IR 05000315/2013007

IR 05000315-13-007; 05000316-13-007; 08/26/2013 & 09/13/2013; D. C. Cook Nuclear Power Plant, Units 1 and 2; Biennial Problem Identification and Resolution (Pi&R) Inspection

ML13301A635
Person / Time
Site:	Cook
Issue date:	10/28/2013
From:	Jamie Benjamin Division Reactor Projects III
To:	Weber L Indiana Michigan Power Co
References
EA-06-295 IR-13-007
Download: ML13301A635 (25)

Text

ber 28, 2013

SUBJECT:

D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2 - BIENNIAL PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000315/2013007 AND 05000316/2013007

Dear Mr. Weber:

On September 13, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed a problem identification and resolution (PI&R) biennial inspection at D. C. Cook Nuclear Power Plant, Units 1 and 2, and discussed the results of this inspection with Mr. S. Lies and other members of your staff. The inspection team documented the results of this inspection in the enclosed inspection report.

Based on the inspection sample, the inspection team determined that your staffs implementation of the corrective action program supported nuclear safety. In reviewing your corrective action program, the team assessed how well your staff identified problems at a low threshold, your staffs implementation of the stations process for prioritizing and evaluating these problems, and the effectiveness of corrective actions taken by the station to resolve these problems. In each of these areas, the team determined that your staffs performance was adequate to support nuclear safety.

The team also evaluated other processes your staff used to identify issues for resolution. These included your use of audits and self-assessments to identify latent problems and your incorporation of lessons learned from industry operating experience into station programs, processes, and procedures. The team determined that your stations performance in each of these areas supported nuclear safety.

Finally, the team determined that your stations management maintains a safety-conscious work environment adequate to support nuclear safety. Based on the teams observations, your employees are willing to raise concerns related to nuclear safety through at least one of the several means available. The inspection also confirmed your implementation of two items from a confirmatory order issued to you by the NRC on April 7, 2007. We independently inspected records of completed activities and determined that your actions were in compliance with the requirements delineated in the confirmatory order. The NRC has no further questions on this issue.

Based on the results of this inspection, no findings were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and 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 System (PARS)

component of NRC's Agencywide Documents Access and Management System (ADAMS),

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Jamie Benjamin, Acting Chief Branch 4 Division of Reactor Projects Docket Nos. 50-315; 50-316 License Nos. DPR-58; DPR-74

Enclosure:

Inspection Report 05000315/2013007; 05000316/2013007 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-315; 50-316 License Nos: DPR-58; DPR-74 Report No: 05000315/2013007; 05000316/2013007 Licensee: Indiana Michigan Power Company Facility: D. C. Cook Nuclear Power Plant, Units 1 and 2 Location: Bridgman, MI Dates: August 26, 2013, through September 13, 2013 Inspectors: J. Lennartz, Project Engineer P. LaFlamme, Resident Inspector A. Dunlop, Reactor Engineer J. Maynen, Senior Physical Security Inspector Approved by: Jamie Benjamin, Acting Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000315/2013007; 05000316/2013007; 08/26/2013 - 09/13/2013;

D. C. Cook Nuclear Power Plant, Units 1 and 2; Biennial Problem Identification and Resolution (PI&R) Inspection.

This inspection was performed by three NRC regional inspectors and the D. C. Cook Nuclear Plant resident inspector. No findings of significance or violations of NRC requirements were identified during this inspection. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

Problem Identification and Resolution On the basis of the sample selected for review, the inspection team concluded that the corrective action program (CAP) at the D. C. Cook Nuclear Plant was generally being implemented in an effective manner. Licensee personnel had a low threshold for identifying problems and entering them in the CAP. Items entered into the CAP were screened and prioritized in a timely manner using established criteria; were properly evaluated commensurate with their safety significance; and, corrective actions were generally implemented in a timely manner, commensurate with the safety significance. The team noted that the licensee reviewed operating experience (OE) for applicability to station activities and that, in general, OE was effectively utilized. Audits and self-assessments were generally thorough and intrusive, and performed at an appropriate level to identify deficiencies. Based on the interviews conducted during the inspection, the team concluded that an acceptable safety conscious work environment had been established. Workers at the site expressed freedom to raise concerns related to nuclear safety; and, workers were aware of and generally familiar with the CAP process and other processes, including the employee concerns program, which could be used to raise safety concerns.

