IR 05000346/2011003

IR 05000346-11-003, on 4/1/11 - 6/30/11, Davis-Besse Nuclear Power Station, Follow Up of Events and Notices of Enforcement Discretion, Inspection Report

ML112060312
Person / Time
Site:	Davis Besse
Issue date:	07/21/2011
From:	Marshfield M NRC/RGN-III/DRP/B6
To:	Allen B FirstEnergy Nuclear Operating Co
References
IR-11-003
Download: ML112060312 (41)

Text

UNITED STATES uly 21, 2011

SUBJECT:

DAVIS-BESSE NUCLEAR POWER STATION INTEGRATED INSPECTION REPORT 05000346/2011003

Dear Mr. Allen:

On June 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Davis-Besse Nuclear Power Station. The enclosed report documents the results of this inspection, which were discussed on July 12, 2011, with the Director, Site Engineering, Mr. Vito Kaminskas, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the results of this inspection, one self-revealed finding of very low safety significance was identified. The finding also involved a violation of NRC requirements. However, because of its very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating the issue as a non-cited violation (NCV) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Davis-Besse Nuclear Power Station. In addition, if you disagree with the cross-cutting aspect assigned to 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 III, and the NRC Resident Inspector at the Davis-Besse Nuclear Power Station. 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 System (PARS)

component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Mark Marshfield, Acting Chief Branch 6 Division of Reactor Projects Docket No. 50-346 License No. NPF-3

Enclosure:

Inspection Report 05000346/2011003 w/Attachment: Supplemental Information

REGION III==

Docket No: 50-346 License No: NPF-3 Report No: 05000346/2011003 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Davis-Besse Nuclear Power Station Location: Oak Harbor, OH Dates: April 1, 2011, through June 30, 2011 Inspectors: D. Kimble, Senior Resident Inspector A. Wilson, Resident Inspector T. Briley, Reactor Engineer Approved by: Mark Marshfield, Acting Chief Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000346/2011003; 4/1/11-6/30/11; Davis-Besse Nuclear Power Station;

Follow Up of Events and Notices of Enforcement Discretion.

This report covers a 3-month period of inspection by resident inspectors. One Green finding was identified by the inspectors. The finding was considered a non-cited violation (NCV) of NRC regulations. The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A self-revealed Green finding and associated NCV of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, were identified for the licensees failure to ensure that activities affecting quality are properly accomplished in accordance with instructions, procedures, and drawings. Specifically, the licensee failed to follow radio usage guidelines when performing fire detection surveillance testing in the auxiliary shutdown panel. The procedure did not contain a specific requirement to exclude radio usage in the vicinity of the auxiliary shutdown panel. The inappropriate use of radio communication caused interference in the auxiliary shutdown panel, resulting in a momentary loss of emergency feedwater controls. The licensee included this issue in their corrective action program as CR 11-90403. An immediate corrective action was taken to post signs restricting radio usage within the auxiliary shutdown panel room. The procedures that govern in-plant radio communications and security communications were revised to prohibit the use of portable radios in the auxiliary shutdown panel room. Additionally, a corrective action was initiated to provide training to the appropriate personnel to ensure awareness and adherence to radio communication use in the vicinity of plant equipment.

The inspectors determined that the licensees failure to follow radio usage guidelines when working inside the auxiliary shutdown panel cabinet was a performance deficiency.

The inspectors determined that the finding was more than minor because it is associated with the Mitigating Systems Cornerstone attribute of Equipment Performance, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations. Using the Phase 1 SDP worksheet for the Mitigating Systems Cornerstone, the inspectors answered no to all five screening questions.

Because of the short duration of the reduction in control signals (approximately 27 seconds), it was determined that sufficient design margin was available to accommodate the worst case scenario of an auxiliary feedwater flowrate increase to both steam generators during any transient described in the Updated Safety Analysis Report. An SDP Phase 2 analysis was not required because the emergency feedwater system remained available throughout this event. Therefore, the finding was determined to be of very low safety significance (Green). This finding is associated with a cross-cutting aspect in the resources component of the human performance cross-cutting area, because the licensee did not ensure that personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety. Specifically, personnel were not adequately trained on procedure DB-OP-05441, Radio Communication System. H.2(b) (Section 4OA3)

Licensee-Identified Violations

No violations of significance were identified.

