IR 05000413/2009002

IR 05000413-09-002, 05000414-09-002, on 01/01/2009 - 03/31/2008, Catawba Nuclear Station, Units 1 and 2; Design Control Integrated Inspection

ML091190050
Person / Time
Site:	Catawba
Issue date:	04/28/2009
From:	Bartley J NRC/RGN-II/DRP/RPB1
To:	Morris J Duke Energy Carolinas, Duke Power Co
References
IR-09-002
Download: ML091190050 (42)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION pril 28, 2009

SUBJECT:

CATAWBA NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000413/2009002, 05000414/2009002

Dear Mr. Morris:

On March 31, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Catawba Nuclear Station Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on April 22, 2009, with Mr. George Hamrick, Engineering Manager, and other members of your staff.

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

This report documents one self-revealing finding of very low safety significance (Green), which was determined to be a violation of NRC requirements. In addition, this report also documents one licensee-identified violation of very low safety significance. However, because of their very low safety significance, and because they were entered into your corrective action program, the NRC is treating these violations as non-cited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest any of the non-cited violations, you should provide a written response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Catawba facility.

DEC 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Jonathan H. Bartley, Chief Reactor Projects Branch 1 Division of Reactor Projects Docket Nos.: 50-413, 50-414 License Nos.: NPF-35, NPF-52

Enclosure:

Integrated Inspection Report 05000413/2009002, 05000414/2009002 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-413, 50-414 License Nos.: NPF-35, NPF-52 Report Nos.: 05000413/2009002, 05000414/2009002 Licensee: Duke Energy Carolinas, LLC Facility: Catawba Nuclear Station, Units 1 and 2 Location: York, SC 29745 Dates: January 1 through March 31, 2009 Inspectors: A. Sabisch, Senior Resident Inspector R. Cureton, Resident Inspector A. Vargas, Reactor Inspector (Sections 1R08, 4OA5.3)

B. Collins, Reactor Inspector (Sections 1R08, 4OA5.3)

Approved by: Jonathan H. Bartley, Chief Reactor Projects Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000413/2009002, 05000414/2009002; 1/1/2009 - 3/31/2009; Catawba Nuclear

Station, Units 1 and 2; Design Control.

The report covered a three month period of inspection by two resident inspectors and two region based inspectors (i.e., two reactor inspectors). One Green NCV was identified as well as one licensee-identified violation. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using IMC 0609, Significance Determination Process. Findings for which the Significance Determination Process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process (ROP),

Revision 4, dated December 2006.

Cornerstone: Mitigating Systems

• Green: A self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion III,

"Design Control," was identified for the failure to translate the design basis for the Component Cooling Water (KC) heat exchanger Nuclear Service Water (RN) outlet control valve and the vendors construction drawings into maintenance procedures to ensure the valve would remain operable over the design lifetime of the component. As a result, the control valve failed and rendered the 1A train of KC inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The failed component was replaced and the valve retested satisfactorily. This issue has been entered into the licensees Corrective Action Program as Problem Investigation Process (PIP) report C-09-0546.

The finding was determined to be more than minor because it is associated with the Mitigating Systems cornerstone of Design Control. The valve failure caused the 1A train of KC to be inoperable for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> which impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events and prevent undesirable consequences. A Phase 2 evaluation was required because the 1B train was also unavailable due to planned maintenance causing a loss of safety function. The finding was determined to be of very low safety significance (Green) using the Phase 2 Worksheets based on the exposure time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This finding was reviewed for crosscutting aspects and none were identified. (Section 4OA3.1)

Other Findings

• One violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspectors. Corrective actions taken by the licensee have been entered into their corrective action program. This violation and the licensees corrective action program tracking number are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period operating at approximately 100 percent Rated Thermal Power (RTP) and remained there for the entire inspection period.

Unit 2 began the inspection period operating at approximately 100 percent RTP. Coast down began on February 23, 2009, and reached 94 percent RTP on March 6, 2009.

The unit was removed from service on March 7, 2009, for the Unit 2 End-of-Cycle (EOC)16 refueling outage.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness

1R01 Adverse Weather Protection

.1 Protection from External Flooding

a. Inspection Scope

The inspectors reviewed the licensees external flood protection features. The inspectors performed a walkdown of external site areas including designated Type I inlet catch basins on-site, which are part of the surface water drainage system designed to protect all safety-related facilities from flooding during a local probable maximum precipitation. This included observing that steel grating on four sides and top of the basins was intact, and to the extent possible, the inspectors visually observed the basin and pipe cavity to determine that the area was free of debris accumulation and no significant blockage of the drains was apparent. The inspectors reviewed the corrective action program documents to ascertain that the licensee was identifying issues and resolving them. The documents reviewed during this inspection are listed in the to this report.

b. Findings

No findings of significance were identified.

