone objective of assuring that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Specifically, the failure to adhere to steam generator tube inspection procedures resulted in a missed tube inspection and affected the assurance that barrier integrity was maintained. The finding was determined to be of very low safety significance because subsequent testing of the missed tube in March 2010 did not indicate tube degradation. This finding was determined to not have a cross-cutting aspect associated with it due to the timeframe of the event and that the cause of the event is not indicative of current plant performance. (Section 1R08.4)

Cornerstone: Mitigating Systems

  • Green: A self revealing, non-cited violation of 10 CFR Part 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, was identified for failure to establish measures to assure that purchased material, equipment, and services conform to the procurement documents. More specifically that safety-related EMAX breaker closing coils were capable of performing their safety related function. All affected EMAX breaker closing coils were replaced with a qualified 90V closing coil capable of continuous duty cycle.

This finding is more than minor because if left uncorrected, the failure to establish measures to assure that purchased material, equipment, and services conform to procurement documents could become a more significant safety concern.

Additionally, it impacted the Reactor Safety Cornerstones of Mitigating Systems and Barrier Integrity in that, the failure to establish measures to assure that purchased material, equipment, and services conform to procurement documents to ensure that safety-related breakers are assembled and functionally tested correctly, impacted the design control and equipment performance (availability and reliability) attributes.

This finding was determined to be of very low safety significance (Green) because it did not result in a loss of operability or functionality. This finding was determined to not have a cross-cutting aspect associated with it due to the timeframe of the event and that the cause of the event is not indicative of current plant performance.

(Section 1R18)

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

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at essentially full rated thermal power (RTP) for the entire inspection period.

Unit 2 started the report period shutdown for a planned refueling outage. The unit was restarted on April 6 and attained full RTP power on April 11. Unit 2 operated at essentially full RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

a. Inspection Scope

Offsite/Alternate AC Readiness.==

The inspectors reviewed the licensees procedures to verify that communication protocols exist between the transmission system operator and the control room to promptly identify issues that could impact the offsite power system.

The inspectors also verified the adequacy of these procedures to address measures to monitor and maintain availability and reliability of both the offsite alternating current (AC)power system and the alternate AC power system. The inspectors also conducted walkdowns with appropriate plant personnel to verify material condition of offsite AC power systems and onsite alternate AC power systems to the plant including 500 KV and 230 KV switchyards and transformers. Documents reviewed are listed in the

.

Seasonal Readiness Review. The inspectors performed a walkdown of the following two systems to verify they would remain functional during high temperature conditions. The inspectors walked down the systems to determine component temperatures and interviewed engineers to ensure that the systems would be operable at the observed temperature. Additionally, the inspectors reviewed the CR database to verify that adverse weather related items were being identified and appropriately resolved.

Documents reviewed are listed in the Attachment.

  • Unit 2 main generator excitation system

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 B engineered safety features (ESF) chiller system during the Unit 2 train A ESF chiller maintenance outage
  • Unit 1 train B nuclear service cooling water (NSCW) system during the maintenance outage on train A NSCW pump #5

b. Findings

No findings were identified.

==1R05 Fire Protection

a. Inspection Scope

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 (LCO) 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 (UFSAR) section 9.5.1, Fire Protection Program, and Appendix 9A, Fire Hazards Analysis, were met. Documents reviewed are listed in the Attachment.

  • Unit 1 A & B train auxiliary component cooling water (ACCW) heat exchanger rooms
  • Unit 2 A & B train component cooling water (CCW) pump rooms
  • Unit 1 charging pump rooms and level C pipe penetration area
  • Unit 1 A & B train NSCW towers

b. Findings

No findings were identified.

==1R06 Flood Protection Measures

a. Inspection Scope

Internal Flood Review.==

The inspectors walked down the following areas which contained risk-significant structures, systems and components below flood level to verify flood barriers were in place. Motor controllers and terminal boxes that could become potentially submerged were inspected to ensure that the sealing gasket material was intact and undamaged. The inspectors reviewed selected licensee alarm response procedures to verify alarm setpoints and setpoints for sump pump operation were consistent with the UFSAR, the setpoint index, and Technical Specifications (TSs).

Underground Bunker/Manhole Cable Review. The inspectors verified the following underground cable bunkers/manholes installed cables were not submerged in water or qualified for existing environmental conditions. Inspectors also verified splices and cable support systems intact. Inspectors verified installed dewatering devices were operational and level alarm circuits set appropriately. In cases where no dewatering device was installed, inspectors determined if drainage was provided and functional.

  • Pull boxes 1NE7ADKEM39, 1NE7ADKEM40, and 1NE96HKEPB01

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08P

From March 15 to May 27, 2010, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, steam generator tubes, emergency feedwater systems, risk-significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, 1R08.4 and 1R08.5 below constituted one inservice inspection sample as defined in Inspection Procedure 71111.08.

