IR 05000498/2012005

IR 05000498-12-005 and 05000499-12-005; 09/29/2012 - 12/31/2012; South Texas Project Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report; Inservice Inspection and Problem Identification and Resolution

ML13037A195
Person / Time
Site:	South Texas
Issue date:	02/05/2013
From:	Webb Patricia Walker NRC/RGN-IV/DRP/RPB-A
To:	Koehl D South Texas
Walker W
References
IR-12-005
Download: ML13037A195 (71)

Text

U N IT E D S TA TE S N U C LE AR R E GU LA TOR Y C OM MI S S I ON R E G IO N I V 1600 EAST LAMAR BLVD AR L I NG TO N , TE X AS 7 60 1 1 - 4511 February 5, 2013 Mr. Dennis Koehl Chief Executive Officer and Chief Nuclear Officer STP Nuclear Operating Company P.O. Box 289 Wadsworth, TX 77483 Subject: SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000498/2012005 AND 05000499/2012005

Dear Mr. Koehl:

On December 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your South Texas Project Electric Generating Station, Units 1 and 2, facility. The enclosed inspection report documents the inspection results which were discussed on January 3, 2013, with Mr. D. Rencurrel, Senior Vice President, and other members of your staff.

The inspections 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.

Three NRC-identified findings of very low safety significance (Green) were identified during this inspection. All of these findings were determined to involve violations of NRC requirements.

Further, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at South Texas Project Electric Generating Station, Units 1 and 2, facility.

If you disagree with a cross-cutting aspect assignment 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 IV; and the NRC Resident Inspector at South Texas Project Electric Generating Station, Units 1 and 2, facility.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs Agencywide Document Access and Management 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/

Wayne C. Walker, Branch Chief Project Branch A Division of Reactor Projects Docket Nos.: 05000498, 05000499 License Nos.: NPF-76, NPF-80 Enclosure: Inspection Report 05000498/2012005 and 05000499/2012005 w/Attachment 1: Supplemental Information w/Attachment 2: Document Request for Occupational Radiation Safety Inspection w/Attachment 3: Inservice Inspection Document Request cc w/ encl: Electronic Distribution

SUMMARY OF FINDINGS

IR 05000498/2012005, 05000499/2012005; 09/29/2012 - 12/31/2012; South Texas Project

Electric Generating Station, Units 1 and 2, Integrated Resident and Regional Report;

Inservice Inspection and Problem Identification and Resolution.

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Three Green non-cited violations of significance were identified. The significance of most findings is indicated by their color (Green,

White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. The cross-cutting aspect is determined using Inspection Manual Chapter 0310,

Components Within the Cross-Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

Inspectors identified a non-cited violation of 10CFR50.55a(g)(4) involving the licensees failure to perform a system pressure test of the reactor vessel flange leak-off line of Units 1 and 2, in accordance with the applicable edition of Section XI of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code. Contrary to the above, prior to November 1, 2012, the licensee failed to perform the required pressure test of the reactor vessel flange seal leak-off line for both units. Specifically, the licensee failed to implement the American Society of Mechanical Engineers Boiler and Pressure Vessel Code,

Section XI, Class 2 requirements for pressure retaining components as provided by Article IWC 5220, System Leakage Test. The licensee entered the finding into their corrective action program as Condition Report 12-28600.

The inspectors determined that the licensees failure to perform a pressure test of the reactor vessel flange leak-off line was a performance deficiency. This finding was more than minor because it affected the Initiating Events Cornerstone attribute of Equipment Reliability and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Using Manual Chapter 0609, Attachment A, The Significant Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green) because the finding did not result in exceeding the reactor coolant system leak rate for a small loss-of-coolant accident, and did not affect other systems used to mitigate a loss-of-coolant accident resulting in a total loss of their function. This issue did not have a cross-cutting aspect associated with it because it is not indicative of current performance (Section 1R08).

Green.

Inspectors identified a non-cited violation of very low safety significance of Technical Specification 6.8.1.a and Regulatory Guide 1.33, for the failure to follow procedures that ensured abrasive tools for use on stainless steel systems were not contaminated with carbon steel. Specifically, the inspectors determined that the licensee was not maintaining tools as required by Procedure 0PGP03-ZG-0001, Control of Materials and Products By User Groups, Revision 30, and Procedure 0PNP01-ZP-0032, Tools and Measuring

&Test Equipment Control, Revision 6, because inspectors observed multiple instances of tools coded for use on stainless steel or aluminum bronze stored with tools marked for use on carbon steel, rust deposits on tools marked for use on stainless steel, and rust deposits on stainless steel components in the plant.

This indicated that carbon steel contaminated tools may have been used on these systems. The licensee took corrective actions to segregate the coded tools and trained tool room attendants to properly store and mark abrasive tools designated for use on stainless steel, and evaluated the systems with indications of rust deposits. This issue was entered into the licensees corrective action program as Condition Report 12-28689.

Inspectors determined the failure to assure that abrasive tools designated for exclusive use on stainless steel were stored separately from tools used on other materials was a performance deficiency. This finding was more than minor because it affected the Initiating Events Cornerstone attribute of Equipment Reliability and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Using Manual Chapter 0609, Attachment A, The Significant Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green) because the finding did not result in exceeding the reactor coolant system leak rate for a small loss-of-coolant accident, and did not affect other systems used to mitigate a loss-of-coolant accident resulting in a total loss of their function. This finding had a cross-cutting aspect in the area of human performance work practices in that the licensee failed to effectively communicate expectations regarding procedural compliance, and personnel did not follow procedures. Specifically, the inspectors observed that although there were requirements to segregate tools, tools were not consistently segregated when returned to the storage locations as required by procedures H.4(b) (Section 1R08).

Green.

The inspectors identified a non-cited violation of Technical Specification 6.8.1.d, Fire Protection Program Implementation, for the failure to follow work order package instructions requiring the use of Drawing C012-00081-F7F, Detail E-1 Silicone Elastomer Typical Electrical Pen.