REPORT DETAILS

Summary of Plant Status

With the following exceptions, the unit operated at full power for the entire assessment period except for brief down-power maneuvers to accomplish rod pattern adjustments and to conduct planned surveillance testing activities:

Between April 10, 2011, and May 6, 2011, the plant occasionally reduced power in order to maintain condenser vacuum within procedural limits. Power reductions varied within the range of 1 to 12 percent. Power reductions were necessary due to a combination of environmental conditions and an extended maintenance period on circulating water pump No. 4, which was returned to service on May 12, 2011; and On June 28, 2011, the plant reduced power to approximately 95 percent in order to sequentially shut down circulating water pumps No. 3 and No. 4 while maintaining condenser vacuum within procedural limits. The pumps were shutdown in order to facilitate emergent cleaning of the pump suction screens. The unit returned to operation at full power the same day.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

• the coordination between the TSO and the plant during off-normal or emergency events;

• the explanations for the events;

• the estimates of when the offsite power system would be returned to a normal state; and

• the notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

• the actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;

• the compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;

• a re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and

• the communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures.

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

.2 External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions provided in the Updated Safety Analysis Report (USAR) for features intended to mitigate the potential for flooding from external factors.

As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable. Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site which would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also walked down underground bunkers/manholes subject to flooding that contained multiple train or multiple function risk-significant cables. The inspectors also reviewed the licensees off-normal procedure for mitigating flooding to ensure it could be implemented as written.

This inspection constituted one external flooding sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Alignment Verifications

a. Inspection Scope

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

• the station blackout diesel generator (SBODG) when emergency diesel generator (EDG) 1-1 was inoperable for periodic surveillance testing on April 14, 2011; and

• containment spray train 2 during preventive maintenance outage of containment spray train 1 on May 3, 2011.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, USAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization.

Documents reviewed are listed in the Attachment to this report.

These activities constituted two partial system alignment verification samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Alignment Verification

a. Inspection Scope

On June 24, 2011, the inspectors performed a complete system alignment inspection of the service water system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.

Documents reviewed are listed in the Attachment to this report.

These activities constituted one complete system alignment verification sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Mechanical Penetration Room No. 1 (Room 202, Fire Area AB);

• Auxiliary Feedwater Pump Room No. 1 and No. 2 (Rooms 237, 238, Fire Areas E, F);

• High Voltage Switchgear Room A (Room 325, Fire Area S);

• EDG 1-1 Rooms (Rooms 318 and 318UL, Fire Area K); and

• Low Voltage Switchgear Room - F-Bus / Battery Room 2 (Rooms 428 and 428A, Fire Area X).

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events (IPEEE) with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On June 17, 2011, the inspectors observed fire brigade response to live fires at the licensees offsite fire training facilities. Based on this observation, the inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

• proper wearing of turnout gear and self-contained breathing apparatus;

• proper use and layout of fire hoses;

• employment of appropriate fire fighting techniques;

• sufficient firefighting equipment brought to the scene;

• effectiveness of fire brigade leader communications, command, and control;

• search for victims and propagation of the fire into other plant areas;

• smoke removal operations;

• utilization of pre-planned strategies;

• adherence to the pre-planned drill scenario; and

• drill objectives.

Documents reviewed are listed in the Attachment to this report.

These activities constituted one annual fire protection inspection sample as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the USAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant areas to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• internal floods in the auxiliary building from feedwater;

• internal floods in the auxiliary building from fire suppression;

• internal floods in the intake structure from fire suppression; and

• internal floods in the AFW pump vault from various sources.

This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

.2 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submergence conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground manholes subject to flooding:

• Manhole 3045, 3004, and SB2.