.1 Piping Systems ISI

a. Inspection Scope

The inspectors evaluated the following non-destructive examinations mandated by the ASME Code Section XI to verify compliance with the ASME Code Section XI, and Section V requirements and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

  • Ultrasonic Testing (UT) of pipe-to-elbow weld (21204-023-18-RB), ASME Class 2, High Head Safety Injection (HHSI) system, 6 diameter, Category R-A-Direct Observation
  • UT of pipe-to-elbow weld (21204-030-45-RB), ASME Class 2, HHSI system, 4 diameter, Category R-A - Direct Observation
  • UT of pipe-to-elbow weld (21204-030-46-RB), ASME Class 2, HHSI system, 4 diameter, Category R-A - Direct Observation

The inspectors reviewed the following examination records (volumetric or surface) with recordable indications that were analytically evaluated and accepted for continued service against the ASME Code Section XI or an NRC-approved alternative.

  • UT on Upper Head-to-Upper Shell Barrel D Weld (21201-B6-001-W01)
  • UT on Upper Shell Barrel C-to-Transition Cone Weld (11201-B6-002-W03)

The inspectors reviewed documentation for the following pressure boundary welds completed for risk-significant systems during the outage to evaluate if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the construction Code. In addition, the inspectors reviewed the welding procedure specifications, welder qualifications, welding material certifications and supporting weld procedure qualification records to evaluate if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

Vent Piping

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the Unit 2 vessel head, a VT-2 visual examination was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors reviewed records of the visual examination conducted on the Unit 2 reactor vessel head 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 reviewed the following documentation and/or observed the following activities:

  • Evaluated if the required visual examination scope/coverage was achieved and limitations (if applicable) were recorded in accordance with the licensee procedures.
  • Evaluated if the licensees criteria for visual examination quality and instructions for resolving interference and masking issues were adequate.

The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage for Unit 2. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control (BACC)

a. Inspection Scope

The inspectors performed an independent walkdown of portions of the containment building, which recently received a licensee boric acid walkdown and evaluated if the licensees BACC visual examinations emphasized locations where boric acid leaks could cause degradation of safety-significant components. The inspectors reviewed the following licensee evaluations of reactor coolant system components with boric acid deposits to evaluate if degraded components were documented in the corrective action system. The inspectors also evaluated the corrective actions for any degraded reactor coolant system components against the component Construction Code.

  • 1208-2010-001 - Corrosion Assessment for Downstream Flange of 21208X4031

The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to evaluate if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

  • CR 2008109843 - Boron Residue around Valve 2-1205-HV-8701A with Brown Residue Noted
  • CR 2008110243 - Boron Residue around Manways of Accumulators 02 & 03 with Brown Residue Noted

b. Findings

No findings were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The NRC inspectors interviewed eddy current testing (ET) personnel including the licensee SG engineer, ET Level III, and ET Qualified Data Analyst (QDA), and vendor lead ET Level III and ET Technical Advisor; and reviewed documentation related to the SG ISI program. The following items were evaluated against the requirements of the ASME B&PV Code,Section XI; the Technical Specifications; and the guidance documents referenced in NEI 97-06, Steam Generator Program Guidelines, Revision 2:

  • Assessed whether assumed NDE flaw sizing accuracy was consistent with data from the EPRI examination technique specification sheets (ETSS) or other applicable performance demonstrations.
  • Reviewed ET data (including historical ET data) from: SG #2 - Row (R)5, Column (C)56, R1C1, R1C2, R13C56, R52C73, R3C67, R50C77, and R40C58; SG #3 - R1C112, R1C23, R2C2, R1C28, R9C6, R12C7, and R18C9; and SG #4 - R1C121.
  • Compared the numbers and sizes of SG tube flaws/degradation identified, against the licensees previous outage Operational Assessment predictions.
  • Reviewed the SG tube ET examination scope and expansion criteria.
  • Evaluated the licensees SG tube ET examination scope for potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to the licensees SG tubes.
  • Reviewed the licensees examination scope expansion plans and implementation when defects were identified.
  • Reviewed the licensees repair criteria and processes.
  • Evaluated ET equipment and techniques used by the licensee to acquire data from the SG tubes for site-validation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7.
  • Reviewed the licensees secondary side SG Foreign Object Search and Removal (FOSAR) activities.
  • Reviewed the licensees disposition of irretrievable foreign objects left within the secondary side of the steam generators.
  • Verified the licensee was complying with appropriate probe wear criteria during implementation of Generic Letter 95-05.
  • Reviewed equipment and data acquisition and analysis personnel certification and medical examination reports.

b. Findings

Introduction:

An NRC identified Green non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to adhere to steam generator eddy current examination procedures during a March 2007 Unit 2 refueling outage.

Description:

The inspectors reviewed the licensees eddy current testing results for Steam Generator 2 from the March 2010 outage. The licensee identified that March 2010 tube R1C2 results showed no flaw indications. This was inconsistent with a 2007 inspection result where a flaw was identified for R1C2 and classified as a DNG or Ding.

The licensee determined that tube R1C2 was encoded incorrectly in the computer during the inspection process in March 2007. After initially taking data on tube R1C2, operators had manually moved the bobbin probe to tube R1C1. However, the operators failed to update the tube location in the analysis computer. As a result, data from tube R1C1 was received under the label of R1C2.

The inspectors questioned the vendor technical advisor and Level III analyst about the missed tube and impact, and they replied that both sets of data for tubes R1C1 and R1C2 in the 2007 analysis were identical with no indications. Therefore, while a tube was missed due to an encoding issue, they did not identify procedural issues with the data acquisition and the analyses in 2007.

