IR 05000445/2009006

IR 05000445-09-006, 05000446/2009006; 07/27/09 - 08/14/09; Comanche Peak Steam Electric Station, Biennial Baseline Inspection of the Identification and Resolution of Problems

ML092710287
Person / Time
Site:	Comanche Peak
Issue date:	09/25/2009
From:	Greg Werner NRC/RGN-IV/DRS/PSB-2
To:	Flores R Luminant Generation Co
References
IR-09-006
Download: ML092710287 (28)

Text

UNITED STATES NUC LE AR RE G UL AT O RY C O M M I S S I O N ber 25, 2009

SUBJECT:

COMANCHE PEAK STEAM ELECTRIC STATION -

NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000445/2009006 AND 05000446/2009006

Dear Mr. Flores:

On August 14, 2009, the U. S. Nuclear Regulatory Commission (NRC) completed a team inspection at Comanche Peak Steam Electric Station. The enclosed report documents the inspection findings, which were discussed on August 14, 2009, with Mr. M. Lucas, Site Vice President, and other members of your staff.

The inspection examined activities conducted under your license as they relate to identification and resolution of problems, safety and compliance with the Commissions rules and regulations and with the conditions of your operating license. The team reviewed selected procedures and records, observed activities, and interviewed personnel. The team also interviewed a representative sample of personnel regarding the condition of your safety-conscious work environment.

This report documents one NRC-identified finding of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance of the violation and because it was entered into your corrective action program, the NRC is treating this violation as a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest this non-cited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd., Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at Comanche Peak Steam Electric Station. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at Comanche Peak Steam Electric Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

Luminant Generation Company LLC -2-In accordance with 10 CFR 2.390 of the NRC's 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 NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gregory E. Werner, Chief Plant Support Branch 2 Division of Reactor Safety Dockets: 50-445,05-446 Licenses: NPF-87, NPF-89

Enclosure:

Inspection Report 05000445/20090006; 05000446/2009006 w/Attachments 1. Supplemental Information 2. Initial Information Request

REGION IV==

Dockets: 05000445, 05000446 Licenses: NPF-87, NPF-89 Report: 05000445/2009006 and 05000446/2009006 Licensee: Luminant Generation Company LLC Facility: Comanche Peak Steam Electric Station Location: FM-56, Glen Rose, Texas Dates: July 27 through August 14, 2009 Team Leader: James F. Drake, Senior Reactor Inspector Team: Robert M. Latta, Senior Reactor Inspector Paula A. Goldberg, Reactor Inspector Brian W. Tindell, Resident Inspector Approved By: Gregory E. Werner, Chief Plant Support Branch 2 Division of Reactor Safety-1- Enclosure

SUMMARY OF FINDINGS

IR 05000445/2009006, 05000446/2009006; 07/27/09 - 08/14/09; Comanche Peak Steam

Electric Station, Biennial Baseline Inspection of the Identification and Resolution of Problems The team inspection was performed by two senior reactor inspectors, a reactor inspector, and a resident inspector. One Green non-cited violation of very low safety significance was identified during this inspection. The significance of most findings is indicated by their color (Green,

White, Yellow, Red) using Inspection Manual Chapter 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, Revision 4, dated December 2006.

Identification and Resolution of Problems The team reviewed approximately 300 SmartForms (condition reports), work orders, engineering evaluations, root and apparent cause evaluations, and related supporting documentation to determine if problems were being properly identified, characterized, and entered into the corrective action program for evaluation and resolution. The team reviewed a sample of system health reports, self-assessments, trending reports and metrics, and various other documents related to the corrective action program. Based on these reviews, the inspection team concluded that the implementation of the corrective action program at Comanche Peak nuclear power plant Units 1 and 2 was effective. The team noted a distinct improvement in the quality of the corrective action program between the early portion of the inspection timeframe and the latter portion. The team determined that Comanche Peak staff currently has a low threshold for identifying problems and issues are now prioritized and evaluated commensurate with their safety significance. Corrective actions are now typically implemented in a timely manner and address the identified causes of problems.

There has been a marked improvement in the evaluation of industry operating experience and the licensee used industry operating experience when performing root cause and apparent cause evaluations. However, the team noted potential challenges to timely review of the information contained in operating experience reports because most operating experience reports were classified at the second lowest level of prioritization in the SmartForm processing procedure.