This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On May 24, 2011, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• containment gas monitoring and post accident monitoring systems; and

• turbine-driven auxiliary feedwater (AFW) pumps.

The inspectors independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessment and Emergent Work Control Quarterly Resident

Inspections

a. Inspection Scope

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

• emergent work on the backup service water/dilution pump during the weeks ending April 9 and April 16, 2011;

• emergent work on the soak back pump for EDG 1 during protected train 1 work for the week ending April 23, 2011;

• planned maintenance on the motor-driven feedwater pump during the week ending April 30, 2011; and

• emergent work, which included a period of unplanned yellow risk, for the replacement of oil in AFW pump No. 2 during the week ending May 21, 2011.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

These maintenance risk assessments and emergent work control activities constituted four inspection samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

.1 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• the operability of emergency core cooling system (ECCS) components associated with a missing flood barrier seal located in mechanical penetration room No. 4 of the auxiliary building, as documented in CR 11-91555;

• the functionality of the SBODG associated with voltage control and reactive power anomalies noted during surveillance testing, as documented in CR 11-93333;

• the operability of EDGs after observation of a larger than normal air receiver pressure drop after a start of the EDGs, as documented in CR 11-92091 and CR 11-92886 ;

• the operability of AFW Train 2 following identification of an oil viscosity issue for AFW Pump No. 2, as documented in CR 11-94998; and

• the capability of the control room emergency air temperature control system (CREATCS) of performing its design functions using service water temperature of 90 degrees F and an outside ambient air temperature of 95 degrees F after surveillance test extrapolations challenged each parameter, as documented in CR 11-95467 and CR 11-95563.

The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the licensees evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and other plant licensing and safety basis documents to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability or functionality, the inspectors determined whether the measures in place would function as intended and were properly controlled. Where appropriate, the inspectors evaluated compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations and functionality assessments. Documents reviewed are listed in the Attachment to this report.

These operability evaluation and functionality assessment reviews constituted five inspection samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Quarterly Review of Post-Maintenance Tests

a. Inspection Scope

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

• functional testing of service water pump 1-2 and its associated strainer (F15-2)on April 21, 2011, following pump motor and strainer maintenance;

• functional testing of the motor-driven feed pump (MDFP) on April 27, 2011, following an extensive mechanical and electrical maintenance work window; and

• monthly test of EDG No. 2 on the DA31 air start side after replacement of the pressure regulating valve on April 29, 2011.

These activities were selected based upon the SSCs ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (i.e., temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TS and other design and licensing basis documents, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests (PMTs) to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

The inspectors reviews of these post-maintenance testing activities constituted three inspection samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• DB-MI-03057, RPS Channel 1 Calibration of Overpower, Power/Imbalance/Flow, and Power/Pumps Trip Functions, on April 8, 2011 (routine);

• DB-SC-03077, Emergency Diesel Generator 2 184-Day Test, on April 28, 2011 (routine);

• DB-SS-03711, Functional Test for Control Room Emergency Ventilation System Train 2, on May 23, 2011 (routine); and

• DB-SP-03137, Decay Heat Train 2 Pump and Valve Test, on May 26, 2011 (IST).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the USAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers (ASME) code, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted three routine surveillance testing samples and one inservice testing sample, as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Safety System Functional Failures

a. Inspection Scope

The inspectors sampled licensee submittals for the Safety System Functional Failures performance indicator for the period from the second quarter of 2010 through the first quarter of 2011. To determine the accuracy of the performance indicator (PI) data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73" definitions and guidance, were used. The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, issue reports, event reports and NRC Integrated Inspection Reports for the period of April 2010 through March 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees condition report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one safety system functional failures sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Emergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System performance indicator for the period from the second quarter of 2010 through the first quarter of 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports, event reports and NRC Integrated Inspection Reports for the period of April 2010 through March 2011 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified. Documents reviewed are listed in the to this report.