On further review of the March 2007 data, the inspectors noted that the first data taken for tube R1C2 reflected a clean tube. However, data taken a few minutes later labeled as R1C2, but actually from R1C1, reflected a tube with a noticeable flaw. The inspectors became concerned whether the operators and analysts appropriately evaluated these inconsistent results in 2007.

The inspectors reviewed test data from 1998 through 2010 for R1C2 and from 2004 to 2010 for tube R1C1. The inspectors also reviewed the licensees testing procedures.

The two procedures used for the data acquisition and data analysis in 2007 were MRS-GEN-1127, Guidelines for Steam Generator Eddy Current Data Quality Requirements, Revision 9 and MRS 2.4.2 GPC-37, Steam Generator Eddy Current Data Analysis Techniques for Vogtle Units 1 and 2, Revision 15.

The inspectors determined that the first and second data operators, primary and secondary analysts, and the resolution analyst did not adhere to the procedure requirements at several stages during the 2007 testing.

Section 7.5 of Procedure MRS-GEN-1127 stated that, if an operator manually encodes a row/column overriding the robot encodes, then operator must have a second operator verify the location. The inspectors noted that both primary and secondary operators failed to adequately verify that the correct encoding was reflected in the computer after the operator manually changed the bobbin location from R1C2 to R1C1.

Sections 5.1.1 of procedure MRS 2.4.2 GPC-37 stated, The Primary Analyst is responsible for reviewing and evaluating all recorded inspection data for reportable indications of degraded tubing and anomalies defined in this document. Section 5.2.1 stated, A Secondary Analyst is responsible for the same duties as the Primary Analyst.

The inspectors noted that the data from tube R1C2 indicated a clean tube, while the second data labeled as R1C2 (actually taken from tube R1C1) taken a few minutes later indicated a flaw classified as a DNG or ding. Because the recorded data difference was readily apparent and the discrepancy was not identified by the analysts, the inspectors determined that both analysts failed to adequately review all of the recorded data.

Section 5.5.4 of procedure MRS 2.4.2 GPC-37 stated, The Resolution Analyst shall ensure that all required history reviews are performed. All historical reviews require dual Resolution Analyst concurrence. Section 8.5.7 identified DNG - Ding as Category VII.

Section 7.6.7 stated, Category VII - Review indications, review history, supplemental sampling or engineering evaluation required. The inspectors determined that both resolution analysts failed to adequately review the historical data for tube R1C2 in 2007.

The first 2007 data run for R1C2 indicated a clean tube, while the second data run labeled as R1C2 indicated DNG. Furthermore, the data history revealed that no previous indication of DNG existed prior to 2007 for tube R1C2. These readily apparent discrepancies were not identified by the resolution analysts.

The inspectors noted that test personnel had three procedural opportunities in 2007 to identify the tube encode error. Both data acquisition operators failed to verify the tube number in the computer code, both data analysts failed to perform an adequate evaluation on the first data and compare all the data, and both resolution analysts failed to adequately review historical data particularly when DNG was identified by both analysts.

Analysis:

The inspectors determined that the failure of test personnel to adhere to test procedures in March 2007 was a performance deficiency warranting significance determination. The inspectors determined that the finding was more than minor because it was associated with the human performance attribute of the initiating events cornerstone and affected the cornerstone objective of assuring that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Specifically, the failure to adhere to steam generator tube inspection procedures resulted in a missed tube inspection and affected the assurance that barrier integrity was maintained.

The inspectors evaluated the risk of this finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of findings. Using Tables 1, 2, 3b, and 4a of Exhibit 1 of Attachment 0609.04, the finding was found to be of very low safety significance (Green) because tube R1C2 was inspected during a March 2010 inspection and was found to be without significant degradation.

A cross-cutting aspect was not assigned for this finding because the performance deficiency occurred in March 2007 and the licensee determined that no similar errors were identified in March 2010.

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, required, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Licensee procedures MRS-GEN-1127, Guidelines for Steam Generator Eddy Current Data Quality Requirements, Revision 9 and MRS 2.4.2 GPC-37, Steam Generator Eddy Current Data Analysis Techniques for Vogtle Units 1 and 2, Revision 15, contained instructions for steam generator tube testing, an activity affecting quality. MRS-GEN-1127 required personnel to verify tube location for manual encodes and MRS 2.4.2 GPC-37 required personnel to review all recorded data and historical data for tubes with DNG flaws. Contrary to the above, in March 2007, test personnel did not accomplish the Steam Generator 2 of Unit 2 inspection activity in accordance with these instructions, in that:

(1) personnel failed to verify the encoding of tube data for tube R1C2 and R1C1;
(2) failed to evaluate all recorded data when two discrepant sets of data were obtained for tube R1C2; and
(3) failed to evaluate the data history for tube R1C2 when DNG was identified.

As part of their corrective action, the licensee inspected and evaluated tube R1C2 in March 2010. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as CR 2010103680, this violation is being treated as a Non-Cited Violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000425/2010003-01, Failure to Inspect Tube R1C2 of Steam Generator 2 during the Steam Generator Eddy Current Examination in 2007.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI/SG related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if:

  • the licensee had established an appropriate threshold for identifying ISI/SG related problems;
  • the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and
  • the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate 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 Attachment.