Approximately 20 percent of the operability evaluations reviewed by the team did not contain sufficient documentation to support a reasonable expectation that the system, structure, or component was operable.

The team reviewed approximately 40 quality assurance audits and self-assessments. Based on the results of these reviews, the team concluded the licensee performed effective quality assurance audits and self-assessments, as demonstrated by self-identification of corrective action program weaknesses. In most cases, audits and self-assessments were critical with corrective actions recommended.

Based on 76 interviews, including seven focus groups (consisting of approximately 50 people)conducted during this inspection, observations of plant activities, and reviews of the corrective action and Safeteam (employee concerns) programs, the team determined that site personnel were willing to raise safety issues and document them in the corrective action program. The team observed that workers at the site felt free to report problems to their management and were willing to use the Safeteam Program.

Cornerstone: Mitigating Systems

Green.

The team identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Actions, for the failure of to promptly correct a condition adverse to quality when they did not apply thread sealant to safety-related atmospheric relief valves positioner adjustment screws. This issue was entered into the licensees corrective action program as SmartForm SMF-2009-004054. The licensee took corrective actions by performing an operability determination, which provided reasonable assurance that the atmospheric relief valves were operable and completion of the thread sealant repairs could be reasonably delayed until the next scheduled outage.

The finding was more than minor since it affected the Mitigation System Cornerstone attribute of availability and reliability of mitigating equipment, specifically the operability of the atmospheric relief valves. Using Manual Chapter 0609, Attachment 4, "Phase 1-Initial Screening and Characterization of Findings," the finding was determined to have very low safety significance since it did not result in a loss of the safety system function.

No crosscutting aspect was assigned because this issue was not indicative of current plant performance. (Section 4OA2.5)

Licensee-Identified Violations

None

REPORT DETAILS

4OA2 Problem Identification and Resolution

The team based the following conclusions on a sample of corrective action documents that were initiated during the assessment period, which ranged from September 25, 2007, to the end of the onsite portion of the inspection on August 14, 2009.

.1 Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The team reviewed 300 SmartForms (condition reports), including associated root cause, apparent cause, and direct cause evaluations, from approximately 9,800 that had been issued between September 25, 2007 and August 14, 2009, to determine if problems were being properly identified, characterized, and entered into the corrective action program for evaluation and resolution. The team reviewed a sample of system health reports, operability determinations, self-assessments, trending reports and metrics, and various other documents related to the corrective action program. The team evaluated the licensees efforts in establishing the scope of problems by reviewing selected logs, work requests, self-assessments, audits, system health reports, action plans, and results from surveillance tests and preventive maintenance tasks. The team reviewed work requests and attended the management review committee meetings to assess the reporting threshold, prioritization efforts, and significance determination process, as well as observing the interfaces with the operability assessment and work control processes when applicable. The teams review included verifying the licensee considered the full extent of cause and extent of condition for problems, as well as how the licensee assessed generic implications and previous occurrences. The team assessed the timeliness and effectiveness of corrective actions, completed or planned, and looked for additional examples of similar problems. The team conducted interviews with plant personnel to identify other processes that may exist where problems may be identified and addressed outside the corrective action program.

The team also reviewed corrective action documents that addressed past NRC-identified violations to ensure that the corrective action addressed the issues as described in the inspection reports. The team reviewed a sample of corrective actions closed to other corrective action documents to ensure that corrective actions were still appropriate and timely. The team considered risk insights from both the NRCs and Comanche Peak's risk assessments to focus the sample selection and plant tours on risk significant systems and components. The team selected the following risk significant systems:

auxiliary feed water; and 120, 480 and 6,900 Volt power systems. The samples reviewed by the team focused on, but were not limited to, these systems. The team also expanded their review to include five years of evaluations involving the auxiliary feed water and 480 and 6,900 Volt power systems to determine whether problems were being

effectively addressed. The team conducted walkdowns of these systems to assess whether problems were identified and entered into the corrective action program.

b. Assessments Assessment - Effectiveness of Problem Identification The team concluded that the licensee correctly identified deficiencies that were conditions adverse to quality and entered them into the corrective action program in accordance with the licensees corrective action program guidance and NRC requirements. The team determined that the licensee was typically identifying problems at a low threshold and entering them into the corrective action program. However, the team identified six conditions adverse to quality that were not placed in the corrective action program. These examples were identified by the NRC and are documented in the integrated resident inspection reports. The licensee had written approximately 9,800 SmartForms during the 2-year period of review.