This inspection constituted one MSPI emergency AC power system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - High Pressure Injection System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection System performance indicator for the period from the second quarter of 2010 through the first quarter of 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports for the period of April 2010 through March 2011 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator, and none were identified.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI high pressure injection system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Sections 4OA2.1 and 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six month period of January 1, 2011, through June 30, 2011, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted a single semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Annual Sample: Review of Operator Workarounds

a. Inspection Scope

The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of the operator workarounds (OWAs) on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.

The inspectors performed a review of the cumulative effects of OWAs. The documents listed in the Attachment were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP and proposed or implemented appropriate and timely corrective actions which addressed each issue. Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed.

Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.

This review constituted one operator workaround annual inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

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

.1 Technical Specification 3.0.3 Entry Due to Inoperability of Both Trains of the Control

Room Emergency Air Temperature Control System

a. Inspection Scope

The inspectors followed up on an event in the afternoon of June 4, 2011. Specifically, while Control Room Emergency Air Temperature Control System (CREATCS) Train 1 was inoperable and undergoing return-to-service testing following modifications to enhance its air-cooled mode of operation, plant operators conducting a routine plant tour identified that Service Water (SW) Pump Area Vent Fan 1-4 was not running. This vent fan, which should have been in operation, was one of two such fans required to function to ensure the operability of SW Train 2 when outside ambient air temperatures exceeded 86 degrees F.

At 12:51 p.m., plant operators declared SW Train 2 inoperable when outside ambient air temperature reached 86 degrees F. Equipment of concern supported by SW Train 2 included CREATCS Train 2, which was also declared inoperable at the same time.

Noting that TS 3.7.11 for CREATCS did not contain any required actions for both CREACTS trains being simultaneously inoperable, plant operators entered TS 3.0.3, which required actions to commence within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to shut down the plant to a hot standby condition. At 1:48 p.m., plant personnel completed testing on CREACTS Train 1 and declared it operable. This allowed TS 3.0.3 required actions to be exited.

While plant operators had made preparations for a possible plant shutdown, no reduction in reactor power was ever initiated.

Inspectors responded to the site and independently evaluated the licensees actions for this event. Specific items reviewed by the inspectors included the licensees operability declaration for CREATCS Train 1 and supporting test data, and the licensees evaluation of reporting criteria required under 10 CFR 50.72.

The inspectors' response to and review of this event constituted one inspection sample as defined in IP 71153.

a. Findings

No findings were identified.

.2 (Closed) Licensee Event Report 05000346/2011-003: Radio Usage Renders

Emergency Feedwater Inoperable

a. Inspection Scope

This event, which occurred on March 3, 2011, happened when a radio used by station personnel for communications was keyed twice while instrumentation cabinet doors were open to the auxiliary shutdown panel. Radio interference caused a momentary reduction in control signals to the AFW pump and MDFP discharge valves. These momentary signal reductions resulted in the rendering of all three trains of emergency feedwater inoperable for approximately 2 minutes. A self-revealed Green finding and associated NCV was identified. Documents reviewed as part of this inspection are listed in the Attachment. This Licensee Event Report (LER) is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

Introduction:

A self-revealed Green finding and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to ensure that activities affecting quality are properly accomplished in accordance with instructions, procedures, and drawings. Specifically, the licensee failed to follow radio usage guidelines when performing fire detection surveillance testing in the auxiliary shutdown panel. The procedure did not contain a specific requirement to exclude radio usage in the vicinity of the auxiliary shutdown panel. The inappropriate use of radio communication caused interference in the auxiliary shutdown panel, resulting in a momentary loss of emergency feedwater controls.