Seals (Walls & Floors), to establish 6 inches of fire retardant sealant material for penetrations in Units 1 and 2. The inspectors noticed that Unit 1 train B safety-related 4160 Vac switchgear room electrical penetration F4476 had gaps around the edge. A design change installed new electrical cables that required the penetration be sealed using work order package 139376, that stated the penetration seal WILL BE IAW the Penetration Seal Permit and detail

Drawing C012-00081-F7F. During the repair activities to correct the gaps, it was discovered that a portion of the seal was only 4.5 inches. The licensee captured this issue as Condition Report 12-28283. Corrective actions included restoring the seal to 6 inches, performing additional analysis to support a 3-hour fire barrier with just 5 inches, and performing extent of condition inspections.

The finding was more than minor because it was associated with the Initiating Events Cornerstone attributes of Design Control and Procedure Quality, and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions because it resulted in multiple fire penetration seals being declared nonfunctional as a result of being less than the design thickness. The inspectors used Manual Chapter 0609,

Attachment 0609.04, to determine that fire protection issues are processed through Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005. The inspectors used Appendix F, Attachment 1, to determine that the finding was of very low safety significance because it was a Moderate A fire confinement issue that screened out using Task 1.3.2 questions, since the seals would still have provided a 2-hour fire endurance rating or a 20 minute fire endurance rating without the seal being subject to direct flame impingement. In addition, this finding had human performance cross-cutting aspects associated with work practices because the licensee did not communicate human error prevention techniques such as self and peer checking, commensurate with the risk, such that the work activity was performed safely H.4(a) (Section 4OA2).

Licensee-Identified Violations

A violation of very low safety significance identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and associated corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power and remained there until October 10, 2012, when the unit entered coastdown operations in preparation for Refueling Outage 1RE17. Unit 1 commenced Refueling Outage 1RE17 on October 20, 2012. On November 24, 2012, Unit 1 reached normal operating temperature and pressure in preparation for reactor startup, which was achieved on November 26, 2012. The main generator output breaker was closed on November 27, 2012; with 100 percent rated thermal power achieved on November 30, 2012, and essentially remained there for the duration of the inspection period.

Unit 2 began the inspection period at 100 percent rated thermal power and essentially remained there for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

November 1, 2012, Unit 1, residual heat removal system train B December 3, 2012, Unit 1, auxiliary feedwater system train C December 4, 2012, Unit 2, component cooling water system train A December 20, 2012, Unit 1, safety injection system train C The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with

the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

On October 30, 2012, the inspectors performed a complete system alignment inspection of the Unit 1 residual heat removal system train C to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one complete system walkdown sample as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Inspection Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

October 23, 2012, Unit 1, electrical auxiliary building engineered safety features switchgear room train B, Fire Zone Z042

October 24, 2012, Unit 1, electrical auxiliary building engineered safety features switchgear room train C, Fire Zone Z052 October 24, 2012, Unit 1, fuel handling building, Fire Zone 303 October 27, 2012, Unit 1, mechanical auxiliary building, Fire Zone 147 The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b. Findings

See Section 4OA2 for a non-cited violation associated with the train B switchgear room fire penetration seal.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the UFSAR, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding; reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. The inspectors also inspected the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers. Specific documents reviewed during this inspection are listed in the attachment.

December 5, 2012, Unit 1, isolation valve cubicle These activities constitute completion of one flood protection measures inspection sample as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the Unit 1 component cooling water essential cooling water heat exchangers. The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines; the licensee properly utilized biofouling controls; the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one heat sink inspection sample as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Completion of Sections

.1 through .5, below, constitutes completion of one sample as

defined in Inspection Procedure 71111.08-05.

.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water

Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control (71111.08-02.01)

a. Inspection Scope

The inspectors observed five nondestructive examination activities and reviewed ten nondestructive examination activities that included four types of examinations.

The licensee did not identify any relevant indications accepted for continued service during the nondestructive examinations.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD/COMPONENT IDENTIFICATION EXAMINATION TYPE Component 1-CC 1109-RH02/20-CC-1109-WA3-H Visual Examination - VT-2 Cooling Water Reactor 12-RC-1125-BB1-FW5 Ultrasonic Testing Coolant System Main Steam 30-MS-1001-25B Ultrasonic Testing System Chemical and 1-CV-1210-BB2 HFW-0403 Penetrant Testing Volume Control System Main Steam 30-MS-1003-GA2 26PL1-26PL8 Pipe Magnetic Particle System Lugs Testing - Dry Powder The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD/COMPONENT IDENTIFICATION EXAMINATION TYPE Component 1-CC 1109-RH02/20-CC-1109-WA3-H Visual Examination - VT-2 Cooling Water Reactor Vessel Bottom Mounted Instrumentation 8, and Remote Visual 10 through 58 Examination Reactor Vessel Bottom Mounted Instrumentation 9 Visual Examination Reactor Vessel Bottom Mounted Instrumentation 9 Remote Visual Examination Pressurizer 2R141TRC0078 FW8409 and FW8410 Penetrant Testing System Main Steam 2S131XFW0604 Penetrant Testing System Chemical and 1-CV-1210-BB2 HFW-0403 Penetrant Testing Volume Control System

SYSTEM WELD/COMPONENT IDENTIFICATION EXAMINATION TYPE Main Steam 30-MS-1001-GA2-25B Ultrasonic Testing System Reactor Coolant 12-RC-1125-BB1-FW5 Ultrasonic Testing System Main Steam 30-MS-1003-GA2 26PL1-26PL8 Pipe Magnetic Particle System Lugs Testing - Dry Powder During the review and observation of each examination, the inspectors verified that activities were performed in accordance with the ASME Code requirements and applicable procedures. The inspectors compared any indications identified during previous examinations and verified that licensee personnel evaluated the indications in accordance with the ASME Code and approved procedures. The inspectors also verified the qualifications of all nondestructive examination technicians performing the inspections were current.

The inspectors observed one weld on a high point vent for the 1B centrifugal charging pump discharge line in the chemical and volume control system.

The inspectors reviewed records for the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Chemical and 1-CV-1210-BB2 HFW-0403 Gas Tungsten Arc Welding Volume Control System The inspectors verified, by review, that the welding procedure specifications and the welder had been properly qualified in accordance with ASME Code,Section IX requirements. The inspectors also verified, through observation and record review, that essential variables for the welding process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.01.

b. Findings

Introduction.

Inspectors identified a Green non-cited violation of 10CFR50.55a(g)(4)involving the licensees failure to perform a system pressure test of the reactor vessel flange leak-off line of Units 1 and 2, in accordance with the applicable edition of Section XI of the ASME Code.