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification Program

a. Inspection Scope

==

Resident Quarterly Observation. The inspectors observed operator performance on April 12, during licensed operator simulator training described on simulator exercise guide V-RQ-SE-08205, Dynamic Simulator Scenarios. The simulator scenarios covered operator actions resulting from a rapid power reduction due to high vibrations on the A train main feedwater pump turbine and a loss of class 1E 125V DC power. 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 Technical Specifications
  • 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 safety-significant systems to verify that 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.

Documents reviewed are listed in the Attachment. Also, the inspectors interviewed system engineers and the maintenance rule coordinator to assess the accuracy of identified deficiencies and extent of condition.

  • Unit 1&2 NSCW systems
  • Unit 2 CS system

b. Findings

No findings were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Control

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.

  • Unit 1 reserve auxiliary transformer (RAT) outage while performing surveillance in-service tests (ISTs) on the 1A motor-driven auxiliary feedwater (MDAFW) pump
  • Unit 1 NSCW pump #4 outage while performing surveillance on the containment air coolers
  • Unit 1 train B ESF room cooler while performing maintenance on NSCW pump #4

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 2010104649, loop 4 main feedwater isolation valve (MFIV) has dual indication
  • CR 2010104786, loose parts remaining at the top of tubesheets in the steam generators after 2R14
  • CR 2010105015, potential gas binding issue
  • CR 2010105594, Unit 2 CCW pump #4 inboard bearing oil sample contained ferrous wear products
  • CR 2010106730, diesel fire pump #1 does not meet acceptance criteria

b. Findings

No findings were identified.

==1R18 Plant Modifications

a. Inspection Scope

Temporary Modifications.==

The inspectors reviewed temporary modification TM-2100655701 and associated 10CFR50.59 screening criteria against the system design bases documentation and procedure 00307-C, Temporary Modifications. This temporary modification secured the wet annular burnable assembly (WABA) handling tool, in its extended position with a WABA assembly retracted in its cage, on the west wall of the Unit 2 spent fuel pool. The temporary modification allowed the full weight of the WABA handling tool to rest on top of a fuel rack insert with several strands of No.9 wire wrapped around the tool to prevent lateral movement. The inspectors reviewed the implementation, engineering justification, and operator awareness for this temporary modification.

Permanent Modifications. The inspectors reviewed design change package (DCP)2060337001, 2R14 480V Breaker & 4160/480V Transformer Replacement, against the system design bases documentation. This DCP allowed for the replacement GE AKR style breakers with ABB EMAX series style breakers. The inspectors reviewed the design change package to verify that the modification did not degrade the system design bases, licensing bases, or equipment performance capability. Additionally, the inspectors verified that plant risk was not increased unnecessarily during implementation of the modification.

b. Findings

Introduction:

A self revealing, Green NCV of 10 CFR Part 50, Appendix B, Criterion VII, Control of Purchased Material, Equipment, and Services, was identified for failing to establish measures to assure that purchased material, equipment, and services conform to procurement documents to ensure that safety-related electrical breakers were capable of performing their safety related function. More specifically, that safety-related EMAX breaker closing coils were capable of performing their safety related function. This resulted in the failure of 2BB16-13, Unit 2 B train NSCW fan #3, breaker closing coil and associated control power fuse.

Description:

To address aging and obsolescence issues with GE AKR 480V circuit breakers, the licensee had been routinely replacing them with ABB EMAX series 480V circuit breakers in accordance with DCP 2060337001. The ABB EMAX breakers were designed and procured under SNC specification X3AC02B and Purchase Order (PO)70638400000. During the initial design phase of the project, discussions had taken place between the licensee, its contracted design engineering firm, Bechtel, and the breaker vendor, ABB, concerning the use of a standard 90V closing coil or a special low impedance 70V closing coil. Documentation indicated that the 70V closing coil was not suitable for existing plant design and that the 90V standard closing coil would be required to meet section 3.3.7 of the specification document. Section 3.3.7 of the design specification states, closing relays shall be capable of operation with either momentary or maintain-type contacts. Final design documentation, i.e. electrical characteristic data sheet and vendor manual, delivered from ABB via Bechtel to SNC indicated that the 70V closing coil would be used in the final design. This anomaly was not captured during the design review process and subsequent functional testing of the breaker final design.

On November 15, 2009, while in Mode 1, 2BB16-13 breaker red running indicator light was discovered extinguished during a routine main control board walk-down. The breaker was found closed and energized with its charging springs charged.

Subsequent investigation revealed a failed (shorted) breaker closing coil and a blown 6A control power fuse. This failure occurred approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after initial installation and functional testing per DCP 2060337021. Previously installed EMAX circuit breakers had been in operation for up to two years without a failure of the closing coil. The licensees immediate corrective action was to replace the failed breaker and fuse with a new one from stock. The licensee then sent the failed closing coil to ABB for failure analysis.