Description:

On March 3, 2011, Maintenance Instrument and Control (I&C) technicians were performing a fire surveillance test in the auxiliary shutdown panel room. Two smoke detectors are located inside the auxiliary shutdown panel cabinet. For testing efficiency, the technicians used radios to communicate between the person performing the test in the field and a technician located at the local fire panel. The technician left both doors of the cabinet open when applying smoke to the detectors to allow for smoke to dissipate and not cause further alarms. When the technician keyed his radio (approximately two feet from the cabinet), he unknowingly affected electronic equipment in the auxiliary shutdown panel. The control room received unexpected indications for steam generator level and pressure. The change in steam generator level signal due to the radio usage resulted in a momentary reduction in the control signals to the AFW Pumps and MDFP discharge valves. These signals would have caused the control valves to open and increase emergency feedwater flow to the steam generators if the equipment had been in operation. The technician keyed the radio twice over a period of approximately two minutes during the test. Control signals were affected for a total of 27 seconds in length.

The control signals returned to normal after each momentary event.

Operations declared all three trains of emergency feedwater inoperable for a two minute duration when the emergency feedwater control valves were affected. The NRC was notified of the eight hour reportable condition per 10CFR 50.72 (b)(3)(v)A,B for a condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to:

(1) shutdown the reactor and maintain it in a safe shutdown condition and

(2) remove residual heat. The licensee performed an analysis of the momentary transient reduction in steam generator levels to determine the impact. Had the AFW system been called upon to operate this would have resulted in an increase in AFW flow. The evaluation concluded sufficient design margin was available to accommodate a flowrate increase to 800 gallons per minute (gpm) for 38 seconds to both steam generators. The licensee determined that AFW remained available throughout the event.

The licensees procedure DB-OP-06441, Radio Communication System, describes the guidance given to Davis-Besse Operations and Maintenance personnel regarding the use of radios. Plant personnel are expected to be knowledgeable of this procedure, although it is not a training requirement. Procedural guidance in DB-OP-06441 recommends that portable radio users be advised not to operate their radios within two feet of plant electrical and electronic equipment. This restriction is intended to insure that near field reactive coupling does not occur between portable radios and plant equipment. The procedure also lists rooms and cabinets where portable radios shall be turned off and restricted from use when either entering the room or approaching within six feet of a cabinet with doors open. However, at the time of the event on March 3, 2011, the auxiliary shutdown panel was not on the list of radio-restricted areas.

The licensees root cause analysis of the event revealed that procedure DB-OP-06441 originally listed that portable radios shall be turned off prior to entering and when in the Auxiliary Shutdown Panel room. This restriction was based on Electro-Magnetic Interference (EMI) testing in the plant that revealed the susceptibility of the auxiliary shutdown panel. However, following a meeting in 1991 between station personnel to establish a list of areas in the plant where radio usage would be restricted, the final restriction listing did not include the Auxiliary Shutdown Panel Room. The basis behind this decision was not documented.

The technicians working in the auxiliary shutdown panel room were not aware of procedure DB-OP-05441, Radio Communication System. The technicians were aware that radios shall not be used in posted rooms, but they were not aware of the restriction of radio operation within two feet of electronic equipment. The auxiliary shutdown panel room was not posted as a restricted area. A training gap analysis performed by the licensee concluded that there was a general lack of awareness or knowledge among many groups regarding the procedural guidance for portable radio use at Davis-Besse.

Plant personnel are expected to be knowledgeable of this procedure, although it is not a training requirement. Most maintenance personnel were not aware of this procedure.

Portable radio users were found to be dependent on signage to determine radio restrictions.

A sign was installed shortly after this event occurred, restricting radio usage within the auxiliary shutdown panel room. The procedures that govern in-plant radio communications and security communications were revised to prohibit the use of portable radios in the auxiliary shutdown panel area with the cabinet doors open. The procedures and signage were expanded to include the restriction of cell phones in sensitive areas. Additionally, a corrective action was initiated to provide training to the appropriate personnel to ensure awareness and adherence to radio communication use in the vicinity of plant equipment.