Description.

During a review of the licensees inservice inspection program, the inspectors noted that the reactor vessel flange seal leak-off line for each of the units was classified as an ASME Class 2 component. The inspectors identified, through further review and discussion, that the licensee had not performed the required system leakage test of each of the seal leak-off lines as described by the applicable sections of the 2004 Edition of the ASME Code. Specifically, the licensee implemented a methodology that looked for leakage and credited a walkdown of the accessible piping sections of each line during Mode 3 conditions without the line being pressurized. Article IWC-5000, System Pressure Tests, of Section XI of the ASME Code requires that all pressure retaining components be pressure tested via a system leakage test per IWC-5220, System Leakage Test. The licensee implemented a visual examination of the system without the system being filled or pressurized. The licensee is required to comply with the requirements imposed by Section XI of the ASME Code, or request exemption from particular requirements via a relief request. The licensee submitted a relief request to invoke ASME Code Case N-805 to restore compliance with regulatory requirements.

Analysis.

The inspectors determined that the licensees failure to perform a pressure test of the reactor vessel flange leak-off line was a performance deficiency. This finding was more than minor because it affected the Initiating Events Cornerstone attribute of Equipment Reliability and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Using Manual Chapter 0609, Attachment A, The Significant Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green)because the finding did not result in exceeding the reactor coolant system leak rate for a small loss-of-coolant accident, and did not affect other systems used to mitigate a loss-of-coolant accident resulting in a total loss of their function. This issue did not have a cross-cutting aspect associated with it because it is not indicative of current performance (Section 1R08).

Enforcement.

Title 10 CFR 50.55a(g)(4) requires that components classified as ASME Code Class 1, Class 2, and Class 3 meet the requirements set forth in Section XI of the applicable editions of the ASME Boiler and Pressure Vessel Code and Addenda.

Title 10 CFR 50.55(a)(g)(4)(ii) requires that inservice examination of components be conducted during successive 120-month inspection intervals and comply with the requirements of the latest edition and addenda of the Code applicable to the specific interval. ASME Code,Section XI, Article IWC-5221 requires for Class 2 pressure retaining components a system leakage test be performed at the system pressure obtained while the system, or portion of the system, is in service performing its normal operating function. Contrary to the above, prior to November 1, 2012, the licensee failed to perform the required pressure test on the reactor vessel flange seal leak-off line for each of the two units. Because this finding is of very low safety significance and has been entered into the corrective action program as Condition Report 12-28600, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000498/2012005-01 and 05000499/2012005-01, Failure to Perform Pressure Testing of the Reactor Vessel Flange Leak-Off Lines.

.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)

a. Inspection Scope

The licensee did not perform inspections of the vessel upper head penetrations. No inspections were performed because the vessel upper head and its assembly was replaced and inspected in a previous outage. Therefore, the inspectors determined this section of Inspection Procedure 71111.08 is not applicable.

These actions constitute completion of the requirements for Section 02.02.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)

a. Inspection Scope

The inspectors evaluated the implementation of the licensees boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensees boric acid corrosion control walkdown as specified in Procedure 0PGP03-ZE-0133, Boric Acid Corrosion Control Program. The inspectors also reviewed the visual records of the components and equipment. The inspectors verified that the visual inspections emphasized locations where boric acid leaks could cause degradation of safety-significant components. The inspectors also verified that the engineering evaluations for those components where boric acid was identified gave assurance that the ASME Code wall thickness limits were properly maintained. The inspectors confirmed that usually the corrective actions performed for evidence of boric acid leaks were consistent with requirements of the ASME Code. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.03.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities (71111.08-02.04)

a. Inspection Scope

The licensee did not perform inspections of the steam generator tube inspection analysis. No inspections were performed because the steam generators were replaced and inspected in a previous outage and no inspections were required this outage.

Therefore, the inspectors determined this section of Inspection Procedure 71111.08 is not applicable.

These actions constitute completion of the requirements for Section 02.04.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems (71111.08-02.05)

a. Inspection scope

The inspectors reviewed four condition reports which dealt with inservice inspection activities and found the corrective actions for inservice inspection issues were appropriate. From this review, the inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry inservice inspection operating experience. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements of Section 02.05.

b. Findings

Introduction.

Inspectors identified a Green non-cited violation of Technical Specification 6.8.1.a and Regulatory Guide 1.33, for the failure to follow procedures that ensured abrasive tools designated for stainless steel weld preparation were stored separately from hand files and wire brushes used on carbon steel.

Description.

During inspection of the tool storage areas in the welding shop; machine shop; and the tool issue room in the radiologically controlled area, inspectors identified that hand files and wire brushes designated for either stainless steel or carbon steel weld preparation and maintenance were not stored separately. The inspectors noted that more than 10 hand files marked for use on stainless steel were rusty and, therefore, most likely had been used on carbon steel. In addition, during system walkdowns, the inspectors identified stainless steel piping and welds with surface rust. This was an indication that the area may have been cleaned with wire brushes that had previously been used on carbon steel. Inspectors were concerned that the failure to separate tools used for stainless steel weld preparation from tools used for carbon steel preparation could result in the contamination of stainless steel welds and piping by carbon steel filings, and affect the material integrity and corrosion resistance of these components.

Inspectors reviewed Procedure 0PGP03-ZG-0001, Control of Materials and Products By User Groups, Revision 30, and Procedure 0PNP01-ZP-0032, Tools and Measuring

& Test Equipment Control, Revision 6, and concluded that the licensee staff was not consistently following the procedure to ensure the segregation of abrasive tools designated for use on stainless steel from tools used on carbon steel. Step 3.1.3.3.a of Procedure 0PNP01-ZP-0032 stated, Color coded tools that inadvertently come in contact with materials other than what they were coded for may be used for

non-stainless steel and non-aluminum bronze use if the color code is removed or color coded black.