On January 19, 2010, the licensee received notification from ABB stating their intentions to issue a 10CFR Part 21notification concerning the EMAX breakers. ABB identified that the breaker closing coil used in the original design was not suited for continuous duty-cycle i.e. continuously energized, and that if subjected to continuous energization, the coil could fail prematurely. Licensee immediate corrective actions to this notification included the issuance of an operations standing order to address the degraded, but operable, condition for currently installed EMAX circuit breakers for continued use. The licensee identified all existing, installed EMAX circuit breakers and developed a safety-significance prioritized replacement schedule. Licensee corrective actions to prevent recurrence revised DCP(s) to reflect a qualified closing coil suitable for continuous duty-cycle and revising procedures and processes associated with vendor oversight. As part of the 10CFR21 investigation, the licensee conducted an extent of condition broadness review and identified a total of 37 installed EMAX circuit breakers used in safety-related circuits since mid 2007.

Analysis:

The failure to conduct a thorough design review process to ensure that design specifications were accurately incorporated into the final design and the failure to adequately specify functional test requirements in accordance with plant design basis and configuration is a performance deficiency. This resulted in the failure of 2BB16-13 breaker closing coil and associated control power fuse. The finding is considered more than minor because it had a direct impact on the breakers ability to perform its safety related function. The finding affected the Reactor Safety Cornerstones of Mitigating Systems and Barrier Integrity in that the failure to establish measures to assure that purchased material, equipment, and services conform to procurement documents to ensure that safety-related breakers are assembled and functionally tested correctly impacted the design control and equipment performance (availability and reliability)attributes. This finding was determined to be of very low safety significance (Green)because it did not result in a loss of operability or functionality. This finding was determined to not have a cross-cutting aspect associated with it because it is not indicative of current licensee performance.

Enforcement:

10 CFR 50 Appendix B, Criterion VII, Instructions, Control of Purchased Material, Equipment, and Services, states in part that, measures shall be established to assure that purchased material, equipment, and services, whether purchased directly or through contractors and subcontractors, conform to the procurement documents.

Contrary to the above, the licensee failed to establish measures to assure that EMAX electrical circuit breaker final design conformed to procurement documents, i.e. SNC Design Specification X3AC02B and that the breaker final design was adequately functionally tested prior to plant installation. This resulted in the failure of 2BB16-13 breaker closing coil and associated control power fuse. This design deficiency condition existed from February 2006 through November 2009. Because this issue was determined to be of very low safety significance (Green) and the licensee has entered it into their corrective action program as CR 2009111523, this violation is being treated as a non-cited violation (NCV), consistent with Section VI.A.1 of the NRCs Enforcement Policy: NCV 05000424,425/2010003-02, Failure to Verify Purchased Equipment Conformed to Design Specifications.

==1R19 Post-Maintenance Testing

a. Inspection Scope

==

The inspectors either observed post-maintenance testing or reviewed the test results for the following six 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 Technical Specification (TS) operability requirements.

  • MWO 1060336532, train A NSCW tower fan #1 breaker 1AB1505 closing coil replacement
  • Unit 2A ESF chiller maintenance outage
  • MWO 21003328, train B CCW pump #4
  • Unit 1B NSCW pump #2 system outage
  • Unit 2 safety injection (SI) pump discharge flow transmitter 2FT-922 calibration

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 2R14 refueling outage that ended on April 11, 2010. The inspectors confirmed that, 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 technical specifications 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:

  • Performed containment closure activities, including a detailed containment walkdown prior to startup, to verify no evidence of leakage and that debris had not been left which could affect the performance of the containment sump.
  • Observed heat up and startup activities to verify that TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant conditions. Reactor coolant system (RCS) integrity was verified by reviewing RCS leakage calculations.

==1R22 Surveillance Testing

a. Inspection Scope

==

The inspectors reviewed the following five 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, Delta T/ Tave Loop 3 Protection Channel III, 2T 431, Channel Operational Test and Channel Calibration

In-Service Tests (IST)

  • 14825-2 Rev. 82.2, Quarterly Inservice Valve Test, section 5.3.12

RCS Leakage Detection

  • 14905-2 Rev. 44.1, RCS Leakage Calculation (Inventory Balance)

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.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee submittals for the listed PIs during the period from April 1, 2009 through March 31, 2010, for both 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, Rev. 14.0, NRC Performance Indicator and Monthly Operating Report Preparation and Submittal.

Barrier Integrity Cornerstone

The inspectors reviewed Unit 1 and Unit 2 chemistry and operator log entries, 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.

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 operator work-arounds, operator burdens, and control room deficiencies for Unit 1 and 2 that were in effect on April 21, 2010. The inspectors reviewed the licensees lists to determine whether any items would adversely affect the operators ability to implement abnormal or emergency operating procedures. The inspectors reviewed proposed corrective actions and schedule for each item on the operator work-arounds, operator burdens, and control room deficiencies lists. The inspectors reviewed the compensatory actions and cumulative effects on plant operation. The inspectors verified each item was being dispositioned in accordance with plant procedure 10025-C, Work-Around Program.