Although CAP implementation was determined to be generally effective, the team identified several issues that represented potential deficiencies, which were all determined to be of minor significance.

NRC-Identified

and Self-Revealed Findings None

Licensee-Identified Violations

None

REPORT DETAILS

4OA2 Problem Identification and Resolution

This inspection constituted one biennial sample of problem identification and resolution (PI&R) as defined in Inspection Procedure 71152, Problem Identification and Resolution. Documents reviewed are listed in the Attachment to this report.

.1 Corrective Action Program Effectiveness

a. Inspection Scope

The inspector reviewed the licensees corrective action program (CAP) implementing procedures and interviewed licensee personnel to assess CAP implementation. The inspectors also observed and assessed the effectiveness of CAP related meetings, which included the initial screening and management screening committee meetings; the corrective action review board meeting; the operating experience screening meeting; and the work assessment group meeting.

The inspectors reviewed risk and safety significant action requests (ARs) entered into the licensees CAP since the last NRC PI&R inspection in May 2011. The ARs reviewed included a sampling of issues identified through NRC generic communications, licensee audits and self-assessments, operating experience reports, NRC documented findings, and licensee identified violations. The inspectors also reviewed ARs for selected systems, structures and components or functions classified as (a)(1) status in accordance with the maintenance rule (10 CFR 50.65). The ARs selected ensured an adequate review across NRC cornerstones and included completed root cause, apparent cause, equipment apparent cause, in-depth apparent cause, and common cause evaluations.

Based on input from the resident staff, the inspectors selected mechanical maintenance performance and licensee oversight of contract/vendor supplemental workers over the past five years for in-depth reviews. The mechanical maintenance performance review focused on maintenance deficiencies resulting in rework on plant equipment; included a detailed look at AR 2013-7523, U1C25 Rework Common Cause Analysis, which evaluated repeat maintenance issues identified by the licensee over the past three refueling outages; and included interviews with several mechanical maintenance personnel. The licensee oversight of supplemental workers review focused on the training that individuals overseeing the supplemental workforce received; the use of supplemental workers to complete Fast Track projects; and, the trend analyses completed by the licensees Performance Assurance organization regarding the use of supplemental workers. The inspectors reviewed selected ARs and the licensees procedures for the oversight and use of supplemental workers. The inspectors also conducted interviews with licensee personnel responsible for implementing the training and oversight procedures. These in-depth reviews were conducted to determine whether the licensee was properly evaluating and taking appropriate corrective actions for issues related to maintenance performance and oversight of supplemental workers to limit the likelihood that human or equipment performance issues could impact nuclear safety.

During the reviews, the inspectors determined whether licensee personnel actions were in compliance with the CAP implementing procedures and 10 CFR Part 50, Appendix B requirements. Specifically, the inspectors assessed whether licensee personnel identified issues at a proper threshold; whether identified issues were being entered into the CAP in a timely manner with the appropriate characterization; and, whether identified issues were appropriately prioritized to resolve the issues. The inspectors determined whether licensee personnel assigned the appropriate evaluation method to ensure that the correct root, apparent, and contributing causes were identified; verified that issues were appropriately evaluated with respect to the maintenance rule and operability; and, assessed the evaluations scope and depth. The inspectors also evaluated the timeliness and effectiveness of corrective actions. For significant conditions adverse to quality the inspectors assessed the corrective actions to prevent recurrence. For less significant issues the inspectors verified that the corrective actions were implemented in a timely manner commensurate with their safety significance.

b. Assessment

(1) Effectiveness of Problem Identification The inspectors concluded that problem identification was generally effective. Based on the information reviewed, the inspectors determined that licensee personnel have a low threshold for initiating ARs; a high percentage of identified problems are being identified by licensee personnel; licensee personnel appropriately screened issues from both the NRC and industry operating experience at an appropriate level and entered them into the CAP when applicable; and, identified problems were generally entered into the CAP in a complete, accurate and timely manner.

However, the inspectors noted a vulnerability regarding trending, as discussed below, which could potentially result in adverse trends not being identified.

Observations Failure to Add Appropriate Trending Codes to ARs Following Review The inspectors noted a vulnerability regarding AR trend coding while reviewing cause evaluations. Specifically:

• In-depth apparent cause evaluation (IACE), AR 2012-2189, Unit 1 Power Range Drawer Calibration Came into Question, identified human performance decision making and questioning attitude as elements in the apparent cause. However, no human performance trend codes were added to the AR after the IACE was completed.