Assessments - Effectiveness of Prioritization and Evaluation of Issues The licensee had weaknesses when performing and/or documenting evaluations of conditions adverse to quality during this assessment period. The team reviewed approximately 100 SmartForms that involved operability reviews and assessments to evaluate the quality, timeliness, and prioritization of operability assessments. The team noted that the immediate and prompt operability assessments reviewed were completed in a timely manner, but frequently failed to fully evaluate all aspects of operability related to the issue. Operability assessments were routinely performed without sufficient engineering rigor, generally involved little discussion about what functions were impacted, and why performance of a component/system was sufficient to fulfill these functions as required by station procedures. The team concluded that the operability assessments that were based on engineering judgment were not identified as such and the procedural requirements for this activity were not followed to confirm that the assumptions were correct. The team also noted that several of the immediate operability assessments did not include adequate justification and documentation to support the conclusions for the prompt operability assessments. Overall, the team determined that both immediate and prompt operability reviews did not include the appropriate technical rigor, as described in the following six examples, to support conclusions as required by station procedures. The team did a detailed reviewed 32 operability assessments during the inspection period and identified 6 that did not include an adequate engineering review.

The licensee had identified that there was a weakness in operability evaluations. This was documented in SmartForm SMF-2008-002551. A recent self-assessment completed June 30, 2009, identified that some improvement had been made in the performance of operability evaluations and determinations, but additional improvement was needed and additional corrective actions have been implemented. This was documented in SmartForm SMF-2009-003220. The team observed that the improvement noted in other areas of the corrective action program was not apparent in the operability evaluations yet.

Examples:

• SmartForm SMF-2007-002909 addressed a nonconformance notification submitted in accordance with 10 CFR Part 21, from Fischer regarding early failure of some diaphragms used in air-operated valves due to inadequate cure time. Failure of the diaphragm would result in valve 2-HV-2452-2, "Turbine-Driven Auxiliary Feedwater Pump Steam Supply Valve," failing to the open position, which is one of its safety-related positions. The licensee's operability determination concluded that since the valve would be in its fail-safe position, the steam admission valve was operable. However, the licensee failed to address the other safety function of the valve as a containment isolation valve in the event of a steam generator tube rupture. If the diaphragm failed, the team noted that the steam admission valve was not capable of performing its safety function of containment isolation during a steam generator tube rupture event. However, the team determined that the licensee's emergency operating procedures provided adequate guidance to operators for isolating the valve in the event of a failure during a steam generator tube rupture event.

• The operability evaluations performed for SmartForms SMF-2009-001632 and SMF-2009-002000, which documented boric acid leaks observed from two containment spray heat exchangers, had simplistic evaluations that did not account for the fact that the leaks had existed for at least 10 years, and provided no technical basis for why it was acceptable to allow the leakage to continue.

The licensee's subsequent operability determination concluded the degradation to affected components was acceptable until at least the next scheduled outage.

• During the performance of a control room positive pressure test, control room pressure dropped below 0.125 WG. The licensee documented this condition on SmartForm SMF-2009-001895. The licensees operability determination stated that the surveillance they were performing contained no acceptance criteria for pressure and therefore did not affect operability. The licensee stated that the system had previously passed Surveillance Requirement SR 3.7.10.4, Tracer Gas Testing, and therefore the system was operable. The evaluation stated that a gravity damper, one of two dampers in series, was stuck open and could not hold differential pressure. The team questioned the operability determination based on single failure criteria. In response to this issue, the licensee concluded that the single failure criteria did not apply to the control room boundary.

However, after additional inquiries by the team, the licensee identified that

Document DBD-ME-003, Control Room Habitability, Section 4.2.1 d stated in part, the Control Room Air Conditioning System pressure boundary dampers should be provided with sufficient redundancy in equipment and power supply to enable the system to sustain a single failure of an active component without compromising Control Room Habitability. (SRP 6.4, Part II.2). If the motor-operated damper is the active failure, and fails open, the gravity damper has to provide the boundary. During the evaluation performed as a result the team's challenge concerning system operability, gravity damper CPX-VADPGU-0-29 was determined to be operable, contrary to the initial evaluation, and able to perform its safety function based on the results of the licensee's boroscopic inspection.