The licensee reviewed the inspectors concerns and concluded that the storage of files and wire brushes designated for use only on stainless steel in the various tool rooms was not meeting the requirements established in Procedure 0PGP03-ZG-0001, Control of Materials and Products By User Groups, Revision 30, and Procedure 0PNP01-ZP-0032, Tools and Measuring &Test Equipment Control, Revision 6. In particular, there was no consistent segregation of files or wire brushes, and there were files designated for use on stainless steel that were rusty and may have been used on carbon steel. The licensee took immediate action to remove the stainless steel designations from tools that were mixed with tools used on carbon steel. Additionally, the licensee planned to conduct additional training with maintenance personnel regarding the requirements for the separation of abrasive tools that are designated for use on stainless steel from those used on other materials. The licensee also reinforced the standards to the tool room attendants to properly store and mark abrasive tools designated for use on stainless steel, and to question the requester of abrasive tools for the end use location so the appropriate tool could be provided.

The inspectors walked down various safety-related and important to safety systems, and identified corrosion deposits on stainless steel components that may have been caused by using contaminated stainless steel brushes. The licensee did not have any procedure or approved methodology for cleaning stainless steel surfaces that were contaminated, or suspected to be contaminated, by inappropriate use of tools that had contaminated with carbon steel. This issue was entered into the licensees corrective action program as Condition Report 12-28689.

Analysis.

Inspectors determined that the failure to follow the requirements of Procedure 0PGP03-ZG-0001, Control of Materials and Products By User Groups, Revision 30, and Procedure 0PNP01-ZP-0032, Tools and Measuring &Test Equipment Control, Revision 6, to assure that abrasive tools designated for exclusive use on stainless steel were stored separately from tools used on other materials was a performance deficiency. This finding was more than minor because it affected the Initiating Events Cornerstone attribute of Equipment Reliability and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. Using Manual Chapter 0609, Attachment A, The Significant Determination Process (SDP) for Findings At-Power, the finding was determined to be of very low safety significance (Green) because the finding did not result in exceeding the reactor coolant system leak rate for a small loss-of-coolant accident, and did not affect other systems used to mitigate a loss-of-coolant accident resulting in a total loss of their function. This finding had a cross-cutting aspect in the area of human performance work practices in that the licensee failed to effectively communicate expectations regarding procedural compliance, and personnel did not follow procedures. Specifically, the inspectors observed that although there were requirements to segregate the tools, tools were not consistently segregated when returned to the storage locations as required by procedures H.4(b).

Enforcement.

Technical Specification 6.8.1.a, Procedures, requires that written procedures be established; implemented; and maintained covering the applicable procedures in Regulatory Guide 1.33, Revision 2, Appendix A. Regulatory Guide 1.33, Quality Assurance Program, Appendix A, Section 9.a requires that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. The control of tools used on stainless steel was an activity affecting quality and was implemented by Procedure 0PGP03-ZG-0001, Control of Materials and Products By User Groups, Revision 30, and Procedure 0PNP01-ZP-0032, Revision 6. Step 3.1.3.3.a required, in part, that tools marked for use only on stainless steel be stored in a designated location, and tools designated for use on stainless steel have the markings removed if used on carbon steel. Contrary to the above, prior to November 1, 2012, the licensee failed to implement written procedures covering requirements in Regulatory Guide 1.33, Quality Assurance Program, Revision 2, Appendix A, Section 9.a. Specifically, the licensee failed to accomplish the separation and appropriate designation of tools used on stainless steel, or to ensure tools used to clean stainless steel components had not been contaminated with carbon steel. The licensee took immediate action to separate the abrasive tools and remark them as necessary and provided training to the tool room attendants on the requirements to segregate tools based on use. This issue was entered into the licensees corrective action program as Condition Report 12-28689.

This finding was determined to be of very low safety significance and was entered into the licensees corrective action program. This violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy:

NCV 05000498/2012005-02, Failure to Follow Procedure for the Control of Tools for Use on Stainless Steel.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Quarterly Review of Licensed Operator Requalification Program

a. Inspection Scope

On December 18, 2012, the inspectors observed a crew of licensed operators in the plants simulator during requalification training. The inspectors assessed the following areas:

Licensed operator performance The quality of the training provided The modeling and performance of the control room simulator Follow-up actions taken by the licensee for any identified discrepancies These activities constitute completion of one quarterly licensed-operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Quarterly Observation of Licensed Operator Performance

a. Inspection Scope

On October 20-23, 2012, the inspectors observed the performance of on-shift licensed operators in the Unit 1 main control room. At the time of the observations, the plant was in a period of heightened activity due to the commencement of a plant shutdown for Refueling Outage 1RE17, which was followed by a cooldown and a period of increased reactor coolant system water inventory (solid plant).

In addition, the inspectors assessed the operators adherence to plant procedures, including the conduct of operations procedure and other operations department policies.

These activities constitute completion of one quarterly licensed-operator performance sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.3 Annual Inspection (Units 1 and 2)

The licensed operator requalification program involves two training cycles that are conducted over a 2-year period. In the first cycle, the annual cycle, the operators are administered an operating test consisting of job performance measures and simulator scenarios. In the second part of the training cycle, the biennial cycle, operators are administered an operating test and a comprehensive written examination. For this annual inspection requirement, the licensee was in the first part of the training cycle.

a. Inspection Scope

The inspector reviewed the results of the examinations and operating tests for both units to satisfy the annual inspection requirements.

On January 7, 2013, the licensee informed the lead inspector of the following Units 1 and 2 results:

Fourteen of fifteen crews passed the simulator portion of the operating test Ninety-six of ninety-six licensed operators passed the simulator portion of the operating test Ninety-six of ninety-six licensed operators passed the job performance measure portion of the examination

All of the individuals that failed the applicable portions of the operating test were remediated, retested, and passed their retake operating tests prior to returning to shift.