• Trend assessment evaluation AR 2012-2738, Adverse Trend in Roll-Up Code NS7, concluded that half of the reviewed events could be attributed to equipment age. However, no age related trend codes were added to any of the ARs that were reviewed to assess the trend and reach that conclusion.

The inspectors noted that procedure PMP-7030-TND-001, Trend Analysis, specified to create a tracking assignment if inappropriate codes identified during evaluations were to be removed from ARs. However, the procedure did not specify to add the appropriate trend codes to ARs following evaluations. Consequently, a subsequent trend analysis search may not capture the entire population of ARs if the appropriate trend code was not added. Therefore, an adverse trend that could potentially impact nuclear safety may not be identified. The inspectors did not identify any adverse trends that had been missed and therefore concluded that this issue was of minor significance. Licensee personnel documented this issue in AR 2013-13735, Trend Procedure does not Direct Code Adjustments.

Findings No findings were identified.

(2) Effectiveness of Prioritization and Evaluation of Issues The inspectors concluded that identified problems were generally prioritized and evaluated commensurate with the safety significance, including an appropriate consideration of risk. Higher level evaluations, such as root cause and in-depth apparent cause, were generally technically accurate; of sufficient depth to effectively identify the cause(s); and, adequately considered extent of condition, generic implications and previous occurrences. However, the inspectors noted some inconsistencies between various vendor documents and a root cause evaluation regarding the Unit 1 steam generator tube wear indications, which are discussed as observations below.

The inspectors determined that the initial and management screening committee meetings, as well as the corrective action review board meeting, were generally thorough and meeting participants were actively engaged and well prepared. Initial screening and management screening meetings accurately prioritized issues.

Corrective action review board members discussed selected issues in sufficient detail and challenged presenters regarding their conclusions and recommendations.

The inspectors determined that the licensee usually evaluated equipment operability and functionality requirements adequately after a degraded or non-conforming condition was identified. In general, appropriate actions were assigned to correct the degraded or non-conforming condition. However, the inspectors identified one maintenance rule evaluation that failed to identify a functional failure and one operability evaluation that inappropriately used information from a previous evaluation to support the conclusion.

In addition, the inspectors identified a vulnerability regarding prioritization of some plant equipment with regulatory functionality requirements. These issues, which were determined to be of minor significance, are discussed as observations below.

Observations Unit 1 Steam Generator Root Cause Evaluation The inspectors reviewed a root cause evaluation (AR 2011-11547) that was conducted to address the unexpected increase in the number of Unit 1 steam generator tube to fan bar wear indications. These indications were identified by eddy current testing during the 2011 refueling outage.

The inspectors reviewed the licensees assumptions and evaluations, as well as available operating experience and supporting vendor documentation. The inspectors noted several inconsistencies between the various vendor documents and the root cause evaluation, which were material to the conclusions reached and the corrective actions proposed. These inconsistencies included:

• The root cause evaluation stated different steam generator operating resonant bands throughout the report and never established conclusively what the actual band is.

• The root cause stated that raising the steam pressure and temperature will correct the current condition; however, the report also stated that the Unit 1 steam generators behavior is counterintuitive, because rather than wear decreasing with an increase in pressure, based on the accumulated data, wear increased.

Through questioning of licensee personnel and reviews of additional documentation provided by the licensee, the inspectors subsequently determined that the inconsistencies were adequately clarified. In addition, the licensee described the analyses and evaluations being performed to support the adequacy of the proposed corrective actions.

Because licensee personnel satisfactorily explained the inconsistencies, the inspectors determined that this issue was of minor significance. Also, the inspectors concluded that the Unit 1 steam generators current condition does not represent a safety concern because the tubes structural integrity was not compromised.