.2 Adverse Weather Conditions (Actual)

a. Inspection Scope

The inspectors reviewed the effectiveness of the licensees cold weather protection program pertaining to the cold weather conditions experienced during the period of January 15 - 17, 2009. This included field walkdowns to assess the risk significant freeze protection equipment in the standby shutdown facility, refueling water storage tank, nuclear service water system and turbine buildings. The inspectors discussed specific measures with operations and maintenance personnel to be taken when low ambient temperatures were experienced. A walkdown of control room equipment related to cold weather protection was performed. The inspectors attended the morning Site Direction Meeting where the station procedure for preparing for cold weather conditions was discussed and action items were assigned for completion prior to cold weather arriving on site. The inspectors observed the performance of cold weather rounds performed by Chemistry technicians when ambient temperatures dropped below 20°F. The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns during the five activities listed below to assess the operability of redundant or diverse trains and components when safety-related equipment was inoperable. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures and walked down system components, selected breakers, valves, and support equipment to determine if they were in the correct position to support system operation. The inspectors reviewed protected equipment sheets, maintenance plans, and system drawings to determine if 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. The documents reviewed during this inspection are listed in the Attachment to this report.

• Protection of the 1B Diesel Generator (DG) and Unit B train 4.16kV bus during the period the 1A DG was removed from service for planned maintenance

• Protection of offsite and onsite electrical sources during the Unit 2 2ETA 4.16kV vital bus supply swap over to support the Unit 2 EOC 16 outage

• Protection of 1B train of Component Cooling Water as well as the 1B train of Emergency Core Cooling System (ECCS) during a planned Orange risk activity which included cleaning of the 1A KC Heat Exchanger and work on 1A Residual Heat Removal piping associated with the 1A KC heat exchanger

• Protection of 1A train of KC as well as the 1A train of ECCS during a planned Orange risk activity which included cleaning of the 1B KC Heat Exchanger, preventative maintenance activities on the 1B1 and 1B2 KC pumps and replacement of the actuator arm on the 1RN-351 flow control valve

• Protection of 2B train of KC as well as the 2B train of ECCS during two planned concurrent Orange risk activities which included cleaning of the 2A KC Heat Exchanger and the replacement of nuclear service water piping associated with the essential return header

b. Findings

No findings of significance were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors conducted one detailed walkdown/review involving the alignment and condition of the Unit 2 Auxiliary Feedwater System (CA). The inspectors utilized licensee procedures, as well as licensing and design documents to verify that the system (i.e., pumps, valves, and electrical) alignment was correct. During the walkdowns, the inspectors also verified that: valves and pumps did not exhibit leakage that would impact their function; major portions of the system and components were correctly labeled; hangers and supports were correctly installed and functional; and essential support systems were operational. In addition, pending design and equipment issues were reviewed to determine if the identified deficiencies significantly impacted the systems functions. Items included in this review were: the operator workaround list, the temporary modification list, System and Component Health Reports, and outstanding maintenance work requests/work orders. A review of open PIPs was also performed to verify that the licensee had appropriately characterized and prioritized CA-related equipment problems for resolution in the corrective action program. This inspection sample was completed using the guidance listed in Operating Experience Smart Sample FY2009-02. The documents reviewed during this inspection are listed in the

.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Fire Protection Walkdowns

a. Inspection Scope

The inspectors walked down accessible portions of the five plant areas listed below to assess the licensees control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures. The inspectors observed the fire protection suppression and detection equipment to determine whether any conditions or deficiencies existed which could impair the operability of that equipment. The inspectors selected the areas based on a review of the licensees safe shutdown analysis probabilistic risk assessment and sensitivity studies for fire-related core damage accident sequences. The documents reviewed during this inspection are listed in the Attachment to this report.

• Auxiliary Building 543 foot elevation, Room 200

• Unit 2 B DG room and sequencer hallway

• Main Control Room

• Unit 2 Refueling Water Storage Tank

• Unit 2 Annulus (all elevations)

b. Findings

No findings of significance were identified.

.2 Fire Drill Observations

a. Inspection Scope

The inspectors observed two graded fire drills conducted by the on-shift fire brigade members.

• The drill on January 16, 2009, involved a simulated fire in the Unit 1 A Safety Injection pump room on the 543 foot elevation in the Auxiliary Building

• The drill on February 20, 2009, involved a simulated fire in the Unit 2 vital 4160V switchgear room The purpose of these inspections was to monitor the fire brigades use of protective gear and fire fighting equipment; determine that fire fighting pre-plan procedures and appropriate fire fighting techniques were used; that the directions of the fire brigade leader were thorough, clear and effective, and that control room personnel responded appropriately to the simulated fire events. The inspectors also attended the subsequent drill critiques to assess whether they were appropriately critical, included discussions of drill observations and identified any areas requiring corrective actions. The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance - Annual Review

a. Inspection Scope

The inspectors reviewed the performance of the Unit 2 A Containment Spray (NS) Heat Exchanger heat capacity test and evaluated the test data for acceptable performance.

The inspectors reviewed the system configuration associated with the test, heat load requirements, the methodology used in calculating heat exchanger performance, and the method for tracking the status of tube plugging activities via the data logger and computer processing equipment. The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection (ISI) Activities (IP 71111.08P, Unit 2)

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

a. Inspection Scope

From March 16 - 25, 2009, the inspectors reviewed the implementation of the licensees ISI program for monitoring degradation of the reactor coolant system boundary and risk significant piping boundaries. The inspectors activities consisted of an on-site review of NDE and welding activities to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI (Code of record: 1998 Edition with 2000 Addenda), and to verify that indications and defects (if present) were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI acceptance standards.

The documents reviewed during this inspection are listed in the Attachment to this report.

