IR 05000237/2013005

IR 05000237-13-005 & 05000249-13-005; on 10/01/2013 - 12/31/2013; Dresden Nuclear Power Station, Units 2 & 3, Refueling Outage Activities

ML14023A632
Person / Time
Site:	Dresden
Issue date:	01/23/2014
From:	Jamnes Cameron NRC/RGN-III/DRP/B6
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-13-005
Download: ML14023A632 (49)

Text

January 23, 2014

SUBJECT:

DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3 NRC INTEGRATED INSPECTION REPORT 05000237/2013005; 05000249/2013005

Dear Mr. Pacilio:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Dresden Nuclear Power Station, Units 2 and 3. The enclosed report documents the results of this inspection, which were discussed on January 7, 2014, with Mr. S. Marik and other members of your staff.

Based on the results of this inspection, one self-revealed finding of very low safety significance was identified. The finding involved a violation of NRC requirements. However, because of the 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 the 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 Dresden 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 Dresden Nuclear Power Station.

As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review. 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/

Jamnes Cameron, Chief Branch 6 Division of Reactor Projects Docket Nos. 50-237; 50-249 License Nos. DPR-19; DPR-25

Enclosure:

IR 05000237/2013005; 05000249/2013005 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-237; 50-249 License Nos: DPR-19; DPR-25 Report No: 05000237/2013005; 05000249/2013005 Licensee: Exelon Generation Company, LLC Facility: Dresden Nuclear Power Station, Units 2 and 3 Location: Morris, IL Dates: October 1 through December 31, 2013 Inspectors: G. Roach, Senior Resident Inspector D. Meléndez-Colón, Resident Inspector D. Betancourt-Roldan, Acting Resident Inspector T. Go, Health Physicist N. Shah, Project Engineer R. Elliott, Reactor Engineer R. Jickling, Senior Emergency Preparedness Inspector M. Holmberg, Senior Reactor Inspector J. Laughlin, Emergency Preparedness Inspector B. Metrow, ASME Inspector, Illinois Emergency Management Agency Observer: J. Boettcher, Reactor Engineer Approved by: J. Cameron, Chief Projects Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000237/2013005, 05000249/2013005; 10/01/2013 - 12/31/2013;

Dresden Nuclear Power Station, Units 2 & 3, Refueling Outage Activities.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding was self-revealed. The finding was considered a non-cited violation (NCV) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using Inspection Manual Chapter (IMC) 0310, Components Within the Cross Cutting Areas dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated non-cited violation of Technical Specification (TS) 5.4.1, Procedures, was self-revealed on November 17, 2013, when the 2/3 Emergency Diesel Generator (EDG) was inoperable to Unit 3 with an Emergency Core Cooling Systems (ECCS) signal present on Unit 2 due to sensing a low reactor water level condition. Specifically, while the licensee performed procedure DIS 0263-07, Revision 20, Unit 2 ATWS RPT/ARI and ECCS Level Transmitters Channel Calibration Test and EQ Maintenance Inspection, in conjunction with Anticipated Transient Without a Scram (ATWS) level transmitter replacements, a failure to remove trip relays in addition to performing all transmitter replacements at the same time resulted in an unexpected Lo-Lo reactor water level trip signal, subsequently resulting in the auto initiation of the Unit 2 EDG and the 2/3 EDG, causing the 2/3 EDG to be inoperable to Unit 3. The licensee immediately restored the ATWS trip relay circuitry, clearing the Lo-Lo reactor water level signal. This enabled the EDGs to be returned to a standby condition and, thereby, restored 2/3 EDG availability to Unit 3.

The licensees failure to properly implement the steps in the procedure was a performance deficiency that was determined to be more than minor, and thus a finding, because it was associated with the Mitigating Systems Cornerstone attribute of Configuration Control and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding was determined to be of very low safety significance. The finding was of very low safety significance because each of the questions provided in IMC 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, were answered no. The finding has a cross-cutting aspect in the area of human performance, work control, for failing to appropriately coordinate work activities by incorporating actions to address the impact of changes to the work activity on the plant. Specifically, the licensee committed a human performance error by failing to adequately address the impact of work activity changes on the plant and implement the required prerequisites (H.3(b)). (Section 1R20)

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 2 Unit 2 entered the inspection period in power coastdown operations in preparation for a refueling outage. On November 5, 2013, operators reduced power to 60 percent for a planned isolation condenser heat removal test and after the test resumed power coastdown on November 6, 2013. On November 11, 2013, the unit was shut down for refueling outage D2R23. Unit 2 remained shut down until December 1, 2013, when it was synchronized to the grid and achieved full power on December 3, 2013, where it remained for the rest of the inspection period.