Inadequate Maintenance Rule Evaluation The inspectors reviewed the maintenance rule evaluation (MRE) for AR 2012-4305, Evaluate Auxiliary Feedwater MRE Function 12 for Issue in AR 2011-12319, and concluded the basis for not considering it a functional failure was incorrect. The failure of motor-operated valve (MOV) 1-FMO-211 to reposition electrically was caused by sand entering the valves actuator limit switch housing and was initially documented in AR 2011-12319, 1-FMO-211 Turbine Driven Auxiliary Feed Pump to #1 Steam Generator Feed Valve will not Close. However, the resident inspectors identified that the associated MRE failed to address the MOVs maintenance rule function to isolate a faulted steam generator. To address this issue, licensee personnel initiated AR2012-4305 and subsequently concluded that there was not a functional failure because the MOV could be manually operated locally by its handwheel.

However, the Updated Final Safety Analysis Report, Section 10.5.2.2, stated that auxiliary feedwater (AFW) flow to the steam generators can be controlled remotely such that electrically operating the MOV was a required function. The inspectors discussed this issue with the maintenance rule NRC staff in the office of Nuclear Reactor Regulation (NRR) and concluded that the reliance on manual actions under the maintenance rule was not appropriate. In parallel, licensee personnel came to the same conclusion with respect to manual actions and subsequently initiated AR 2013-13506, Maintenance Rule Program Scope of AFW Manual Operator Action, to re-perform the MRE to determine if the functional failure was maintenance preventable. The evaluation also addressed the extent of condition to determine if this incorrect reliance on manual operator actions was used in other similar maintenance rule evaluations.

Based on this review, licensee personnel determined that the 1-FMO-211 functional failure was also a maintenance preventable functional failure (MPFF). In addition, two other failures of similar AFW valves were re-evaluated and determined to be MPFFs.

However, the reliability performance criteria for AFW were monitored on a unit specific, train basis, and each of the three MPFFs was in a different unit and/or train such that no performance criteria were exceeded. Therefore, the inspectors concluded that this issue was a minor violation of the maintenance rule, 10 CFR 50.65 (a)(2), as it would not have required an (a)(1) evaluation.

Use of Information from Prior Evaluations to make Operability Determinations The inspectors reviewed two ARs that were written to document gas voiding in the Unit 1 south safety injection system piping. These issues, which occurred in 2008 and then again in 2011, were documented in AR 00839240, 1-SI-120S, Identified Air/Gas Void in Piping, and AR 2011-14450, 1-SI-120S Identified Void in Piping, respectively. The operability evaluations for these issues relied on engineering judgment, which was based on industry gas transport testing. However, during the TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01), inspection as documented in NRC Inspection Report 05000315/2012008; 05000316/2012008, the inspectors identified a finding regarding the licensees failure to have a quantitative value for the maximum allowable void in the safety injection system piping. The inspectors documented the finding because for cases involving gas voiding, engineering judgment was not considered an acceptable method for evaluating system operability. To address this finding, the licensee performed a calculation in early 2012 to establish the maximum allowable void size, and procedure EHI-5202, Gas Accumulation Condition Monitoring Program, was revised to include the criteria from the calculation.

In 2013, a void was identified in the Unit 2 north safety injection system piping, which was documented in AR 2013-6601, Air/gas Void Found at and around 2-SI-120N. The operability evaluation for this issue again included a reference to industry gas transport testing in addition to referring to the revised guidance in procedure EHI-5202. However, it was only necessary to show that the as-found void was smaller than the maximum allowable void size documented in EHI-5202 to prove operability. Because the operability evaluation also referred to the industry gas transport testing, the inspectors raised a concern that licensee personnel might be accepting prior operability evaluations without ensuring that the conditions and methodology used were still valid for the given condition. This could result in an inadequate operability determination. Because the inspectors did not identify any inadequate operability determinations and because the safety injection system piping was operable based on the guidance in EHI-5202 for the void identified in 2013, the inspectors concluded that this issue was of minor significance. Licensee personnel generated AR 2013-13526, Past Operability Determination Evaluation Referenced Superseded Past Operability Determination Evaluation, to address this issue.

Prioritization of Equipment in the CAP Process The inspectors noted that the licensees AR initiation process as described in PMP-7030-CAP-001, Action Initiation, did not contain provisions to ensure that problem resolution would be appropriately prioritized for some plant equipment that has regulatory requirements for functionality.

Specifically, the licensees AR initiation process uses the following three standards to prioritize the resolution of an equipment problem: 1) SCAQ (Significant Condition Adverse to Quality), CAQ (Condition Adverse to Quality), and CNAQ (Condition not Adverse to Quality), as defined by 10 CFR 50 Appendix B for safety-related structures, systems and components relied on to mitigate design basis accidents; 2) a pre-defined list of equipment important to emergency response; and 3) an equipment problem related to a reportability requirement.