The inspector completed one inspection sample of the annual licensed operator requalification program.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

October 31, 2012, Units 1 and 2, essential cooling water November 26, 2012, Units 1 and 2, component cooling water December 6, 2012, Units 1 and 2, residual heat removal system The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensees actions to address system performance or condition problems in terms of the following:

Implementing appropriate work practices Identifying and addressing common cause failures Scoping of systems in accordance with 10 CFR 50.65(b)

Characterizing system reliability issues for performance Charging unavailability for performance Trending key parameters for condition monitoring Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1)

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance

effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed licensee personnels evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

October 1-12, 2012, Unit 1, planned work activities on Class 1E 125-volt battery and inverter/rectifiers on trains C and D, which required exceeding the front stop and using the risk management technical specifications configuration risk management program October 1 - November 27, 2012, Unit 1, activities associated with Unit 1 Refueling Outage 1RE17, including staging of materials in preparation of the outage; coastdown operation; the refueling outage; reactor startup; breaker closure; and power ascension The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensees probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following assessments:

November 14, 2012, Unit 1, pressurizer spray valve PCV-655B body-to-bonnet leakage November 28, 2012, Unit 2, essential cooling water through-wall leakage on inlet pipe to component cooling water pump 2A supplemental cooler December 18, 2012, Unit 1 and 2, main steam system steam dump valves wrong size booster installed December 20, 2012, Unit 1, safety injection accumulator 1A level decreasing and residual heat removal header 1A pressurizing December 20, 2012, Units 1 and 2, safety-related fire penetration seals less than the design thickness amount The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure technical specification operability was properly justified and to verify the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b. Findings

See Section 4OA2 for a non-cited violation associated with the fire penetration seals.

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors reviewed key parameters associated with materials, replacement components, timing, equipment protection from hazards, operations, flow paths, pressure boundary, ventilation boundary, structural, licensing basis, and failure modes for the permanent modification identified as safety injection system refueling water storage tank.

The inspectors verified that modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions, key safety functions, or operator response to loss of key safety functions; post-modification testing will maintain the plant in a safe configuration during testing by verifying that unintended system interactions will not occur; systems, structures and components performance characteristics still meet the design basis; the modification design assumptions were appropriate; the modification test acceptance criteria will be met; and licensee personnel identified and implemented appropriate corrective actions associated with permanent plant modifications. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample for permanent plant modifications as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

October 4, 2012, Unit 2, standby diesel generator 22 testing after replacement of cylinder head 9L October 15, 2012, Unit 1, essential service water pump 1A testing after Agastat relay replacement October 22, 2012, Unit 1, residual heat removal train B safety injection flow control valve 0852 November 19, 2012, Unit 1, safety injection system refueling water storage tank system pressure test after welded floor plate/joint repairs

December 5, 2012, Unit 1, loop C reactor coolant system average coolant temperature card replacement due to a failed low indication on TI-432A The inspectors selected these activities based upon the structure, system, or components ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate The inspectors evaluated the activities against the technical specifications, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five post-maintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for Unit 1 Refueling Outage 1RE17, conducted October 20 through November 27, 2012, to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense in depth. During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met, and controls over switchyard activities.

Monitoring of decay heat removal processes, systems, and components.

Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

Reactor water inventory controls, including flow paths; configurations; and alternative means for inventory addition; and controls to prevent inventory loss.

Controls over activities that could affect reactivity.

Refueling activities, including fuel handling and sipping to detect fuel assembly leakage.

Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing.

Licensee identification and resolution of problems related to refueling outage activities.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one refueling outage and other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

Preconditioning Evaluation of testing impact on the plant

Acceptance criteria Test equipment Procedures Jumper/lifted lead controls Test data Testing frequency and method demonstrated technical specification operability Test equipment removal Restoration of plant systems Fulfillment of ASME Code requirements Updating of performance indicator data Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct Reference setting data Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

October 16-17, 2012, Unit 1, train A and B main steam safety valves in-service test November 14, 2012, Unit 1, train A, B, and C low head safety injection flow sweeps November 21, 2012, Unit 1, train A, B, C, and D main steam isolation valves actuation and response time test (containment isolation valve test)

December 4, 2012, Unit 2, local leak rate testing of personnel airlock door seals (Unit 2 containment isolation valve)

December 5, 2012, Unit 1, reactor coolant system leakage detection surveillance following startup from Refueling Outage 1RE17 Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five surveillance testing inspection samples as defined in Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

This area was inspected to:

(1) review and assess licensees performance in assessing the radiological hazards in the workplace associated with licensed activities and the implementation of appropriate radiation monitoring and exposure control measures for both individual and collective exposures,

(2) verify the licensee is properly identifying and reporting Occupational Radiation Safety Cornerstone performance indicators, and

(3) identify those performance deficiencies that were reportable as a performance indicator and which may have represented a substantial potential for overexposure of the worker.

The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors performed walkdowns of various portions of the plant, performed independent radiation dose rate measurements, and reviewed the following items:

Performance indicator events and associated documentation reported by the licensee in the Occupational Radiation Safety Cornerstone The hazard assessment program, including a review of the licensees evaluations of changes in plant operations and radiological surveys to detect dose rates; airborne radioactivity; and surface contamination levels Instructions and notices to workers, including labeling or marking containers of radioactive material; radiation work permits; actions for electronic dosimeter alarms; and changes to radiological conditions Programs and processes for control of sealed sources and release of potentially contaminated material from the radiologically controlled area, including survey performance; instrument sensitivity; release criteria; procedural guidance; and sealed source accountability Radiological hazards control and work coverage, including the adequacy of surveys; radiation protection job coverage and contamination controls; the use of electronic dosimeters in high noise areas; dosimetry placement; airborne radioactivity monitoring; controls for highly activated or contaminated materials

(non-fuel) stored within spent fuel and other storage pools; and posting and physical controls for high radiation areas and very high radiation areas Radiation worker and radiation protection technician performance with respect to radiation protection work requirements Audits, self-assessments, and corrective action documents related to radiological hazard assessment and exposure controls since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.01-05.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

This area was inspected to assess performance with respect to maintaining occupational individual and collective radiation exposures ALARA. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspectors interviewed licensee personnel and reviewed the following items:

Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average; site-specific trends in collective exposures; and source-term measurements ALARA work activity evaluations/postjob reviews, exposure estimates, and exposure mitigation requirements The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.02-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the third quarter 2012 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Emergency ac Power System (MS06)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - emergency ac power system performance indicator for Units 1 and 2 for the period from the fourth quarter 2011 through the third quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of October 2011 through September 2012 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with

applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and reviewed condition reports related to Frequently Asked Question 480. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of two, one per unit, mitigating systems performance index - emergency ac power system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - high pressure injection systems performance indicator for Units 1 and 2 for the period from the fourth quarter 2011 through the third quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 2011 through September 2012 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of two, one per unit, mitigating systems performance index - high pressure injection system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Heat Removal System (MS08)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - heat removal system performance indicator for Units 1 and 2 for the period from

the fourth quarter 2011 through the third quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports for the period of October 2011 through September 2012 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of two, one per unit, mitigating systems performance index - heat removal system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.5 Mitigating Systems Performance Index - Residual Heat Removal System (MS09)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - residual heat removal system performance indicator for Units 1 and 2 for the period from the fourth quarter 2011 through the third quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 2011 through September 2012 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified.

Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of two, one per unit, mitigating systems performance index - residual heat removal systems samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.6 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for Units 1 and 2 for the period from the fourth quarter 2011 through the third quarter 2012. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of October 2011 through September 2012 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of two, one per unit, mitigating systems performance index - cooling water system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.7 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the fourth quarter of 2011 through the third quarter of 2012. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

The inspectors reviewed corrective action program records associated with high radiation areas (greater than 1 rem/hr) and very high radiation area nonconformances.

The inspectors reviewed radiological controlled area exit transactions greater than 100 mrem. The inspectors also conducted walkdowns of high radiation areas

(greater than 1 rem/hr) and very high radiation area entrances to determine the adequacy of the controls of these areas.

These activities constitute completion of the occupational exposure control effectiveness sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.8 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors reviewed performance indicator data for the fourth quarter of 2011 through the third quarter of 2012. The objective of the inspection was to determine the accuracy and completeness of the performance indicator data reported during these periods. The inspectors used the definitions and clarifying notes contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, as criteria for determining whether the licensee was in compliance.

The inspectors reviewed the licensees corrective action program records and selected individual annual or special reports to identify potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose.

These activities constitute completion of the radiological effluent technical specifications/offsite dose calculation manual radiological effluent occurrences sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications,

common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

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 that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, but also considered the results of daily corrective action item screening discussed in Section 4OA2.2, above, licensee trending efforts; and licensee human performance results. The inspectors nominally considered the 6-month period of July through December 2012, although some examples expanded beyond those dates where the scope of the trend warranted.

The inspectors also included issues documented outside the normal corrective action program in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the

licensees corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

These activities constitute completion of one single semi-annual trend inspection sample as defined in Inspection Procedure 71152-05.

b. Findings

No findings were identified, but the inspectors did determine that a declining trend in the fire protection program exists. This was evidenced by multiple condition reports on both Units 1 and 2 that documented:

(1) gaps in the fire penetration seals,

(2) lack of required seal penetration thickness per design,

(3) wrong caulk material used to seal gaps,

(4) improperly stored transient combustibles,

(5) improperly used flammable liquid storage lockers,

(6) improperly stored permanent equipment, and

(7) procedures and training on preventative maintenance tasks associated with fire protection are not identifying issues at a low enough threshold. The licensee agreed with the inspectors observations and entered the issue into the corrective action program as Condition Report 12-30292, requiring an apparent cause evaluation be completed to understand how the program developed negative performance issues and to determine actions to take to improve the fire protection program. See Section 4OA2.4 for a violation associated with fire penetration seals.

.4 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting the inspectors questions about fire penetration seals. The inspectors reviewed the UFSAR, the Fire Hazards Analysis Report, fire protection procedures, preventative maintenance work orders, design drawings, vendor documentation, vendor testing, interviewed personnel, reviewed the apparent cause investigation, and the corrective action program to ensure that the licensee was installing, inspecting, and maintaining the fire penetration seals in accordance with required documentation. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one in-depth problem identification and resolution sample as defined in Inspection Procedure 71152-05.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of Technical Specification 6.8.1.d, Fire Protection Program Implementation, for the failure to follow work order package instructions requiring the use of Drawing C012-00081-F7F, Detail E-1 Silicone Elastomer Typical Electrical Pen. Seals (Walls & Floors), Revision F, to establish the required 6 inches of fire retardant sealant material for penetrations in Units 1 and 2.

Description.

During a fire protection walkdown of the Unit 1 train B safety-related 4160 Vac switchgear room, the inspectors noticed that electrical penetration F4476 had gaps around the edges of the seal. The inspectors questioned the licensee on the history of the penetration and determined that as part of a Unit 1 design change in 1999, the licensee installed new electrical cables that required the original hydrosil fire penetration material to be removed in order for the cables to be routed. Once the new cables were routed, the penetrations were sealed. These activities were accomplished by work order package 139376, which stated the penetration seal WILL BE IAW the Penetration Seal Permit and detail Drawing C012-00081-F7F. The penetration permit called for 6 inches of silicone elastomer 45B to be installed and the drawing required a minimum of 6 inches of silicone elastomer 45B to be installed. During the repair activities to correct the gaps, it was discovered that a portion of the penetration only had 4.5 inches of silicone elastomer 45B. This was less than the required 6 inches and, therefore, the penetration was declared nonfunctional and compensatory measures were put in place until corrective actions could be taken. This penetration separates 4160 Vac safety-related switchgear rooms for trains A and B; train C was not impacted and remained operable the entire time providing a safe shutdown train.

The licensee captured this issue as Condition Report 12-28283 and corrective action included an hourly fire watch, restoring the seal to the required minimum of 6 inches, performing additional analysis to be able to support a 3-hour fire barrier with a minimum of 5 inches of silicone elastomer 45B material (but maintaining the design requirement of 6 inches), and performing extent of condition inspections in both Units 1 and 2. These inspections determined that several penetrations had gaps around the circumference, but were within the acceptance criteria of the manufacturer. They also determined that a high number of seals in the sample population were below the required 6 inches, but were greater than 5 inches and determined to be functional but nonconforming.

However, Unit 2 penetration W3660 had only 2 inches of silicone elastomer 45B material in a section of the penetration. This penetration was reworked as a result of a design change in 2005 that replaced an inverter and voltage regulation transformer. Work order package 274967 stated Install penetration seal IAW the Penetration Seal Permit and seal detail drawing C012-00081-F7F. The licensee captured this under Condition Report 12-31930, and declared the penetration nonfunctional. Corrective actions include an hourly fire watch, rework to restore the penetration to the required thickness, and to reevaluate the extent of condition on penetration thickness based on the high number of penetrations that are less than 6 inches. The inspectors view the failure to self check or peer check the thickness of the silicone elastomer 45B material form prior to pouring to be indicative of current performance, since at least one of the seals that was below the required 6 inches was sealed as recently as October 2011.