Assessment - Effectiveness of Corrective Action Program Overall, the team concluded that the licensee developed appropriate corrective actions to address problems based on a sample size of 43 SmartForms. Based on the sample reviewed, the team determined that corrective actions were completed in a timely manner. Nonetheless, the team determined that in one instance corrective actions for a previous event were not timely (See Section 4OA2.5).

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The team examined the licensee's program for reviewing industry operating experience, including reviewing the governing procedure and self-assessments. A sample of 49 operating experience reports was reviewed to assess whether the licensee had appropriately evaluated the notification for relevance to the facility. The team then examined whether the licensee had entered those items into their corrective action program and assigned actions to address the issues. The team reviewed a sample of root cause evaluations and corrective action documents to verify that the licensee had appropriately included industry operating experience.

b. Assessment Based on this review, the team determined that there was a lack of documentation regarding the licensee's assessment of the applicability of operating experience to the site and actions taken. In addition, the team found that in the past, operating experience information was not always appropriately considered for applicability and corrective and preventive actions were not always taken as needed. While this was not indicative of current conditions, there was a potential problem with the current revision of Procedure STA-422, CAP, Deficiency Resolution. The operating experience program procedure screens operating experience based upon the potential consequences and the probability of occurrence. However, unless the operating experience notification is a Significant Operating Experience Report, the resulting SmartForms are assigned a Level 4 classification in accordance with guidance provided in Procedure STA-422. A Level 4 SmartForm is defined in Procedure STA-422 as issues that involve a known

level of low risk. Level 4 SmartForms do not require the respondent to perform an extent of condition review to understand the current impact on equipment, but rather are a broke/fix issue; however, some operating experience information may meet the definition of Level 3 priority (i.e., issues that challenge nuclear safety). Of the 49 operating experience reports reviewed in detail, there were 5 instances in which the assessment failed to appropriately consider the industry information and properly prioritize (all were prioritized as Level 4) and evaluate the impact on system operability.

Three examples follow:

• SmartForms SMF-2005-003489 and SMF-2008-002110 evaluated NRC Information Notices 2005-23, Vibration Induced Degradation of Butterfly Valves, and 2008-11, Service Water System Degradation at Brunswick Steam Electric Plant Unit 1, respectively. Comanche Peaks operability statement read in part, SMF is to evaluate the applicability of the OPERATING EXPERIENCE only; there is no impact to equipment operability. The evaluation noted that the loss of taper pins could cause inoperability of the susceptible valves and that there were 218 susceptible valves that were safety-related components. The licensee stated that plant procedures had previously been modified to require constraining taper pins for these valves; however, there was no objective evidence demonstrating that an operability evaluation had been performed as of August 2009. The team questioned whether all valves had been modified since the procedures had been changed to require welding or staking the taper pins.

The licensee's reviews in this area determined that both trains of Unit 2 service water system discharge valves contained the original un-staked taper pins in the valves. The licensee's operability determination concluded that the valves were operable based on the valve design which incorporates three taper pins to secure the disk to the shaft and that they will be able to detect taper pin loss through valve testing.

• SmartForms SMF-2005-002313 and SMF-2008-002110 evaluated operating experience reports concerning the failure of Fisher butterfly valves with a full valve liner. There are similar valves in the service water system at Comanche Peak that use a seat ring. The licensees operability evaluations stated that, if the seat ring failed, the resulting loss in cooling capability would be minimal because of the design margin incorporated into the component cooling water heat exchangers. However, the licensee failed to evaluate the smaller components in the service water system, such as the pump lube oil coolers.

When the team challenged the licensee' assessment, the licensee determined that the service water valve liner was a different material with an estimated useful life of over 40 years.