However, equipment required under 10 CFR 50.54(hh), (e.g. B.5.b equipment) and some equipment scoped into the maintenance rule (10 CFR 50.65) that is not defined as 10 CFR 50, Appendix B safety-related structures, systems and components relied on to mitigate design basis accidents, were not contained in the standards. Instead, the licensee relied on the knowledge of personnel who initiated the AR and the department-level reviewers (subject matter experts) to ensure the AR was prioritized properly. While the licensees process incorporated several levels of review, the inspectors noted that if the appropriate subject matter expert was not available when the AR was screened, the AR initiation process did not contain pre-defined standards to ensure that the equipments functional requirements were identified. Consequently, resolving the identified problem may not be appropriately prioritized and the related regulatory requirement may not be met.

Because the inspectors did not identify any 10 CFR 50.54(hh) or maintenance rule equipment problems that were not appropriately prioritized, this issue was determined to be of minor significance. Licensee personnel generated AR 2013-13409, The List of CAQ Items Does not Address Non-Appendix B Items, to address this issue.

Findings No findings were identified.

(3) Effectiveness of Corrective Actions Overall, the corrective actions reviewed were appropriately focused to correct the problem and were implemented in a timely manner commensurate with the issues safety significance. Problems identified through root or apparent cause evaluations were resolved in accordance with the CAP procedural and regulatory requirements.

Corrective actions intended to prevent recurrence were generally comprehensive, thorough, and timely.

The corrective actions associated with selected NRC documented findings and violations, as well as licensee identified violations, were generally appropriate to correct the problem and were implemented in a timely manner. However, the inspectors identified examples of minor significance, as discussed below, when corrective actions for non-cited violations (NCV) were not thorough.

Observations Missed Opportunity to Identify Potential 10 CFR 50.59 Process Improvements The inspectors reviewed the actions taken for an NCV of 10 CFR 50.59, Changes, Tests and Experiments, documented in NRC Inspection Report 05000315/2012008; 05000316/2012008 as NCV 05000315/2012008-06; 05000316/2012008-06. The violation pertained to the licensees failure to perform a written evaluation, which provided the bases for not applying for a license amendment when the residual heat removal (RHR) pump casing drain lines were modified. The modification impacted the RHR pump casing drain function during a Mode 4 loss of coolant accident (LOCA),which was not evaluated by the 50.59 review. The licensee documented the issue in AR 2012-1751, Using RHR Pump Casing Drains during Mode 4 LOCA.

Action 2 of AR 2012-1751 requested that a gap analysis be performed regarding the modification process related to the RHR pump casing drains. The cause evaluation associated with this action concluded, in part, that for unknown reasons, the functional requirement was overlooked during execution of the modification and 50.59 review processes in place at the time.

For corrective actions, the original 50.59 was reviewed and corrected to include the function for the RHR pump casing drains during a Mode 4 LOCA. In addition, the RHR pump casing drains were subsequently returned to the original design, which restored the function for the RHR pump casing drains during a Mode 4 LOCA and resolved the 50.59 violation associated with the finding. However, the licensee did not take thorough actions to evaluate why the Mode 4 LOCA functional requirements for the RHR pump casing drains were overlooked in the original 10 CFR 50.59 review.

The inspectors considered the failure to evaluate why the functional requirements were missed during the original 10 CFR 50.59 review a missed opportunity to identify potential 10 CFR 50.59 and modification process enhancements. Because the violation was appropriately resolved, the inspectors concluded that this issue was of minor significance. Licensee personnel generated AR 2013-15181, Missed Opportunity during 50.59 Review, to address this issue.

Gas Accumulation Condition Monitoring The inspectors reviewed the corrective actions taken to resolve two NCVs from the TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008-01), inspection as documented in NRC Inspection Report 05000315/2012008; 05000316/2012008. The inspectors determined that the corrective actions did not fully address the identified concerns.