Unit 3 Unit 3 was shutdown on October 18, 2013 in order to correct a hydrogen leak in the main generator housing to the stator water cooling system. The unit remained shutdown until October 26, 2013, when repairs were completed. The unit achieved full power on October 27, 2013, where it remained for the rest of the inspection period with the exception of planned short duration reduction in power to support control rod pattern adjustments

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. 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.

Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant structures, systems, and components due to their risk significance or susceptibility to cold weather issues:

• Unit 2/3 Cribhouse; and

• Unit 2/3 Isolation Condenser Makeup Pump House.

This inspection constituted one winter seasonal readiness preparations sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• 2/3B standby gas treatment (SBGT) with 2/3A SBGT out-of-service (OOS);

• Bus 23-1/33-1 and Bus 24-1/34-1 cross tie with Reserve Auxiliary Transformer TR22 OOS; and

• Unit 2 isolation condenser with high pressure coolant injection (HPCI) inoperable.

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, UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also 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 corrective action program (CAP) with the appropriate significance characterization.

Documents reviewed are listed in the Attachment to this report.

These activities constituted three partial system walkdown samples 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:

• Unit 2 high pressure heaters/steam lines, elevation 517, Fire Zone 8.2.5A;

• Unit 2 low pressure heater bays, elevation 517, Fire Zone 8.2.5B;

• Unit 2 low pressure heater bays, elevation 538, Fire Zone 8.2.6B; and

• Unit 2 torus, elevation 476, Fire Zone 1.1.2.1 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 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 to this report, 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 four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection (ISI) Activities

From November 12 through 18, 2013, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, risk significant piping and components, and containment systems in Unit 2.

The inservice inspections described in Sections 1R08.1 and 1R08.5 below constituted one inspection sample as defined in IP 71111.08-05.

.1 Piping Systems ISI

a. Inspection Scope

The inspectors observed the following non-destructive examinations mandated by the American Society of Mechanical Engineers (ASME)Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Ultrasonic examination (UT) of the isolation condenser return line pipe-to-elbow welds;

• UT of the main steam pipe-to-elbow weld 2/1/3001D-20/20-3;

• Automated phased array UT of the N1B-3 nozzle-to-safe-end weld; and

• Magnetic particle examination of reactor shutdown cooling piping stanchion attachment weld 2/1/1001A-16/M-1159D-260(IWA).

The inspectors reviewed the following examination record with a recordable indication accepted for continued service to determine whether acceptance was in accordance with the ASME Code Section XI or an NRC-approved alternative.

• Surface indication identified in the vertical shell-to-fillet repair weld 1A on the standby liquid control tank (Report No.11-716).

The inspectors observed and/or reviewed records for the following pressure boundary welds completed for risk significant systems during the outage to determine if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the construction Code, and/or the NRC approved Code relief request.

Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine whether the weld procedures were qualified in accordance with the requirements of the Construction Code and the ASME Code,Section IX.

• Lower head flange face repair weld No. 1 on the low pressure coolant injection heat exchanger (WO 01287892-01);

• Recirculation system piping overlay weld PS2-TEE/202-4B (WO 1444980-01);and

• Standby liquid control tank-to-shell repair weld areas (WO 01483448-01).

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI related problems entered into the licensees Corrective Action Program and conducted interviews with licensee staff to determine if:

• the licensee had established an appropriate threshold for identifying ISI related problems;

• the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

• the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings were identified

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On October 18, 2013, the inspectors observed operators performing a down-power and shutdown of Unit 3 for a maintenance outage. This was an activity that required heightened awareness and was related to increased risk. 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 (if applicable);

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).

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

This inspection constituted one quarterly licensed operator heightened activity/risk 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:

• Maintenance Rule Z03, control rod drive; and

• Maintenance Rule Z5701, main control room ventilation.