Analysis:

The inspectors reviewed this finding using the guidance contained in Appendix B, Issue Disposition Screening, of Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports. The inspectors determined that the licensees failure to follow radio usage guidelines when working inside the auxiliary shutdown panel cabinet was a performance deficiency and was reasonably within the licensees ability to foresee and correct, and should have been prevented. The inspectors determined that the finding was more than minor because it is associated with the Mitigating Systems Cornerstone attribute of Equipment Performance, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the inappropriate use of radio communication caused interference in the auxiliary shutdown panel, resulting in a momentary loss of emergency feedwater controls.

The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations.

Using the Phase 1 SDP worksheet for the Mitigating Systems Cornerstone, the inspectors answered no to all five screening questions. Because of the short duration of the reduction in control signals (approximately 27 seconds), it was determined that sufficient design margin was available to accommodate the worst case scenario of an AFW flowrate increase to both steam generators during any transient described in the USAR. An SDP Phase 2 analysis was not required because the emergency feedwater system remained available throughout this event. Therefore, the finding was determined to be of very low safety significance (Green).

This finding is associated with a cross-cutting aspect in the resources component of the human performance cross-cutting area, because the licensee did not ensure that personnel, equipment, procedures, and other resources are available and adequate to assure nuclear safety. Specifically, personnel were not adequately trained on procedure DB-OP-05441, Radio Communication System. Technicians were not aware that the use of portable radios within two feet of electronic equipment could cause signal interference. H.2(b)

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by instructions, procedures, or drawings and shall be accomplished in accordance with these instructions, procedures, or drawings.

Contrary to the above, the licensee failed to follow radio usage guidelines when performing fire detection surveillance testing in the auxiliary shutdown panel. The procedure did not contain a specific requirement to exclude radio usage in the vicinity of the auxiliary shutdown panel. The inappropriate use of radio communication caused interference in the auxiliary shutdown panel, resulting in a momentary loss of emergency feedwater controls. The licensee included this issue in their CAP as CR 11-90403. An immediate corrective action was taken to post signs restricting radio usage within the auxiliary shutdown panel room. The procedures that govern in-plant radio communications and security communications were revised to prohibit the use of portable radios in the auxiliary shutdown panel room. Additionally, a corrective action was initiated to provide training to the appropriate personnel to ensure awareness and adherence to radio communication use in the vicinity of plant equipment. Because this violation was of very low safety significance and it was entered into the licensees CAP, this violation is being treated as an NCV, consistent with the Enforcement Policy.

(NCV 05000346/2011003-01)

4OA5 Other Activities

.1 (Closed) NRC Temporary Instruction 2515/183, Followup to the Fukushima Daiichi

Nuclear Station Fuel Damage Event

a. Inspection Scope

The inspectors assessed the activities and actions taken by the licensee to assess its readiness to respond to an event similar to the Fukushima Daiichi nuclear plant fuel damage event. This included

(1) an assessment of the licensees capability to mitigate conditions that may result from beyond design basis events, with a particular emphasis on strategies related to the spent fuel pool, as required by NRC Security Order Section B.5.b issued February 25, 2002, as committed to in severe accident management guidelines (SAMGs), and as required by 10 CFR 50.54(hh);

(2) an assessment of the licensees capability to mitigate station blackout (SBO) conditions, as required by 10 CFR 50.63 and station design bases;

(3) an assessment of the licensees capability to mitigate internal and external flooding events, as required by station design bases; and

(4) an assessment of the thoroughness of the walkdowns and inspections of important equipment needed to mitigate fire and flood events, which were performed by the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

b. Findings

Inspection Report 05000346/2011011 (ML111320341) documented detailed results of this inspection activity. Following issuance of the report, the inspectors conducted detailed follow-up on selected issues. No findings were identified during this follow-up inspection.