The inspectors review of NDE activities specifically covered examination procedures, NDE reports, equipment and consumables certification records, personnel qualification records, and calibration reports (as applicable) for the following examinations:

• UT examination of weld 2SM40-01, ASME Class 2, Main Steam System, 34-inch diameter valve-to-pipe weld - Direct Observation

• MT examination of weld 2SM40-01, ASME Class 2, Main Steam System, 34-inch diameter valve-to-pipe weld - Direct Observation

• PT examination of welds 2RPV202-121BSE (RV Hot Leg B Nozzle-to-Safe End),2NC11-01 (RV Hot Leg B Safe End-to-Pipe) and associated adjacent piping, ASME Class 1, Reactor Coolant System, 29-inch diameter welds - Direct Observation The inspectors review of welding activities specifically covered the welding activities listed below in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work orders, repair and replacement plans, weld data sheets, welding procedures, procedure qualification records, welder qualification records, and NDE reports.

• Welding Package for replacement of valve 2NC24-22 (Class 1)

• Welding Package for replacement of valve 2NC33-21 (Class 1)

• Welding Packages for installation of full structural weld overlays (FSWOL) on RV Hot Leg Nozzles (Class 1)

b. Findings

No findings of significance were identified.

.2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

Reactor Vessel Upper Head Penetration activities performed by the licensee during this outage did not fall under the scope of section 02.02 of the inspection procedure.

b. Findings

No findings of significance were identified.

.3 Boric Acid Corrosion Control (BACC) Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walk-down inspections performed during the Unit 1 EOC 17 outage. The inspectors also interviewed the previous BACC program owner and conducted a walk-down of the reactor building to evaluate compliance with licensees BACC program requirements and verify that degraded or non-conforming conditions, such as boric acid leaks identified during the containment walk-down, were properly identified and corrected in accordance with the licensees BACC and corrective action programs.

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

• PIP C-09-00390-01 - Boric Acid Leak Evaluation

• PIP C-09-00545-01 - Boric Acid Leak Evaluation

• PIP C-09-00996-01 - Boric Acid Leak Evaluation

b. Findings

No findings of significance were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The inspectors reviewed the eddy current testing (ECT) activities of Unit 2, A, B, C and D SGs to ensure compliance with Technical Specifications, applicable industry standards, SG Program Procedures, and ASME Code Section XI requirements. The inspectors reviewed the latest Degradation Assessment (DA) report to identify the scope of the inspection and verify it addressed existing and potential degradation mechanisms, plant specific degradation history, and applicable operating experience. The inspectors reviewed portions of the tube inspection plan to verify it complied with the inspections cited in the DA. The inspectors reviewed the licensees Strategic Plan for Steam Generator Integrity to ensure SG tube inspection intervals were in accordance with Electric Power Research Institute (EPRI) Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7. The inspectors selected a sample of site-specific acquisition and analysis Examination Technique Specification Sheets to ensure that equivalency was maintained with the associated qualified Examination Technique Specification Sheets per the EPRI Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7. The inspectors also reviewed the last Condition Monitoring and Operational Assessment report in conjunction with the inspection status reports to assess the licensees prediction capability for expected tube degradation. The inspectors reviewed licensee criteria for tube repair to verify they were consistent with EPRI guidelines. Additionally, the inspectors reviewed documentation to ensure that resolution analysts, ECT probes, and equipment configurations were certified to detect the expected types of SG tube degradation, including performance of a site specific performance demonstration. The inspectors discussed the status of foreign objects, and associated foreign object search and recovery. The inspectors reviewed the licensees Secondary Side Integrity plan, and interviewed plant personnel to ensure compliance with EPRI SG Integrity Assessment Guidelines, Revision 2.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

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

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

The inspectors observed Simulator Scenario S-09 to assess the performance of licensed operators during a training simulator session. The exercise included the failure of the Digital Feedwater Control System requiring manual operator action, a large break Loss of Coolant Accident, failure of safety injection to initiate automatically, transitioning to cold leg recirculation from the containment ECCS sump and the loss of the operable residual heat removal pump requiring implementation of functional recovery procedural guidance. The scenario terminated once the operators realigned the ECCS systems and reestablished cold leg recirculation. The inspection focused on high-risk operator actions performed during implementation of the abnormal and emergency operating procedures, and the incorporation of lessons-learned from previous plant and industry events. The classification and declaration of the Emergency Plan by the Shift Technical Advisor and Operations Shift Manager was also observed during the scenario. The inspectors also attended the subsequent critique to assess whether it was appropriately critical and identified areas requiring corrective actions. The documents reviewed during this inspection are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the two samples listed below for items such as:

(1) appropriate work practices;

(2) identifying and addressing common cause failures;

(3) scoping in accordance with 10 CFR 50.65(b) of the Maintenance Rule;

(4) characterizing reliability issues for performance;

(5) trending key parameters for condition monitoring; (6)charging unavailability for performance;

(7) classification and reclassification in accordance with 10 CFR 50.65(a)(1) or (a)(2); and

(8) appropriateness of performance criteria for Structures, Systems, and Components (SSCs)/functions classified as (a)(2)and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified as (a)(1). For each item selected, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. The documents reviewed during this inspection are listed in the to this report.

• Performance of preventive maintenance work on the 1A DG including removal of the AMOT three-way temperature control valve and replacement of the O-ring based on past operating experience on the 2A DG in 2008

• Performance of maintenance on valve 2CA-62A (Unit 2 A motor drive auxiliary feedwater pump discharge to steam generator isolation valve) and functional testing after the valve failed to open while performing an Inservice Inspection Test

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the following eight activities to determine whether the appropriate risk assessments were performed prior to removing equipment for work.