Analysis.

The inspectors determined that the seals thicknesses being less than the design requirement was a performance deficiency. The finding was more than minor because it was associated with the Initiating Events Cornerstone attributes of Design Control and Procedure Quality, and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions because it resulted in multiple fire penetration seals being declared nonfunctional as a result of being less than the design thickness. The inspectors used

Manual Chapter 0609, Attachment 0609.04, to determine that fire protection issues are processed through Appendix F, Fire Protection Significance Determination Process, dated February 28, 2005. The inspectors used Appendix F, Attachment 1, to determine that the finding was of very low safety significance (Green) because it was a Moderate A fire confinement issue that screened out using Task 1.3.2 questions, since the seals would still have provided a 2-hour fire endurance rating or a 20 minute fire endurance rating without the seal being subject to direct flame impingement. In addition, this finding had human performance cross-cutting aspects associated with work practices because the licensee did not communicate human error prevention techniques such as self and peer checking, commensurate with the risk, such that the work activity was performed safely H.4(a).

Enforcement.

Technical Specification 6.8.1.d states that written procedures shall be established, implemented, and maintained covering the Fire Protection Program implementation. The Fire Protection Program implements and maintains the design requirements for penetrations based on fire confinement as analyzed in the Fire Hazards Analysis Report. The Fire Hazards Analysis Report assumes these fire areas are protected by 3-hour rated fire barriers. Work Authorization Numbers 139376 and 274967 required the use of Drawing C012-00081-F7F, which required a minimum of 6 inches of seal material to be rated for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Contrary to the above, in 1999 for Unit 1 penetration F4476, and in 2005 for Unit 2 penetration W3660, maintenance personnel failed to correctly follow the work package and implement Drawing C012-00081-F7F, to ensure that 6 inches of silicone elastomer 45B were installed. Because this finding was of very low safety significance and was entered into the licensees corrective action program as Condition Reports 12-28283 and 12-31930, this finding is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000498/2012005-03 and 05000499/2012005-03, Failure to Maintain Adequate Fire Penetration Seal Material Thickness.

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

(Closed) Licensee Event Report 05000499/2011-003-000, Unit 2 Plant Mode Change with Turbine Trip Disabled During the April 2010 and November 2011 refueling outages, Unit 2 transitioned from Mode 4 to Mode 3 without having the required solid state protection system generated turbine trip signals operable. A maintenance work activity installed a jumper in both channels, trains R and S, of the nonclass relays to the turbine trip circuit. The defeated signals from the solid state protection system were the turbine trip from the reactor trip breakers open (P-4), turbine trip from a reactor trip signal (P-16), and the turbine trip from a steam generator HI-HI (P-14). Per Technical Specification 3.3.2, items 5a and 5b, P-4 and P-14 are required in Modes 1, 2, and 3. The jumpers were not removed until after Mode 3 had already been entered, a condition prohibited by Technical Specification 3.0.4. See Section 4OA7 for the enforcement aspects of this licensee event report. This licensee event report is closed.

4OA5 Other Activities

.1 (Closed) NRC Temporary Instruction 2515/177, Managing Gas Accumulation in

Emergency Core Cooling, Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)

As documented in NRC Inspection Reports 05000498/2010003, 2011002, 2011003, 2012002 and 05000499/2010003, 2011002, 2011003, and 2012002, the inspectors completed activities associated with Temporary Instruction 2515/177.

.2 (Closed) NRC Temporary Instruction 2515/187, Inspection of Near-Term Task Force

Recommendation 2.3 Flooding Walkdowns

a. Inspection Scope

The inspectors verified that the licensees flooding walkdown activities were conducted using walkdown methodology endorsed by the NRC. These flooding walkdowns are being performed at all sites in response to a letter from the NRC to licensees, entitled Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f)

Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012. Inspectors verified that licensees walkdown packages contained the elements specified in NEI 12-07 Walkdown Guidance document including:

Watertight doors Buildings and structures, including building drain system check valves Hatches and panels Manholes and penetrations b. Inspection Documentation The inspectors accompanied the licensee on their walkdown of the:

Unit 1 essential cooling water intake structure Unit 1 fuel handling building Unit 1 non-safety related electrical penetrations (manholes)

Unit 2 essential cooling water intake structure Unit 2 non-safety related electrical penetrations (manholes)and verified that the licensee confirmed the following flood protection features:

Visual inspection of the flood protection feature was performed if the flood protection feature was relevant. External visual inspection for indications of degradation that would prevent its credited function from being performed was performed Critical structure, system, and component dimensions were measured

Available physical margin, where applicable, was determined Flood protection feature functionality was determined using either visual observation or by review of other documents The inspectors independently performed their walkdown and verified that the flood protection features were in place for the following areas:

Unit 1 safety-related electrical penetrations (manholes)

Unit 1 mechanical and electrical auxiliary building flood doors Unit 2 safety-related electrical penetrations (manholes)

Unit 2 mechanical and electrical auxiliary building flood doors The inspectors verified that noncompliances with current licensing requirements, and issues identified in accordance with the 10 CFR 50.54(f) letter, item 2.g of Enclosure 4, were entered into the licensees corrective action program. In addition, issues identified in response to item 2.g that could challenge risk-significant equipment and the licensees ability to mitigate the consequences will be subject to additional NRC evaluation.

c. Findings

No findings were identified.

.3 (Closed) NRC Temporary Instruction 2515/188, Inspection of Near-Term Task Force

Recommendation 2.3 Seismic Walkdowns

a. Inspection Scope

The inspectors verified that the licensees seismic walkdown activities were conducted using walkdown methodology endorsed by the NRC. These seismic walkdowns are being performed at all sites in response to a letter from the NRC to licensees, entitled Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f)

Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012.

b. Inspection Documentation The inspectors accompanied the licensee on their seismic walkdowns of spaces and components:

Essential cooling water self-cleaning strainer 2A, September 25, 2012; essential cooling water pump room 2A Essential cooling water screen wash pump 2A and FV-6914 solenoid valve, September 25, 2012; essential cooling water 2A room 101 Unit 1, engineered safety features load sequencer cabinet B, September 26, 2012; train A load sequencer room 015C

Auxiliary feedwater pump 12, September 27, 2012; train B auxiliary feedwater pump room 006 Qualified data processing system auxiliary process cabinet B1 ZLP678, September 26, 2012; electrical auxiliary building area 015C The inspectors verified that the licensee confirmed that the following seismic features associated with Electrical Distribution Panel DP 001 were free of potential adverse seismic conditions.