• SmartForm SMF-2005-002354 documents operating experience regarding magnesium rotor motor-operated valve failures. The operability statement on the SmartForm stated that operability is not affected. A review of operating experience history revealed that there were no motor-operated valves in the industry that failed to perform their function as a result of the above described condition. This statement appears to be incorrect since there have been several

information notices issued documenting failures of magnesium rotor motor-operated valves, as well as additional examples of failures that have been communicated to Comanche Peak as operating experience reports. The corrective actions associated with this SmartForm have been limited to boroscopic inspections of three valves that did not have acceptance criteria documented. At the conclusion of the inspection, the licensee had not determined how many magnesium rotor motor-operated valves are installed in the plant. Similarly, SmartForm SMF-2009-000083 documents additional operating experience on magnesium rotor motor-operated valves. The operability statement stated None. Industry Event. Previous evaluations of this issue have been done. As of August 2009, no evaluation was completed.

Specifically, the population of valves was unknown, the inspection criteria were undocumented, and some magnesium rotor motor-operated valves may have been subjected to stall conditions or located in the vicinity of steam leaks. The team did not identify any documented magnesium rotor motor-operated valves failures at Comanche Peak.

The team noted that root and apparent cause evaluations were required to evaluate whether internal or external operating experience associated with the event or failure being examined was available, and whether the evaluation and actions to address those items had been effective. Additionally, all root cause evaluations reviewed included an assessment as to whether the issue being evaluated had potential application to other similar component or plants.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The team reviewed a sample of 40 licensee self-assessments, surveillances, and audits to assess whether the licensee was regularly identifying performance trends and effectively addressing them. The team reviewed audit reports to assess the effectiveness of assessments in specific areas. The team evaluated the use of self and third-party assessments, the role of the quality assurance department, and the role of the performance improvement group related to licensee performance. The specific self-assessment documents reviewed are listed in the attachment.

b. Assessment The team concluded that the licensee had effective audit and self-assessment processes. The team observed that the licensee's assessment teams included members with the proper skills and experience to ensure effective self-assessments were conducted. The assessments were all self-critical and identified areas for improvement.

.4 Assessment of Safety-Conscious Work Environment

a. Inspection Scope

The inspection team conducted approximately 26 individual interviews and seven focus groups discussions (consisting of approximately 50 people) during this inspection. The team also completed observations of plant activities and reviews of the corrective action and Safeteam (employee concerns) programs. The interviewees represented various functional organizations and ranged across contractor, licensee staff, and supervisor levels. The team conducted these interviews to assess whether conditions existed that would challenge the establishment of a safety-conscious work environment at Comanche Peak.

b. Assessment The licensee maintained a safety-conscious work environment. The team determined that individuals were aware of the importance of nuclear safety, stated a willingness to raise safety issues, had not experienced retaliation in any prior issues raised, and had an adequate knowledge of the corrective action program and Safeteam (Employee Concern Program). In addition, the team noted that the Safeteam had demonstrated effective involvement in raising and addressing concerns.

No findings of significance were identified.

.5 Specific Issues Identified During This Inspection

a. Untimely Corrective Actions For Bailey/Asea Brown Boveri Positioners.

Introduction.

The team identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, for failure to take prompt corrective actions to address inadequate maintenance on a Bailey Type AV1 positioner, which resulted in the loss of one train of shutdown cooling.

Description.

Non-cited Violation 05000445/2007007-02; 05000446/2007007-02 was issued for the failure to provide work instructions or procedures appropriate to the circumstances. Specifically, Work Order 3-05-333517-01 and Procedure INC-2085, ARework and Replacement of I&C [Instrumentation and Control] Equipment,@ Revision 3, directed the replacement of the Bailey Type AV1 positioner for valve 1-HCV-0607, "Residual Heat Removal Heat Exchanger 1-02 Flow Control Valve," but did not contain appropriate instructions for applying thread sealant or other measures to ensure the adjustment screw remained securely in place, despite operational experience in 1999 that indicated this action was necessary. As a result, valve 1-HCV-0607 failed to operate when called upon. The licensee entered the condition into their corrective action program as SmartForm SMF-2007-002087; however, the licensee failed to identify all the safety-related positioners affected.