Documents reviewed are listed in the Attachment.

b. Findings and Observations

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees Corrective Action Program and associated documents to identify trends which could indicate the existence of a more significant safety issue. The review was focused on repetitive equipment issues, but also considered the results of inspector daily CR screening and the licensees trending efforts. The review nominally considered the six month period of October 2009 through March 2010 although some examples extended beyond those dates when the scope of the trend warranted. The inspectors also reviewed several CRs associated with operability determinations which occurred during the period. The inspectors compared and contrasted their results with the results contained in the licensees latest Integrated Performance Assessment (IPA). Corrective actions associated with a sample of the issues identified in the licensees trend reports were reviewed for adequacy. The inspectors also evaluated the trend reports against the requirements of the licensees corrective action program as specified in licensee procedure NMP-GM-002, Corrective Action Program, and 10 CFR 50, Appendix B.

b. Findings

and Observations

No findings were identified. The inspectors compared the licensee IPA with the results of the inspectors daily screening and did not identify any discrepancies or potential trends in the data that the licensee had failed to identify.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000424/2007-001-01:

Auxiliary Contact Blocks on Motor Starter Assemblies not being Secured resulted in the Inability to meet Seismic Qualifications

On February 19, 2007, a top-mounted auxiliary contact block for the Unit 1 B train SI pump mini-flow isolation valve motor starter assembly was found not completely engaged. This component was assumed inoperable for longer than allowed by technical specifications as a result of not meeting seismic qualifications. An investigation by the licensee determined that original installation of the contact blocks did not have adequate procedural guidance to ensure they were properly engaged via a locking tab. The inspectors reviewed the LER, the associated condition reports, and subsequent action items. The enforcement aspects of this finding are discussed in Section 4OA7. This LER is closed.

.2 (Closed) Licensee Event Report 05000424/2009-001: Ultimate Heat Sink (UHS)

Inoperable Longer than Allowed by Technical Specifications

On September 16, 2009, when the plant was in mode 1, licensee personnel rendered the B train UHS incapable of fulfilling its 30 day mission time based on NSCW system back leakage caused during the performance of section 4.4.6, Chilled Water Alignment to the B Train Containment Auxiliary Cooler and Reactor Cavity Cooler, of procedure 13743-C, Normal Chilled System. The inspectors reviewed the LER, the associated condition report, and subsequent action items. The enforcement aspects associated with this event were documented in NRC integrated inspection report 05000424,425/2009004 Section 4OA7. No other findings were identified. This LER is closed.

.3 (Closed) Licensee Event Report 05000424/2009-002: Inadvertent Hand-Switch Contact

causes Automatic Reactor Trip

On December 7, 2009, at approximately 18:01 hours Eastern Standard Time (EST) with Unit 1 operating at 100 percent rated thermal power, an automatic turbine trip occurred due to low main condenser vacuum. In response to the turbine trip, the Reactor Protection System (RPS) actuated and automatically opened the reactor trip breakers.

The unit was stabilized in Mode 3. The licensees investigation determined that the cause of the low condenser vacuum was due to inadvertent operation of a control room hand switch that resulted in a de-energization of a non-vital 480 volt switchgear. The inspectors reviewed the LER, the associated condition report, and subsequent action items. No findings were identified. This LER is closed.

.4 (Closed) Licensee Event Report 05000424/2009-003: High Vibrations on Main Turbine

causes Manual Reactor Trip

On December 9, 2009 at approximately 23:10 hours during power ascension from an unplanned shutdown, with the unit operating at approximately 24 percent rated thermal power, the reactor was manually tripped. As preparations were being made to synchronize the main generator to the grid, high vibrations were experienced on the high pressure turbine. Due to the high vibrations the turbine was manually tripped. As the turbine was coasting down, vibration levels continued to increase. Therefore, condenser vacuum was broken to slow the turbine to minimize any potential damage. Prior to breaking condenser vacuum and in anticipation of the trip of the operating main feedwater pump due to low condenser vacuum, the control room operators manually tripped the reactor. The inspectors reviewed the LER, the associated condition report, and subsequent action items. No findings were identified. This LER is closed.

.5 (Closed) Licensee Event Report 05000425/2009-001: Inadvertent Isolation of Instrument

Air System cause Automatic Reactor Trip

On December 23, 2009, while attempting to restore the B instrument air dryer to service (after removing tagout 2-DT-09-2420-00438), the system operator inadvertently isolated instrument air to the turbine building, auxiliary building, and control building by closing the respective isolation valves. Per tagout 2-DT-09-2420-00438, the system operator was directed to restore instrument air dryer B to service by performing section 4.1.3 of procedure 13711. Instead, the system operator performed section 4.1.1 of procedure 13711, which directed the operator to isolate air to the turbine building, auxiliary building, and control building. The control room operators quickly identified the loss of instrument air, and dispatched operators to restore it. However, before instrument air could be restored, lowering instrument air pressure caused an automatic trip of the B main feed pump. The control room operators immediately inserted a manual trip of the reactor per the alarm response procedure. The enforcement aspects associated with this event were documented in NRC integrated inspection report 5000424,425/2009005 Section 4OA3. No other findings were identified. This LER is closed.