.2 (Closed) NRC Temporary Instruction 2515/184, Availability and Readiness Inspection of

Severe Accident Management Guidelines

a. Inspection Scope

On May 18, 2011, the inspectors completed a review of the licensees SAMGs, implemented as a voluntary industry initiative in the 1990s, to determine

(1) whether the SAMGs were available and updated,

(2) whether the licensee had procedures and processes in place to control and update its SAMGs,

(3) the nature and extent of the licensees training of personnel on the use of SAMGs, and

(4) licensee personnels familiarity with SAMG implementation.

b. Findings

The results of this review were provided to the NRC task force chartered by the Executive Director for Operations to conduct a near-term evaluation of the need for agency actions following the Fukushima Daiichi fuel damage event in Japan. Plant-specific results for the Davis-Besse Nuclear Power Station were provided as an to a memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and Regional Support, dated June 1, 2011 (ML111520396). No findings were identified.

.3 Groundwater Sampling Results

a. Inspection Scope

The inspectors reviewed the results of groundwater samples taken from wells in the plant owner controlled area. The most recent samples were taken on March 29, 2011.

The sampling of wells was completed as part of the licensees voluntary groundwater monitoring initiative. All of the wells in the most recently reviewed groundwater samples contained less than 1,100 picocuries per liter (pCi/L) of tritium. Sample results above the 2,000 pCi/L groundwater monitoring program threshold require making courtesy notifications to state and local government officials and the NRC resident inspectors.

The formal reporting limit threshold is 30,000 pCi/L, as documented in the licensees Offsite Dose Calculation Manual. The licensee will continue to monitor wells in accordance with their groundwater monitoring program. The inspectors reviewed the licensees compliance to their stated offsite agency reporting requirements.

These routine reviews for samples to detect tritium in groundwater did not constitute any additional inspection samples. Instead, they were considered as part of the inspectors daily plant status monitoring activities.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 12, 2011, the inspectors presented the inspection results to the Director, Site Engineering, Mr. Vito Kaminskas, 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

-

B. Allen, Site Vice President

-

J. Barron, Manager, Site Projects

-

P. Boissoneault; Manager, Chemistry

-

B. Boles, Director, Site Operations

-

K. Byrd, Director, Site Performance Improvement

-

J. Dominy, Director, Site Maintenance

-

A. Garza, ALARA Specialist (Lead for Set Point Manual)

-

G. Hayes, Supervisor, Reactor Engineering

-

J. Hook, Manager, Design Engineering

-

R. Hovland, Manager, Training

-

V. Kaminskas, Director, Site Engineering

-

G. Kendrick, Manager, Site Outage Management

-

P. McCloskey, Manager, Site Regulatory Compliance

-

D. Noble, Manager, Radiation Protection

-

M. Parker, Manager, Site Protection

-

R. Patrick, Manager, Site Work Management

-

A. Percival, Sr. Chemistry Technologist (Liquid Radwaste and Effluent Analysis)

-

S. Plymale, Manager, Site Operations

-

C. Price, Director, Special Projects

-

J. Rogers, Manager, Steam Generator Replacement Project

-

D. Saltz, Manager, Site Maintenance

-

J. Scott, Supervisor, RP

-

C. Steenbergen, Superintendent, Operations Training

-

J. Sturdavant, Regulatory Compliance

-

T. Summers, Manager, Plant Engineering

-

L. Thomas, Manager, Nuclear Supply Chain

-

S. Trickett, Superintendent, Radiation Protection

-

J. Vetter, Manager, Emergency Response

-

A. Wise, Manager, Technical Services

-

G. Wolf, Supervisor, Regulatory Compliance

Attachment

LIST OF ITEMS

Opened

05000346/2011003-01 NCV Inadequate Training on Procedure Requirements Results in Auxiliary Feedwater Inoperability (Section 4OA3.2)

Closed

05000346/2011003-01 NCV Inadequate Training on Procedure Requirements Results in Auxiliary Feedwater Inoperability (Section 4OA3.2)

05000346/2011-003 LER Radio Usage Renders Emergency Feedwater Inoperable (Section 4OA3.2)

2515/183 TI Followup to the Fukushima Daiichi Nuclear Station Fuel Damage Event (Section 4OA5.1)

2515/184 TI Availability and Readiness Inspection of Severe Accident Management Guidelines (Section 4OA5.2)

Discussed

None Attachment