• The first NCV pertained to inadequate performance monitoring (2012008-03)specified in gas monitoring program procedures. Based on the corrective actions identified in AR 2012-1768, Gas Accumulation Condition Monitoring, it was still unclear that the monitoring specified in procedure EHI 5202, Gas Accumulation Condition Monitoring Program, was adequate to identify gas intrusion. The NCV was based on not having programmatic processes with clear acceptance criteria to monitor for gas intrusion. The first issue concerned EHI-5202, step 4.5.2, which was identified by the licensee. Based on the results from calculation MD-12-ECCS-022-N, Maximum Void Formation from Accumulator Leakage, a 12 cubic feet void could have potentially formed prior to the acceptance criteria being exceeded. However, the license basis for voids in the system was zero such that monitoring would not be effective in identifying air intrusion prior to exceeding acceptance criteria. In addition, the system manager was to monitor accumulator level; however there was not adequate criteria identified of when to enter issues into the CAP to be evaluated. The second issue evaluated by AR 2012-1768 discussed, in part, how the monitoring performed in EHI 5202, steps 4.5.1 and 4.5.4, could identify gas intrusion. However specific guidance was not incorporated into the procedure. The inspectors concluded that these issues were of minor significance because the licensee had established frequent preventive maintenance activities to conduct ultrasonic testing to monitor for voiding. Licensee personnel generated AR 2013-13436, Update the ECCS System Monitoring Plan to Reflect Monitoring, and GT 2013-13453, EHI-5202 Revision Tracker, to address these issues.

• The second NCV pertained to not having adequate analyses for vortexing for three tanks (2012008-01) to ensure the tanks were isolated from the associated pumps prior to ingesting air into the system. Calculation MD-12-CTS-021-N, Minimum Level to Prevent Vortexing in the Spray Additive Tank, determined there was a negative margin (1.75 inches) such that the start of vortexing would occur prior to the isolation valves closing, which could lead to air intrusion into the system. Based on engineering judgment, the licensee concluded that this was acceptable because the methodology used was considered conservative and bounding. However, the inspectors noted that the methodology did not appear to be applicable for a tank configuration with reducing level, such as the spray additive tank, as it was more appropriate for an intake structure with constant level. The inspectors performed a simplified vortex calculation applicable to tanks with decreasing levels that provided reasonable assurance that vortexing would not occur prior to tank isolation. Therefore, the inspectors concluded that this issue was of minor significance. Licensee personnel initiated AR 2013-13536, NRC Comment on Methodology of Vortex Calculations, to review the issue to ensure that the vortex analysis used was applicable for the application.

Findings No findings were identified.

.2 Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees Operating Experience (OE) program implementation. Specifically, the inspectors reviewed OE program implementing procedures; attended CAP meetings to observe the use of OE information; reviewed completed evaluations of OE issues and events; and, reviewed selected monthly assessments of the OE composite performance indicators. The inspectors review was to determine whether the licensee was effectively integrating OE into the performance of daily activities; whether evaluations of issues were proper and conducted by qualified personnel; whether the licensees program was sufficient to prevent future occurrences of previous industry events; and, whether the licensee effectively used the information in developing departmental assessments and facility audits. The inspectors also assessed if corrective actions resulting from OE were identified and implemented in an effective and timely manner.

b. Assessment The inspectors did not identify issues of concern regarding the licensees use of OE and concluded that, in general, OE was effectively utilized at the station. The inspectors observed that OE was discussed as part of the daily plant status and pre-job briefings.

Industry OE was effectively disseminated across the various plant departments and the inspectors did not identify any issues while reviewing licensee evaluations of OE. The inspectors also verified that the use of OE in formal CAP products such as root cause evaluations and equipment apparent cause evaluations was appropriate and adequately considered. Generally, OE that was applicable to the station was thoroughly evaluated and actions were taken in a timely manner to address any issues that resulted from the evaluations.

Findings No findings were identified.

.3 Self-Assessments and Audits

a. Inspection Scope

The inspectors reviewed selected self-assessments, including adverse trend assessments, and performance assurance audits to assess the licensee staffs ability to identify and enter issues into the CAP with the appropriate characterization; to prioritize and evaluate issues commensurate with the safety significance; and, to implement effective corrective actions in a timely manner. The inspectors also evaluated whether the self-assessments and audits were effectively managed and adequately covered the subject areas; and, verified that assessments were conducted in accordance with PMP-7034-SAP-001, Conduct of Self-Assessments.

b. Assessment The inspectors did not identify any issues of concern regarding the licensees ability to conduct self-assessments and audits. Assessments were conducted in accordance with plant procedures; were generally thorough and intrusive; adequately covered the subject area; and, were effective at identifying issues and enhancement opportunities at an appropriate threshold. Identified issues were entered into the CAP with an accurate characterization and corrective actions were completed, and/or scheduled to be completed, in a timely manner commensurate with the significance.