The inspectors reviewed events such as where ineffective equipment maintenance had resulted or could have resulted in valid or invalid automatic actuations of engineered safeguards systems and 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 Assessments and Emergent Work Control

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:

• Unit 3 high pressure coolant injection (HPCI) with isolation condenser unavailable during emergent repairs to 3-1301-3 valve control circuit repairs;

• Unit 2 Yellow risk due to 2A fuel pool cooling train OOS during pump breaker replacement; and

• Unit 3 Yellow risk for 2/3A SBGT train OOS.

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.

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

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Unit 3 isolation condenser (IC) initiation circuit relay failure;

• Secondary containment conditions during 2/3B SBGT run;

• Snubber 2-3001A-42 failed functional testing (tension test) historic operability;

• HPCI injection valve 2-2301-8 preconditioning;

• LPCI injection valve 2-1501-21B failed to stroke open associated with degraded auxiliary electrical contact;

• HPCI check valve in vertical piping; and

• Degraded power cable to Unit 2 IC steam admission motor operated valve, 2-1301-1.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the 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 UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, 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. Documents reviewed are listed in the to this report.

This operability inspection constituted seven samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

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:

• Work Order (WO) 010106190-01, D3 22Y EQ Torus to Reactor Building Diff PT XMTR Replacement;

• WO 01681150, IM PMT Isolation Condenser Time Relay 3-0595-117A;

• WO 01623420, Contingency Repairs to the 2-0220-58B Feedwater Check Valve, Task 08 and WO 01623422; Operations Perform As Left LLRT 2-0220-62B per DOS 7000-26; Task 06;

• WO 01689458-01, EM MCC 28-7/29-7 Did Not Transfer as Expected;

• WO 01511291-04 and -20, D2 RFL TS Perform 10% Sample Select Criteria per DTS 0020-02, Following Snubber 2-3001A-42 Failure; and

• WO 01225306-02, PMT Run Pump and Check Schraeder Valve for Leaks.

These activities were selected based upon the structure, system, or component's 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 (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 TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted six post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 2 refueling outage (RFO), conducted November 11, 2013 to December 1, 2013, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown and cool down processes and monitored licensee controls over the outage activities listed below:

• licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TS when taking equipment out of service;

• implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing;

• installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error;

• controls over the status and configuration of electrical systems to ensure that TS and OSP requirements were met, and controls over switchyard activities;

• monitoring of decay heat removal processes, systems, and components;

• controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system;

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

• controls over activities that could affect reactivity;

• maintenance of secondary containment as required by TS;

• licensee fatigue management, as required by 10 CFR 26, Subpart I;

• refueling activities, including fuel handling and core alterations;

• startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing; and

• licensee identification and resolution of problems related to RFO activities.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RFO sample as defined in IP 71111.20-05.

b. Findings

Introduction:

A finding of very low safety significance (Green) and associated non-cited violation of Technical Specification (TS) 5.4.1, Procedures, was self-revealed on November 17, 2013, when the 2/3 EDG was inoperable to Unit 3 with an emergency core cooling system (ECCS) signal present on Unit 2 due to sensing a low reactor water level condition. Specifically, while the licensee performed Procedure DIS 0263-07, Revision 20, Unit 2 ATWS [anticipated transient without scram] RPT/ARI and ECCS Level Transmitters Channel Calibration Test and EQ Maintenance Inspection, in conjunction with ATWS level transmitter replacements, a failure to remove trip relays in addition to performing all transmitter replacements at the same time resulted in an unexpected Lo-Lo reactor water level trip, subsequently resulting in the auto initiation of the U2 EDG and the 2/3 EDG, causing the 2/3 EDG to be inoperable and unavailable to Unit 3.

Description:

During performance of the replacement of the Unit 2 ATWS level transmitters, a failure to remove trip relays in addition to performing all transmitter replacements at the same time versus the original schedule sequence resulted in an unexpected Lo-Lo reactor water level trip signal, subsequently resulting in the auto initiation of the U2 EDG and the 2/3 EDG, causing the 2/3 EDG to be inoperable and unavailable to Unit 3. The licensee entered TS 3.8.1, Required Action D.2, to restore the 2/3 EDG to operable within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The licensee immediately restored the ATWS trip relay circuitry, clearing the Lo-Lo reactor water level signal. This allowed them to return the EDGs to a standby condition and, thereby, restored 2/3 EDG availability to Unit 3 and TS 3.8.1 was exited.