When emergent work was performed, the inspectors reviewed the risk assessment to determine that the plant risk was promptly reassessed and managed. The inspectors reviewed the appropriate use of the licensees risk assessment tool and risk categories in accordance with Nuclear System Directive 415, Operational Risk Management (Modes 1-3), for appropriate guidance to comply with 10 CFR 50.65 (a)(4). The documents reviewed during this inspection are listed in the Attachment to this report.

• Assessment of the risk resulting from the emergent condition of the failure of the cell switch associated with the Unit 2 A reactor trip bypass breaker

• Re-evaluation of the risk associated with the E Instrument Air (VI) compressor remaining out of service for an additional five days upon discovery of a leak in the after cooler

• Re-evaluation of the planned work activities scheduled for Work Week 4 once adverse weather conditions were predicted for the site

• Review of Unit 2 EOC 16 Refueling Outage Risk Profile prior to the start of the outage

• Review of the planned work activities associated with the annual dual unit Standby Shutdown Facility (SSF) Outage

• Assessment of the planned Orange risk condition resulting from the 1A KC heat exchanger tube cleaning as well as work on the 1A Residual Heat Removal system

• Assessment of the planned Orange risk condition resulting from the 1B KC heat exchanger tube cleaning, preventative maintenance activities on the 1B1 and 1B2 KC pumps and work on valve 1RN-351

• Review of the planned maintenance and modification activities associated with the 2A train of KC and RN which resulted in Unit 2 entering an Orange risk condition

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

For the six operability evaluations listed below, the inspectors evaluated the technical adequacy of the evaluations to determine if TS operability was properly justified and the subject components and systems remained available such that no unrecognized increase in risk occurred. The inspectors reviewed the operability determinations to verify that they were made as specified by Nuclear System Directive (NSD) 203, Operability. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) to determine that the systems and components remained available to perform its intended function. The documents reviewed during this inspection are listed in the to this report.

• PIP C-09-00008; The Unit 1 Loose Parts Monitor tape recorder screen went blank with its ON light lit and the recorder would not turn off

• PIP C-09-00135; Unexpected 2A Reactor Trip Bypass Breaker values obtained during the Unit 2 Reactor Trip Breaker and Solid State Protection System (SSPS)testing

• PIP C-09-00271; Mispositioning of the 2A2 KC Pump Suction Isolation valve 2KC-7 during the performance of the periodic KC pump in-service testing and PIP C-09-00268; 2A2 KC Pump exhibited unusual parameters when started per the in-service test

• PIP C-09-00392; RN flow to the B Control Area Chilled Water chiller exceeded the Hi-Hi alarm setpoint of 2,000 gpm during testing

• PIP C-09-00463; 1B Safety Injection pump inboard seal drain bowl drain line clogged

• PIP C-09-01119; Control Room received a 1B DG annunciator for low jacket water temperature

b. Findings

No findings of significance were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed one permanent plant modification to verify the adequacy of the modification package, and to evaluate the modification for adverse affects on system availability, reliability and functional capability. The documents reviewed during this inspection are listed in the Attachment to this report.

• Reinforcement and modification of the Unit 1 and 2 diesel generator underground fuel oil storage tank fill and vent lines to provide required protection against water intrusion and tornado missiles

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the four post-maintenance tests listed below to determine if procedures and test activities ensured system operability and functional capability. The inspectors reviewed the licensees test procedures to determine if the procedures adequately tested the safety function(s) that may have been affected by the maintenance activities, that the acceptance criteria in the procedures were consistent with information in the applicable licensing basis and/or design basis documents, and that the procedures had been properly reviewed and approved. The inspectors also witnessed the tests and/or reviewed the test data to determine if test results adequately demonstrated restoration of the affected safety function(s). The documents reviewed during this inspection are listed in the Attachment to this report.

• Functional test of the E VI compressor following repair and replacement of a leaking aftercooler gasket

• Performance test of valve 2CA-56 following troubleshooting due to negative trending from past tests

• Performance test following orifice replacement in the steam supply system for Unit 1 turbine driven auxiliary feedwater pump

• Operability run of the SSF diesel generator following annual maintenance activities

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors evaluated licensee outage activities to determine whether the licensee:

considered risk in developing outage schedules; adhered to administrative risk reduction methodologies they developed to control plant configuration; adhered to operating license, TS and Selected Licensee Commitment requirements and procedural guidance that maintained defense-in-depth; and developed mitigation strategies for losses of the key safety functions identified below:

• Decay Heat Removal

• Inventory Control

• Reactivity Control

• Containment Control

• Spent Fuel Cooling

• Power Availability The inspectors reviewed the licensees outage risk control plan to assess the adequacy of the risk assessments that had been conducted and that the licensee had implemented appropriate risk management strategies as required by 10 CFR 50.65(a)(4).

The inspectors reviewed the Just-in-Time training conducted for the shift involved in the unit shutdown on March 4, 2009, which simulated bringing the unit from an initial power level of 91 percent RTP to Mode 3.