Findings No findings were identified.

.4 Safety Conscious Work Environment

a. Inspection Scope

The inspectors assessed the licensees Safety Conscious Work Environment (SCWE)through the review of the licensees employee concerns program (ECP) implementing procedures, discussions with the ECP coordinators, and interviews with licensee personnel from various departments. The inspectors also reviewed the results from a Nuclear Safety Culture Assessment that was conducted in February 2013, as well as Safety Conscious Work Environment Pulsing Surveys for contract employees that were conducted in March 2013 and June 2013.

b. Assessment The inspectors did not identify any issues of concern regarding the licensees safety conscious work environment. Information obtained during the interviews indicated that an environment was established where licensee and contract employees felt free to raise nuclear safety issues without fear of retaliation; licensee personnel were aware of and generally familiar with the CAP and other processes, including the ECP and the NRC, through which concerns could be raised; and, safety significant issues could be freely communicated to supervision. Documents provided to the inspectors regarding the SCWE surveys generally supported the conclusions from the interviews.

Findings No findings were identified.

.5 Review of Confirmatory Order EA-06-295, Items 3 and 5

Confirmatory Order EA-06-295 dated April 4, 2007, was issued to the licensee by the NRC as part of a settlement agreement between Indiana Michigan Power Company (I&M), the licensee for the D. C. Cook nuclear power plant, and the NRC regarding an apparent violation of 10 CFR 50.7, Employee Protection, that was issued on December 13, 2006. The settlement agreement was reached during an Alternate Dispute Resolution mediation session conducted on March 8, 2007 (ADR-07-001).

The inspectors reviewed the actions taken by the licensee to address confirmatory order items 3 and 5, as discussed below:

• Confirmatory order item number 3 (licensee commitment number 8434) stated:

As expeditiously as possible but by no later than December 31, 2008, I&M agrees to complete training of all DC Cook plants non-supervisory employees and long-term contractors on the topic of a SCWE.

The inspectors reviewed training attendance records and training lesson plans to verify that the licensee had completed the actions as specified in confirmatory order item 3. No issues of concern were identified. The inspectors concluded that the conditions of confirmatory order item 3 were met. The NRC has no further questions on this issue.

• Confirmatory order item number 5 (licensee commitment number 8438) stated:

By no later than ninety

(90) calendar days after the issuance of this Confirmatory Order, I&M agrees to implement a periodic assessment of its compliance with its work hour limitations program and evaluate the results of the assessment for trends.

The inspectors reviewed plant procedures, work orders and self-assessments associated with the work hour limitations program to verify that the licensee had completed the actions as specified in confirmatory order item 5. No issues of concern were identified. The inspectors concluded that the conditions of confirmatory order item 5 are being met. The NRC has no further questions on this issue.

4OA6 Management Meetings

.1 Exit Meeting Summary

On September 13, 2013, the inspectors presented the inspection results to Mr. S. Lies and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Lies, Engineering Vice President

B. Bradley, System Engineering

M. Chouinard, System Engineering

D. Ethridge, Performance Improvement

J. Harner, Environmental Manager

B. Hite, Radiation Protection Manager

M. Kennedy, Performance Improvement

B. Kraha, Maintenance Manager

J. Labis, Employee Concerns Program

J. McClelland, System Engineering Manager

S. Mitchell, Regulatory Affairs

S. Partin, Plant Manager

M. Scarpello, Nuclear Regulatory Assurance Manager

S. Schneider, Senior License Holder

M. Siewert, Maintenance CAP Coordinator

A. Thompson, Emergency Planning

C. Wohlgamuth, Compliance Manager

R. Wynegar, Regulatory Affairs

Nuclear Regulatory Commission

John Ellegood, Senior Resident Inspector

LIST OF ITEMS

Opened

None

Closed

EA-06-295, Item 3 ORD ADR-07-001, Third Item of Order Issued in ML070940133 (4OA2.5)

EA-06-295, Item 5 ORD ADR-07-001, Fifth Item of Order Issued in ML070940133 (4OA2.5)

Attachment