.6 (Closed) Licensee Event Report 05000425/2010-001: Closure of Residual Heat

Removal Injection Valve in Mode 1

On February 18, 2010 while reviewing a partially completed surveillance procedure for verifying the operability of the train B shutdown panel transfer function, it was discovered that the MOV that isolates RHR flow to loops 3 and 4 cold legs had been momentarily stroked closed twice with the unit in Mode 1, on January 5, 2010. Stroking this valve closed in Mode 1 renders both trains of RHR inoperable since the required emergency core cooling flow from the RHR pump(s) cannot be assured, and requires entry into technical specification LCO 3.0.3. The inspectors reviewed the LER, the associated condition report, and subsequent action items. The enforcement aspects of this finding are discussed in Section 4OA7. 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 the following 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 Reactor Coolant System Dissimilar Metal Butt Welds (TI 2515/172, Revision 1)

a. Inspection Scope

The inspectors conducted a review of the licensees activities regarding licensee dissimilar metal butt weld (DMBW) mitigation and inspection implemented in accordance with the industry self-imposed mandatory requirements of Materials Reliability Program (MRP-139), Primary System Piping Butt Weld Inspection and Evaluation Guidelines.

Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds, was issued February 21, 2008, to support the evaluation of the licensees implementation of MRP-139. This inspection was limited to review of MRP-139 activities performed after April 2008.

TI 2515/172 was performed in April 2008 as documented in Inspection Report 2008003.

During that time a complete program review (per TI 2515/172 paragraph 03.05) was performed.

The documents reviewed by the inspector for this inspection are listed in the Attachment.

From March 15 - 19, 2010, the inspectors performed a review in accordance with TI-172 as described in the Observation Section below:

b.

Observations

In accordance with requirements of TI 2515/172 (dated 02/21/08), the inspectors evaluated and answered the following questions:

(1) Implementation of the MRP-139 Baseline Inspections

1. Have the baseline inspection been performed or are they scheduled to be performed

in accordance with MRP-139 guidance?

Yes. The licensee has performed all required baseline inspections at the time of this review.

Overlays were installed on all Alloy 82/182 Pressurizer butt welds during the spring 2008 outage for Unit 1 and during the spring 2007 outage for Unit 2. Baseline UT exams for all these welds occurred at the time. Follow-on exams for these welds were completed for Unit 2 during this outage. The answers in part

(2) below refer to these exams. Follow-on exams for the Unit 1 welds are scheduled as part of that units ISI program.

There are no Alloy 82/182 butt welds greater than or equal to 4 NPS and less than 14 NPS exposed to temperatures equivalent to the hot leg.

Alloy 82/182 butt welds greater than 14 NPS exposed to temperatures equivalent to the hot leg were inspected as part of the American Society of Mechanical Engineers (ASME) Code exams - during the fall 2006 outage for Unit 1 and during the spring 2007 outage for Unit 2. The follow-on exams for these welds are scheduled in the respective ISI programs for each unit.

Alloy 82/182 butt welds exposed to temperatures equivalent to the cold leg were inspected as part of the ASME Code exams - during the fall 2006 outage for Unit 1 and during the spring 2007 outage for Unit 2. The follow-on exams for these welds are also scheduled in the respective ISI programs for each unit.

2. Is the licensee planning to take any deviations from the MRP-139 baseline inspection

requirements of MRP-139? If so, what deviations are planned, what is the general basis for the deviation, and was the NEI-03-08 process for filing a deviation followed?

No. The licensee has not submitted any requests for deviation from MRP-139 requirements.

(2) Volumetric Examinations

1. Were the examinations performed in accordance with the MRP-139, Section 5.1

guidelines and consistent with NRC staff relief request authorization for weld overlaid welds? Yes. All examinations were performed in accordance with applicable requirements.

2. Were examinations performed by qualified personnel? (Briefly describe the

personnel training/qualification process used by the licensee for this activity.)

Yes. All personnel performing the examinations were qualified under the Performance Demonstration Initiative (PDI) program.

3. Were examinations performed such that deficiencies were identified, dispositioned,

and resolved?

Yes. Examinations were performed in a manner where deficiencies were identified, dispositioned and resolved.

(1) Weld Overlays

This portion of the TI was not inspected during the period of this report.

(2) Mechanical Stress Improvement (SI)

There were no stress improvement activities performed or planned by this licensee to comply with their MRP-139 commitments.

(3) Application of Weld Cladding and Inlays

This portion of the TI was not inspected during the period of this report.

(4) Inservice Inspection Program

1. Has the licensee prepared an MRP-139 inservice inspection program? If not, briefly

summarize the licensees basis for not having a documented program and when the licensee plans to complete preparation of the program.

Yes. The welds associated with MRP-139 have been entered into the Augmented Exam section of the licensees ISI program.

2. In the MRP-139 inservice inspection program, are the welds appropriately

categorized in accordance with MRP-139? If any welds are not appropriately categorized, briefly explain the discrepancies.

Yes. The welds are appropriately categorized in accordance with MRP-139.

3. In the MRP-139 inservice inspection program, are the inservice inspection

frequencies, which may differ between the first and second intervals after the MRP-139 baseline inspection, consistent with the inservice inspections frequencies called for by MRP-139?

Yes. The inspection frequencies of the Augmented exams are consistent with the requirements of MRP-139.

4. If any welds are categorized as H or I, briefly explain the licensees basis of the

categorization and the licensees plans for addressing potential PWSCC.

Welds previously categorized as H or I have been inspected and have been re-categorized.