SmartForm SMF-2007-001250, which addressed the failure of valve 1-HCV-0607 to close while in shutdown cooling mode, made the assumption that the inverted installation of the positioner was a contributing cause to adjustment screw vibrating in, but did not provide any engineering justification. As a result, corrective actions were taken to revise Maintenance Procedure PCN-INC-2085-R3-P6, "Bailey AV1 Positioners,"

which required the application of thread sealant to the adjustment screw following maintenance, and immediately applying thread sealant to the adjustment screws on the Bailey positioners for residual heat removal valves 1-HCV-0607, 1-HCV-0606, 2-HCV-0606, and 2-HCV-0607. These were the only valves which have this positioner model in similar installation configuration (installed upside down). However, the assumption that the inverted installation of the positioner was a contributing cause to adjustment screw vibrating in was not substantiated in any of the operating experience reports available. This information indicates that the adjustment screw can vibrate either direction, which would indicate that the orientation of the positioner might not have been a contributing factor. None of the available operating experience indicated the orientation of the positioners that failed, but information was available that the adjustment screw had vibrated in both directions. However, there are approximately 43 Bailey Type AV1 positioners installed in the plant including the atmospheric relief valves, which are safety-related. The licensee failed to apply thread sealant to the positioner screws for these eight valves and the licensee did not address the operability of these valves. This issue of untimely corrective actions was entered into the licensees corrective action program as SmartForm SMF-2009-004054. The licensee took corrective actions by performing an operability determination, which provided reasonable assurance that the atmospheric relief valves were operable and completion of the thread sealant repairs could be reasonably delayed until the next scheduled outage.

Analysis.

The failure to complete timely corrective actions for a previously identified non-cited violation is a performance deficiency. The finding was more than minor since it affected the Mitigation System Cornerstone attribute of availability and reliability of mitigating equipment, specifically the operability of the atmospheric relief valves. Using Manual Chapter 0609, Attachment 4, "Phase 1- Initial Screening and Characterization of Findings," the finding was determined to have very low safety significance since it did not result in a loss of the safety system function. No crosscutting aspect was assigned because this issue was not indicative of current plant performance.

Enforcement.

Criterion XVI of Appendix B to 10 CFR Part 50 requires, in part, that conditions adverse to quality are promptly identified and corrected. Contrary to this requirement from September 25, 2007, until August 11, 2009, the licensee failed to promptly correct a condition adverse to quality when they did not apply thread sealant to Units 1 and 2 safety-related atmospheric relief valves PV-2325, 2326, 2327, and 2328 positioner adjustment screws. Because this finding was entered into the licensees corrective action program as SmartForm SMF-2009-004054, this violation is being treated as a non-cited violation in accordance with Section VI.A of the NRC Enforcement Policy: NCV 05000445/2009006-01; 05000446/2009006-01, "Untimely Corrective Actions for Bailey/Asea Brown Boveri Positioners."

4OA6 Meetings

Exit Meeting Summary

On August 14, 2009, the team presented the inspection results to Mr. M. Lucas, Site Vice President, and other members of your 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.

4OA7 Licensee-Identified Violations

None ATTACHMENTS:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Back, Operating Experience Program

T. Cerny, Operations Shift Manager

T. Daskam, Regulatory Affairs

T. Gibbs, Safeteam

T. Gilder, Corrective Action Program Manager

J. Henderson, Engineer Smart Team Manager

T. Hope Nuclear Licensing Manager

D. Kross, Plant Manager

M. Lucas, Site Vice President

F. Madden, Director, Nuclear Oversight and Regulatory Affairs

D. McGaughey, Operation Support Manager

G. Mercka, Regulatory Affairs

C. Miller, Reliability Programs Team Supervisor

J. Meyer, Technical Support Manager

M. Pearson, Director, Performance Improvement

W. Reppa, System Engineering Manager

G. Ross, Centers Of Excellence Coordinator

S. Smith Director, Maintenance

J. Taylor, Plant Reliability Manager

D. Walling, Training Manager

D. Wilder, Plant Support Manager

L. Yeager, Design Engineer Analysis Manager

J. Patton, Quality Assurance Manager

NRC personnel

J. Kramer, Senior Resident Inspector

G. Werner, Branch Chief, Plant Support Branch 2

Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened and Closed

05000445/2009006-01; NCV Untimely Corrective Actions For Bailey/Asea Brown Boveri

05000446/2009006-01 Positioners

Closed

None

Discussed

None Attachment 1