Anchorage was free of bent, broken, missing or loose hardware.

Anchorage was free of corrosion that is more than mild surface oxidation.

Anchorage was free of visible cracks in the concrete near the anchors.

Anchorage configuration was consistent with plant documentation.

Safety system components will not be damaged from impact by nearby equipment or structures.

Overhead equipment, distribution systems, ceiling tiles and lighting, and masonry block walls are secure and not likely to collapse onto the equipment.

Attached lines have adequate flexibility to avoid damage.

The area appears to be free of potentially adverse seismic interactions that could cause flooding or spray in the area.

The area appears to be free of potentially adverse seismic interactions that could cause a fire in the area.

The area appears to be free of potentially adverse seismic interactions associated with housekeeping practices, storage of portable equipment, and temporary installations.

The inspectors independently performed their walkdown and verified the following areas:

Unit 1, electrical auxiliary building train A channel distribution room, September 27, 2012 Unit 2, fuel handling building main supply fan room, September 27, 2012 Observations made during the walkdown that could not be determined to be acceptable were entered into the licensees corrective action program for evaluation.

Additionally, inspectors verified that items that could allow the spent fuel pool to drain down rapidly were added to the seismic walkdown equipment list, and these items were walked down by the licensee.

c. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On October 25, 2012, the inspectors presented the results of the radiation safety inspections to Mr. G. Powell, Vice President, Generation, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On November 1, 2012, the inspectors presented the inspection results of the review of inservice inspection activities to Mr. D. Rencurrel, Senior Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On November 16, 2012, the inspectors reexited the inspection for inservice inspection activities with Mr. M. Murray, Manager, Regulatory Affairs, and other members of the licensee staff due to a change in the characterization of the issues based on additional information provided.

On January 3, 2013, the inspectors presented the inspection results to Mr. D. Rencurrel, Senior Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

The lead inspector obtained the final annual examination results and telephonically exited with Mr. T. Hurley, Operations Training Supervisor for Requalification, on January 7, 2013. The inspector did not review any proprietary information during this inspection.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as a non-cited violation.

Technical Specification 3.0.4 requires, in part, that entry into a mode or other specified condition in the applicability shall only be made when the associated actions to be entered permit continued operation for an unlimited period of time, or after performance of a risk assessment addressing inoperable systems, or when specifically allowed by the specification. Contrary to the above, in April 2010 and November 2011, Unit 2 transitioned from Mode 4 to Mode 3 without all required equipment being operable, without performing a risk assessment, and when not allowed by the specification. Specifically, the turbine trip signal from the reactor trip breakers, the turbine trip signal from the reactor trip signal, and the turbine trip signal from a steam generator HI-HI level were all inoperable due to a jumper being

installed for testing when the plant transitioned from Mode 4 to Mode 3. The inspectors used Manual Chapter 0609, Appendix A since the finding was identified after residual heat removal was secured, and determined that the finding was of very low safety significance because the finding did not contribute to both the likelihood of a reactor trip and the loss of mitigation equipment. The licensee entered this issue into the corrective action program as Condition Report 11-27377.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Aguilera, Manager, Health Physics

M. Berg, Manager, Design Engineering

C. Bowman, General Manager, Engineering and Regulatory Affairs

C, Chappell, Licensing

R. Dunn Jr., Manager, Fuels and Analysis

L. Earls, Consultant, Radiation Protection

R. Engen, Site Engineering Director

T. Frawley, Manager, Operations

J. Hartley, Manager, Mechanical Maintenance

J. Heil, Engineering Programs

G. Hildebrandt, Manager, EP/Plant Protection

T. Hurley, Operations Training Supervisor, Requalification

G. Janak, Manager, Unit 1 Operations

B. Jenewein, Manager, Systems Engineering

D. Koehl, President and CEO/CNO

J. Lovejoy, Manager, I&C Maintenance

A. McGalliard, Manager, Areas for Improvement

J. Mertink, Manager, Training and Knowledge Transfer

B. Migl, Manager, Maintenance Engineering (Acting)

J. Milliff, Manager, Unit 2 Operations

M. Murray, Manager, Regulatory Affairs

R. Neimann, Site ANII

J. Paul, Supervisor, Licensing

L. Peter, Plant General Manager

J. Pierce, Manager, Operations Training

G. Powell, Vice President, Generation, Units 1 and 2

D. Rencurrel, Senior Vice President

M. Ruvalcaba, Manager, Testing and Programs

R. Savage, Engineer, Licensing Staff Specialist

M. Schaefer, Manager, Maintenance

K. Silverthorne, Welding, Engineering Programs

S. Sovizral, Manager, Security Operations

L. Spiess, Lead, Inservice Inspection

M. Tomek, ALARA Supervisor, Health Physics

P. Walker, Engineer, Licensing

D. Wiegand, Fire Protection Engineering

J. Williams, Engineering Programs

C. Younger, Engineering Programs

D. Zink, Supervising Engineering Specialist

Attachment 1

NRC Personnel

J. Dixon, Senior Resident Inspector

K. Kennedy, Director, Division Reactor Projects

B. Tharakan, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000498/2012005-01 Failure to Perform Pressure Testing of the Reactor Vessel NCV

05000499/2012005-01 Flange Leak-Off Lines (Section 1R08)

Failure to Follow Procedure for the Control of Tools for Use

05000498/2012005-02 NCV on Stainless Steel (Section 1R08)

05000498/2012005-03 Failure to Maintain Adequate Fire Penetration Seal Material NCV

05000499/2012005-03 Thickness (Section 4OA2)

Closed

Unit 2 Plant Mode Change with Turbine Trip Disabled

05000499/2011-003-000 LER (Section 4OA3)

Managing Gas Accumulation in Emergency Core Cooling, 2515/177 TI Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01) (Section 4OA5)

Inspection of Near-Term Task Force Recommendation 2.3 2515/187 TI Flooding Walkdowns (Section 4OA5)

Inspection of Near-Term Task Force Recommendation 2.3 2515/188 TI Seismic Walkdowns (Section 4OA5)

Attachment 1