On March 6, 2009, the inspectors observed the power reduction process, removing the reactor from service and cooldown from normal operating pressure and temperature to ensure that the requirements in the TS and Selected Licensee Commitments were followed. The inspectors conducted a containment entry once Mode 3 had been reached to observe the condition of major, normally-inaccessible equipment inside containment and review that indications of previously unidentified leakage from the reactor coolant system were not present. An inspection of the reactor vessel head penetrations was made during the containment entry to ensure there were no signs of borated water leakage. The inspectors reviewed the results of the ice condenser material condition inspection performed once Mode 5 was reached to observe the overall material condition in the upper and lower ice condensers, identify any foreign material that was present, and the completed test procedure of the performance of ice condenser lower inlet doors in the as-found conditions. Portions of the cooldown process on March 7, 2009 were also observed to verify that TS cooldown restrictions and administrative guidelines were followed.

The inspectors performed an inspection of the reactor vessel bottom head on March 9, 2009, to determine if any potential leakage had occurred at the welds associated with the bottom head penetrations. This inspection was done in conjunction with the licensees Engineering and Quality Control personnel.

The inspectors observed the items or activities described below, to substantiate that the licensee maintained defense-in-depth commensurate with the outage risk control plan for the key safety functions identified above and applicable TS when taking equipment out of service.

• Reactor Coolant System instrumentation

• Realigning electrical power

• Establishing and maintaining Decay Heat Removal

• Maintaining Spent Fuel Pool cooling

• Inventory control

• Controlling reactivity

• Establishing and maintaining Containment closure The inspectors reviewed the licensees responses to emergent work and unexpected conditions, to establish that resulting configuration changes were controlled in accordance with the outage risk control plan.

The inspectors observed the removal of the reactor vessel head to ensure the lift was conducted in accordance with the recently revised procedures that incorporated the guidance for the head lift supported by the new head drop analysis performed by Westinghouse.

The inspectors observed fuel handling operations during new fuel receipt, movement into the spent fuel pool and core offload to determine that those operations and activities were being performed in accordance with TS and procedural guidance. Additionally, the inspectors observed refueling activities to substantiate that the location of the fuel assemblies was tracked through core offload.

Prior to mode changes and on a sampling basis, the inspectors reviewed system lineups and/or control board indications to substantiate that TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant configurations. Also, the inspectors periodically reviewed the setting and maintenance of containment integrity, to establish that the Reactor Coolant System and containment boundaries were in place and had integrity when necessary.

Periodically, the inspectors reviewed the items that had been entered into the licensees corrective action program, to establish that the licensee had identified problems related to outage activities at an appropriate threshold and had entered them into the corrective action program.

The documents reviewed in support of the Unit 2 EOC 16 refueling outage are listed in the attachment to this report.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the ten tests listed below, the inspectors witnessed testing and/or reviewed the test data, to determine if the SSCs involved in these tests satisfied the requirements described in the TS, the UFSAR, and applicable licensee procedures, and that the tests demonstrated that the SSCs were capable of performing their intended safety functions.

Surveillance Tests

• PT/2/A/4600/001; RCCA Movement Test, Rev. 034

• PT/1/A/4350/002A; Diesel Generator 1A Operability Test, Rev. 119

• PT/1/A/4200/013E; CA Valve Inservice Test, Enclosures 13.3, 13.9, 13.11 and 13.17 (performed following work on the system), Rev. 087

• OP/2/A/6200/032; Primary Sampling Using a Rheodyne Model 7010 Valve, Rev. 012

• MP/0/A/7150/072; Main Steam Safety Valve Setpoint Test, Rev. 018 Leakage Detection

• PT/1/A/4150/001D; NC System Leakage Calculation, Rev. 062 Containment Isolation Valve Test

• PT/2/A/4200/001 I; As Found Containment Isolation Valve Leak Rate Test, 13.25 (Penetration No. M358 As-found Type C Leak Rate Test) Rev. 015

• PT/2/A/4200/001 I; As-found Containment Isolation Valve Leak Rate Test, Enclosure 13.47 (Penetration No. CNIP-2EMF(OUT) As-found Type C Leak Rate Test),

Rev. 015 Ice Condenser Surveillance

• MP/0/A/7150/006; Ice Condenser Lower Inlet Doors Inspection and Testing (As-found testing), Rev. 029 Inservice Testing

• PT/2/A/4200/013 E; CA Valve Inservice Test, Enclosure 13.15 (2CA-60 Valve Inservice Test), Rev. 061

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator Verification

a. Inspection Scope

The inspectors sampled licensee data to confirm the accuracy of reported performance indicator (PI) data for the five indicators during periods listed below. To determine the accuracy of the report PI elements, the reviewed data was assessed against PI definitions and guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Rev. 5. Additional documents reviewed during this inspection are listed in the Attachment to this report.

Cornerstone: Initiating Events

• Unplanned Scrams with Complications, Unit 1

• Unplanned Scrams with Complications, Unit 2 The inspectors reviewed the Unplanned Scrams with Complications Performance Indicator results for the period of January 1, 2008 through December 31, 2008 for Unit 1 and Unit 2. The inspectors reviewed operating logs, PIPs, and monthly operating reports to identify the number of unplanned scrams while critical, both manual and automatic, during the previous four quarters, that required additional operator actions, and determined whether the data reported for the PI corresponded to the performance of both units during that time period. The documents reviewed during this inspection are listed in the Attachment to this report.