According to the licensees apparent cause report, approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to work execution, the Outage Specialist Group revised the level transmitter replacement schedule. Initially, the level transmitters were to be replaced sequentially utilizing individual work packages (WO 1645246-01, 1645249-01, 1645251-01, 1645248-01)which contained instructions to collect the As Found data, replace the transmitter, and then restore. After all four transmitters were replaced, the ATWS level transmitter surveillance DIS 0263-07 (WO 1488328-01) was to be completed. The schedule revision directed the Instrument Maintenance Department (IMD) to perform the As Founds for all four transmitters, simultaneously replace the transmitters, then complete the As Lefts, completing DIS 0263-07. The scheduling change resulted in DIS 0263-07 being used to gather the As Found data. In addition, replacing the transmitters in parallel required removal of the associated Lo-Lo reactor water level trip relays prior to replacement to prevent the one out of two taken twice logic that provides the trip function.

The licensee post event investigation identified that the IMD First Line Supervisor (FLS)annotated the ATWS level transmitter replacement work package steps to remove the relays as work performed under WO #148828-01. The licensee interviewed the IMD FLS and identified the FLS annotated this note based upon shift turnover, the point at which the revised schedule was currently at, and the notification from the IMD Outage Scheduler/Lead that the work was ready. In addition, procedure DIS 0263-07, step E.5 was not adequately implemented in that it requires technicians and supervisors to identify that no other ECCS or ATWS testing or maintenance

(is) ongoing that will affect logic tested in (the) surveillance.

Analysis:

The inspectors determined that the failure to properly implement the steps in DIS 0263-07 and ATWS level transmitter work packages (WO 1645246-01, 1645249-01, 1645251-01, 1645248-01) was contrary to the requirements of TS 5.4.1, Procedures, and was a performance deficiency warranting further review. The performance deficiency was determined to be more than minor, and thus a finding, in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Mitigating Systems Cornerstone Attribute of Configuration Control and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, dated June 19, 2012. The inspectors reviewed the Mitigating Systems Screening Questions in Appendix A, Exhibit 2 and answered no to all questions. As a result, the finding was determined to be very low safety significance (Green).

This finding has a cross-cutting aspect in the area of human performance, work control, for failing to appropriately coordinate work activities by incorporating actions to address the impact of changes to the work activity on the plant. Specifically, the licensee committed a human performance error by failing to adequately address the impact of work activity changes on the plant and implement the required prerequisites, which resulted in the 2/3 EDG being inoperable to Unit 3 (H.3(b)).

Enforcement:

Technical Specification Section 5.4.1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. NRC Regulatory Guide 1.33, Appendix A, Section 9a, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.

Procedure DIS 0263-07, Unit 2 ATWS RPT/ARI and ECCS Level Transmitters Channel Calibration Test and EQ Maintenance Inspection, Section E Prerequisites, Step 5 requires technicians to verify that no other ECCS or ATWS testing or maintenance is ongoing that will affect logic tested in surveillance. Contrary to the above, on November 17, 2013, while performing the replacement of the ATWS level transmitters, the licensee failed to implement Step 5 of procedure DIS 0263-07, Section E. Specifically, the licensee failed to correctly implement the prerequisites outlined in the procedure. The issue was entered into the licensees CAP as IR 1586451.

Because this violation was of very low safety significance and it was entered into the licensees CAP (IR 1586451), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000237/2013005-01; 05000249/2013005-01, Inadvertent Lo-Lo Reactor Water Level Indication Received During Maintenance Resulting in Unavailability of the 2/3 EDG to Unit 3).

.2 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for a planned maintenance outage on Unit 3 that began on October 18, 2013 and continued through October 26, 2013. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The inspectors observed or reviewed the reactor shutdown and cool down, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, personnel fatigue management, startup and heatup activities, and identification and resolution of problems associated with the outage. The licensee performed a planned maintenance outage on Unit 3 following indications of a hydrogen leak from the main generator housing environment into the stator water cooling system. Licensee subsequent investigation identified three small through wall flaws into the stator water cooling system inside the main generator housing. The inspectors observed the licensees adverse condition monitoring plan prior to the commencement of the outage, troubleshooting and inspection of the stator water cooling system, and system repairs and post maintenance testing.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one other outage sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