5. If the licensee is planning to take deviations from the MRP-139 inservice inspection

guidelines, what are the deviations and what are the general bases for the deviations? Was the NEI 03-08 process for filing deviations followed?

No. The licensee is not planning to make any requests for deviation from MRP-139 requirements.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

.1 Exit Meeting

On July, 20th, the resident inspectors presented the inspection results to Mr. R.

Dedrickson and other members of his 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 significance (Green) or Severity Level IV were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-cited Violation.

.1 Closure of RHR Injection Valve in Mode 1

10CFR50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that conditions adverse to quality shall be promptly identified and corrected. Contrary to the above, corrective actions taken in response to an identified procedural error (as documented in CR 2009107697 on 8/11/09), which were required to prevent the closure of 2HV-8809B (RHR discharge isolation valve to loops 3 and 4) during valve testing in Modes 1 and 2, were not promptly implemented. As a result, on 1/5/2010 while Unit 2 was in Mode 1, RHR isolation valve, 2HV-8809B, was stroked closed twice during surveillance testing, which resulted in two unplanned T.S. 3.0.3. entry conditions. This finding is of very low safety significance (Green) due to the fact that the valve was cycled closed twice for a short duration (approximately 1 minute) and then immediately reopened. Also, a system operator, who was in continuous communications with the control room, was stationed at the valve during the test to manually open the isolation valve if a safety injection were required. A regional Senior Reactor Analyst performed a Phase 3 evaluation under the Significance Determination Process for this performance deficiency. Based upon this evaluation, the performance deficiency was characterized as very low safety significance (Green). The dominant accident sequence was a Loss of Coolant Accident with the failure of the Residual Heat Removal System due to the performance deficiency.

Consequently, core cooling was not maintained and core damage ensued. The major assumption of the evaluation was the exposure time of one minute. The licensee has documented this event in their corrective action program (CR 2010102068), issued LER 05000425/2010-001, conducted an apparent cause determination, and developed applicable corrective actions.

.2 Failure of

Auxiliary Contact Blocks in Safety Related MOV Motor Starters

10 CFR 50 Appendix B, Criterion V, Instructions, Procedures and Drawings, requires that all activities affecting quality shall be prescribed by documented instructions, procedures or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Criterion V requires that instructions, procedures or drawings shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, the licensee failed to establish, implement, and maintain adequate maintenance procedures to ensure that safety-related motor starters were capable of performing their safety related function.

More specifically, the maintenance procedure, 25508-C, Freedom Series Motor Starter Installation Instructions, to ensure that the auxiliary contact blocks were fully engaged and locked into position via locking tabs. This finding is not greater than green due to the possibility of recovering the failed equipment and the performance deficiency was associated with only one infrequent initiating event. The licensee has entered this issue into their corrective action program as CR 2006111712, completed an apparent cause determination, issued LER 05000424/2007-001-01 and completed all applicable corrective actions.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

R. Brigdon, Training and Emergency Preparedness Manager
C. Buck, Chemistry Manager
J. Churchwell, ISI Planning
W. Copeland, Performance Analysis Supervisor
D. Cordes, Southern Nuclear
R. Dedrickson, Plant Manager
K. Dyar, Security Manager
W. Garrett, Containment Exams - Appendix J
E. Groves, BACCP/Snubbers & Supports
M. Hickox, Licensing
I. Kochery, Health Physics Manager
S. LeBlanc, Steam Generator Engineer
L. Mansfield, Engineering Director
D. McCary, Operations Manager
C. Paitsell, Site Welding Engineer
J. Robinson, Technical Services Manager
M. Sharma, Licensing
T. Smith, Eddy Current Level III
S. Swanson, Site Support Manager
T. Tynan, Site Vice-President

NRC personnel

M. Cain, Senior Resident Inspector
T. Chandler, Resident Inspector
S. Shaeffer, Chief, Region II Reactor Projects Branch 2

LIST OF ITEMS

OPENED AND CLOSED

OPEN AND CLOSED

05000425/2010003-01 NCV Failure to Inspect Tube R1C2 of Steam Generator during the Steam Generator Eddy Current Examination in 2007 (Section 1R08.4)
05000424,425/2010003-02 NCV Failure to Verify Purchased Equipment Conformed to Design Specifications (Section 1R18)

CLOSED

05000424/2007-001-01 LER Auxiliary Contact Blocks on Motor Starter Assemblies not being Secured resulted in the Inability to meet Seismic Qualifications (Section 4OA3.1)
05000424/2009-001 LER Ultimate Heat Sink (UHS) Inoperable Longer than Allowed by Technical Specifications (Section 4OA3.2)
05000424/2009-002 LER Inadvertent Hand-Switch Contact causes Automatic Reactor Trip (Section 4OA3.3)
05000424/2009-003 LER High Vibrations on Main Turbine causes Manual Reactor Trip (Section 4OA3.4)
05000425/2009-001 LER Inadvertent Isolation of Instrument Air System cause Automatic Reactor Trip (Section 4OA3.5)
05000425/2010-001 LER Closure of Residual Heat Removal Injection Valve in Mode (Section 4OA3.6)

LIST OF DOCUMENTS REVIEWED

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