Cornerstone: Barrier Integrity

• Reactor Coolant System Activity, Unit 2 The inspectors reviewed the Reactor Coolant System Specific Activity PI results for the period of January 1, 2007 through December 31, 2008, for Unit 2. The inspectors observed licensee sampling and analysis of reactor coolant system samples, and compared the licensee-reported performance indicator data with records developed by the licensee while analyzing previous samples. The inspectors also reviewed the PIPs associated with this area to determine that the licensee identified and implemented appropriate corrective actions. The documents reviewed during this inspection are listed in the Attachment to this report.

Cornerstone: Mitigating Systems

• Mitigating Systems Performance Index - Cooling Water Systems, Unit 1

• Mitigating Systems Performance Index - Cooling Water Systems, Unit 2 The inspectors reviewed the licensees procedures and methods for compiling and reporting the Performance Indicators including the Reactor Oversight Program Mitigating Systems Performance Indicator (MSPI) Basis Document for Catawba. The inspectors reviewed the raw data for the PIs listed above for the period of January 1, 2008, through December 31, 2008. The inspectors also independently screened Technical Specification Action Item Logs, selected control room logs, work orders and surveillance procedures, and maintenance rule failure determinations to determine if unavailability/unreliability hours were properly reported. The inspectors compared the licensees raw data against the graphical representations and specific values contained on the NRCs public web page for 2008. The inspectors also reviewed the past history of PIPs for systems affecting the MSPI indicators listed below for any that might have affected the reported values. The inspectors reviewed Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, to verify that industry reporting guidelines were applied. Additional documents reviewed during this inspection are listed in the Attachment to this report

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Review

As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed screening of items entered into the licensees corrective action program. This was accomplished by reviewing copies of PIPs, attending selected daily Site Direction and PIP screening meetings, and accessing the licensees computerized database.

.2 Annual Sample Review

a. Inspection Scope

(Operator Workaround)

The inspectors reviewed the cumulative effects of deficiencies that constituted operator workarounds to determine whether or not they could: affect the reliability, availability, and potential for misoperation of a mitigating system; affect multiple mitigating systems; or affect the ability of operators to respond in a correct and timely manner to plant transients and accidents. The inspectors also assessed whether operator workarounds were being identified and entered into the licensees corrective action program at an appropriate threshold

b. Findings

No findings of significance were identified.

4OA3 Event Followup

.1 Failure of the actuating arm on the Nuclear Service Water flow control valve associated

with the 1A Component Cooling Water heat exchanger

a. Inspection Scope

The inspectors reviewed the licensee's response to and corrective actions taken in response to the January 30, 2009, failure of the Nuclear Service Water outlet throttle valve from the 1A KC heat exchanger (1RN-291). The failure was discovered when the train was placed in service and with the valve indicating open with no flow was indicated through the heat exchanger. The actuator arm for the valve had failed which allowed the air operator to go full open while the valve itself went full closed. The inspectors reviewed the immediate actions taken including protecting the opposite train, reviewing the work schedule for any activities that could increase the unit risk profile and implementation of corrective actions to repair the failed actuator. The documents reviewed during this inspection are listed in the attachment to this report.

b. Findings

Introduction:

A self-revealing Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," was identified for the failure to translate the design basis for the KC heat exchanger RN outlet control valve and the vendors construction drawings into maintenance procedures to ensure the valve would remain operable over the design lifetime of the component.

Description:

On January 30, 2009, the 1A train of KC was being placed in service as part of a planned train swap. When the KC heat exchanger RN outlet control valve was opened from the control room, an open indication was received; however, no flow was indicated on the plant computer or control board gauge. It was determined that the actuator arm connecting the air operator to the valve stem had failed causing the valve to remain in the closed position. A subsequent review of the plant computer revealed that the failure had actually occurred on January 28, 2009. However, since the failure did not produce an alarm or any changes in system parameters since the 1A train was not in operation, it remained undetected until a demand was placed on it by control room personnel. The failed actuator arm assembly was replaced and the 1A train of KC declared operable on January 31, 2009.

Vendor drawings originally supplied with the valve showed the actuator arm as being an assembly component; however, the licensee failed to recognize that aspect of the valve's construction and determine that periodic replacement of the sub-components was required, even though the construction drawing supplied by the vendor recommended stocking a replacement actuator arm assembly. Following discussions with the valve supplier and manufacturer of the failed sub-component, the licensee has revised the preventive maintenance program covering valves of similar design. The actuator arms will be replaced on a set frequency based on the input received from the vendor and is intended to prevent the sudden failure of the component in the future.

Analysis:

The licensees failure to translate the design basis for the KC heat exchanger RN outlet control valve and the vendors construction drawings into maintenance procedures to ensure the valve would remain operable over the design lifetime of the component was a performance deficiency. The finding was determined to be more than minor because it is associated with the Mitigating Systems cornerstone of Design Control. It impacted the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events and prevent undesirable consequences. The failure to maintain the valve actuator arm resulted in a train of safety-related equipment being rendered inoperable, which was determined to be a safety system functional failure.

Using the MC 0609, "Significance Determination Process," Phase 1 Worksheet, the inspectors concluded that a Phase 2 evaluation was required because the finding resulted in a loss of safety function. The inspectors performed a Phase 2 analysis using Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations," of IMC 0609, "Significance Determination Process," and the Phase 2 Worksheets for Catawba Nuclear Station. The finding was determined to be of very low safety significance (Green) upon completion of the Phase 2 evaluation after completing the applicable counting rule worksheets based on the length of time the one train of KC was unavailable.

Enforcement:

Part 50 of Title 10 of the Code of Federal Regulations, Appendix B, Criterion III, Design Control, requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis for systems, structures and components are correctly translated into specifications, drawings, and procedures. Design control measures shall be applied to items such as stress, compatibility of materials; accessibility for maintenance and repair; and delineation of acceptance criteria for inspections and tests.

Contrary to the above, as of January 30, 2009, the licensee failed to correctly translate the design basis for the KC heat exchanger RN outlet control valve and the vendors construction drawings into maintenance procedures to ensure the valve would remain operable over the design lifetime of the component. As a result, the valve actuator arm was not designated as requiring periodic replacement and failed unexpectedly causing the 1A train of KC to be rendered inoperable for a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> period. Because this violation was of very low safety significance and has been entered into the licensees corrective action program as PIP C-09-0546, it is being treated as a non-cited violation consistent with Section VI.A of the NRC Enforcement Policy: NCV 0500413/2009002-01, Failure to translate design requirements into a maintenance program to ensure Component Cooling Water system operability was maintained over the design life of the plant.

.2 (Closed) Licensee Event Report (LER) 05000414/2007002-00: Technical Specification

Violation Associated with Containment Valve Injection Water System On October 7, 2007, calibration of Containment Valve Injection Water System (CVIWS)surge chamber 2A level transmitter 2NW-LT5020 was being performed. It was observed that the transmitters loop output began to drop steadily after the transmitter was returned to service following its calibration. An investigation revealed that CVIWS surge chamber 2A narrow range level high pressure root isolation valve 2NWIV5020 was closed, rendering the A train of CVIWS inoperable due to a loss of its automatic make up function. Further investigation concluded that the valve was closed during the previous outage and not reopened as required for operability. During the time period that the valve was closed, the unit was in violation of TS 3.6.17, Containment Valve Injection Water System (CVIWS). There were also two instances in which the unit violated TS LCO 3.0.3 due to having the opposite train inoperable for longer than the allowed LCO time. The LER and supporting documents were reviewed by the Resident Inspectors.

The inspectors walked down the affected surge chamber and stepped through the procedure that had been used in the 2006 refueling outage. These actions were taken to assess the licensees cause analysis that had been performed in response to the event. The enforcement aspects of this finding are discussed in Section 4OA7 of this report. The documents reviewed during this inspection are listed in the attachment to this report. This LER is closed.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

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

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

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews and inspection activities.

b. Findings

No findings of significance were identified.

.2 (Closed) NRC Temporary Instruction (TI) 2515/176, EDG TS Surveillance Requirements

Regarding Endurance and Margin Testing Inspection activities for TI 2515/176 were previously completed and documented in inspection report 05000413,414/2008004, and this TI is considered closed at Catawba Nuclear Station; however, TI 2515/176 will not expire until August 31, 2009. The information gathered while completing this temporary instruction was forwarded to the Office of Nuclear Reactor Regulation for review and evaluation.

.3 NRC TI 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds (DMBWs)

a. Inspection Scope

From March 16-25, 2009, the inspectors reviewed the licensees activities related to the inspection and mitigation of DMBWs in the reactor coolant system to ensure that the licensee activities were consistent with the industry requirements established in the Materials Reliability Program (MRP) document MRP-139, Primary System Piping Butt Weld Inspection and Evaluation Guidelines, July 2005. This inspection was limited to review and observation of overlay activities being performed on the reactor vessel hot leg nozzles.

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

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

b. Findings

No findings of significance were identified.

MRP-139 Baseline Inspections 1) Have the baseline inspections been performed or are they scheduled to be performed in accordance with MRP-139 guidance Yes. The licensee has performed all required baseline inspections at the time of this review. The licensee performed baseline inspections of the reactor vessel hot leg nozzle welds during this outage (spring 2009), but this occurred after the inspection was complete, so these exams were not inspected.

No follow-on exams occurred since the baseline inspections had been performed, and based on the categorization of the welds in the program, no follow-on exams were required to have been completed at the time of the inspection.

Therefore, the licensee has met the MRP-139 deadlines for baseline examinations of all welds scoped into the MRP-139 program.

2) Is the licensee planning to take any deviations from MRP-139 requirements?

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

Volumetric Examinations Sample not available.

Weld Overlays Activities associated with the weld overlay of the reactor vessel hot leg nozzles were inspected.

1) For each weld overlay inspected, was the activity performed in accordance with ASME Code welding requirements and consistent with NRC staff relief requests authorizations? Has the licensee submitted a relief request and obtained Office of Nuclear Reactor Regulation (NRR) staff authorization to install weld overlays?

The licensee had submitted a relief request and obtained NRR approval to install weld overlays on the reactor vessel hot leg nozzles. The licensee attempted to install these overlays, but problems encountered during the process resulted in the licensee stopping the process and backing out of the overlay procedure. To do so, the licensee addressed the configuration which would meet all applicable requirements. This approach included use of ASME Code as well as a separate relief request than the one originally requested for the weld overlay process. At the time of this report, the licensee was in the process of submitting said request.

During the process of the attempted installation, activities were performed in accordance with ASME Code Section XI, Code Case N504-2, Code Case N638-1, Code Case N740 and the proposed alternative authorization. The inspectors directly observed welding activities and reviewed welding procedure specifications, procedure qualification records, weld wire certifications and the in-process welding process control sheets for compliance to ASME Section IX requirements and adherence to the proposed alternative. The inspectors also evaluated corrective action program documents, and third party contractor corrective action process issue reports regarding weld overlay quality issues.

For the items inspected, the licensee complied with the applicable requirements.

2) For each weld overlay inspected, was the activity performed by qualified personnel?

Yes, welding personnel were qualified in accordance with the requirements identified in ASME Code Section IX. The inspectors reviewed the welder performance qualification test records and compared them with the requirements of QW-300.

The in-process welding process control sheets were reviewed for compliance with the proposed alternative and ASME Code Section IX requirements.

3) For each weld overlay inspected, was the activity performed such that deficiencies were identified, dispositioned, and resolved?

Yes, the inspectors reviewed documentation to verify that deficiencies were identified, dispositioned, and resolved. Based on inspection activities, the inspectors determined that the installation of the FSWOL was conducted in a manner such that deficiencies were identified, dispositioned and resolved.

However, the licensee is in the process of determining the root cause(s) of the deficiencies at the time of this report. Further resolution may be required as a result of identifying the cause(s), therefore this step is not complete at the time of this report.

Mechanical Stress Improvement (Not Applicable)

Sample not available.

In-service Inspection Program This reporting requirement was addressed previously in inspection report 2008003; no new information was noted during this inspection.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 22, 2009, the resident inspectors presented the inspection results to Mr. George Hamrick, Engineering Manager, and other members of licensee management, who acknowledged the findings. The inspectors confirmed that any proprietary information provided or examined during the inspection period had been returned.

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 met the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.

TS 3.6.17, Containment Valve Injection Water System (CVIWS), requires, in part, that two trains of CVIWS shall remain operable when in Modes 1 through 4. Additionally, TS 3.6.17 requires that with one train of CVIWS inoperable it should be restored within 7 days; otherwise the unit must be placed into Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. TS 3.0.3 states, in part, that when an associated action is not provided, the unit shall be placed in a mode in which the LCO is not applicable. Action shall be initiated to place the unit, as applicable, into Mode 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, Mode 4 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and Mode 5 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. Contrary to the above, on October 7, 2007, the licensee identified that the 2A CVIWS surge tank level transmitter, used for automatic emergency make up, had been isolated over an 18 month time period rendering the 2A train inoperable for longer than its prescribed Action Statement time of 7 days. During this time there were also two instances where the 2B train of CVIWS was removed from service for a time period exceeding the TS 3.0.3 Action Statement time. The inspectors determined this finding to be of very low safety significance using Phase 2 Screening Table 6.2 of IMC 0609 Appendix H, Containment Integrity Significance Determination Process. This was based on the fact that during the 18 month period operators had redundant level indication in the control room with the ability to manually make up to the surge chamber if required. This issue is documented in the licensees corrective action program as PIP C-07-05847.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Arlow, Emergency Planning Manager

G. Bartosch, BACCP Program Owner

S. Beagles, Chemistry Manager

D. Brenton, Operations Superintendent

J. Bumgarner, ISI & Welding Services Supervisor

W. Byers, Security Manager

J. Caldwell, Modifications Engineering Manager

B. Callaway, RPV Head Exams

C. Cauthen, SGISI

S. Coy, Operations Training Manager

P. Downing, Duke Corporate SGISI

J. Ferguson, Mechanical, Civil Engineering Manager

J. Foster, Radiation Protection Manager

T. Hamilton, Safety Assurance Manager

G. Hamrick, Engineering Manager

R. Hart, Regulatory Compliance Manager

A. Hogge, Duke Corporate ISI

T. Jenkins, Work Control Manager

D. Llewellyn, Alloy 600 Program Manager

J. McConnell, Shift Operations Manager

N. Mohr, Site Welding Engineer

J. Morris, Catawba Site Vice President

J. Pitesa, Station Manager

T. Ray, Maintenance Manager

M. Sawicki, Regulatory Compliance Engineer

E. Sherwood, Site Welding Supervisor

G. Spurlin, Licensed Operator Requalification Supervisor

C. Trezise, Reactor and Electrical Systems Manager / Acting Engineering Manager

D. Ward, Civil Engineering Supervisor

R. Weatherford, Training Manager

Other

B. Acree, Welding Services, Inc.

M. Sciacca, Welding Services, Inc.

NRC personnel

J. Stang, Project Manager, NRR

J. Thompson, Project Manager, NRR

LIST OF ITEMS

OPENED, CLOSED, AND REVIEWED

Opened and Closed

050000413,414/2009002-01 NCV Failure to translate design requirements into a maintenance program to ensure Component Cooling Water system operability was maintained over the design life of the plant (Section 4OA3.1)

Discussed

2515/172 TI NRC Temporary Instruction (TI) 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds (Section 4OA5.3)

Closed

05000414/2007002-00 LER Technical Specification Violation Associated with Containment Valve Injection Water System (Section 4OA3.2)

2515/176 TI EDG TS Surveillance Requirements Regarding Endurance and Margin Testing (Section 4OA5.2)