1R22 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:

• WO 01489069, D2 30M/RFL TS LLRT MSIV 203-1A & 203-2A Dry Test (isolation valve);

• WO 01429950-01, D2 2Y EQ LPCI System XMTR Calibration/Inspection (routine);

• WO 01659462, U2 Diesel Generator Cooling Water Pump Quarterly Pump and Valve Surveillance (routine);

• WO 01205408, OP D2 5Y TS Isolation Condenser Heat Removal Test (routine);

• WO 01489071, D2 2Y/RFL TS Bus 24-1 UV and ECCS Integrated Functional Test (routine); and

• WO 01506607, D2 RFL TS 1000 PSI Reactor Vessel System Leakage Test/Hydrostatic (RCS leak detection).

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

• did preconditioning occur;

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

• acceptance criteria were clearly stated, demonstrated operational readiness, and were 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 UFSAR, 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 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 four routine surveillance testing samples, one isolation valve sample, and one RCS leak detection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The Office of Nuclear Security and Incident Response headquarters staff performed an in-office review of the latest revisions to the Emergency Plan and various Emergency Plan Implementing Procedures (EPIPs) located under ADAMS Accession Numbers ML123260651, ML130180297, ML13162A199, and ML13200A124, as listed in the to this report.

The licensee transmitted the EPIP revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment to this report.

This emergency action level and emergency plan change inspection constituted one sample as defined in Inspection Procedure (IP) 7114.04-05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspector observed an emergency preparedness drill in the Technical Support Center on October 3, 2013, which required emergency plan implementation by a qualified Site Emergency Director and members of the Emergency Response Organization (ERO). This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the team. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the EROs performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.

This inspection of the licensees emergency preparedness drill constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational Radiation Safety and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

The inspection activities supplement those documented in NRC Inspection Report 05000237(249)/2013002 and constitute one complete sample as defined in IP 71124.01-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed all licensee performance indicators for the Occupational Exposure Cornerstone for follow-up. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors determined if there have been changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether the licensee assessed the potential impact of these changes and has implemented periodic monitoring, as appropriate, to detect and quantify the radiological hazard.

The inspectors reviewed the last two radiological surveys from selected plant areas and evaluated whether the thoroughness and frequency of the surveys where appropriate for the given radiological hazard.

The inspectors selected the following radiologically risk-significant work activities that involved exposure to radiation:

• D2R23 Drywell In Service Inspection Activities;

• D2R23 Refuel Floor Reactor Disassembly/Reassembly and Related Activities;

• D2R23 Refuel Floor Reactor in Vessel Activities;

• D2R23 Scaffold Installation/Removal Activities (Excluding Drywell); and

• D2R23 Drywell Control Rod Drive (CRD) System Maintenance Activities.

For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

• identification of hot particles;

• the presence of alpha emitters;

• the potential for airborne radioactive materials, including the potential presence of transuranics and/or other hard-to-detect radioactive materials (This evaluation may include licensee planned entry into non-routinely entered areas subject to previous contamination from failed fuel.);

• the hazards associated with work activities that could suddenly and severely increase radiological conditions and that the licensee has established a means to inform workers of changes that could significantly impact their occupational dose; and

• severe radiation field dose gradients that can result in non-uniform exposures of the body.

The inspectors observed work in potential airborne areas and evaluated whether the air samples were representative of the breathing air zone. The inspectors evaluated whether continuous air monitors were located in areas with low background to minimize false alarms and were representative of actual work areas. The inspectors evaluated the licensees program for monitoring levels of loose surface contamination in areas of the plant with the potential for the contamination to become airborne.

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors reviewed the following radiation work permits used to access high radiation areas and evaluated the specified work control instructions or control barriers:

• RWP 10014902; D2R23 Drywell In Service Inspection Activities;

• RWP 10014939; D2R23 Refuel Floor Reactor Disassembly/Reassembly and Related Activities;

• RWP 10014940; D2R23 Refuel Floor Reactor in Vessel Activities; and

• RWP 10014860; D2R23 Scaffold Installation/Removal Activities (Excluding Drywell).

For these radiation work permits, the inspectors assessed whether allowable stay times or permissible dose (including from the intake of radioactive material) for radiologically significant work under each radiation work permit were clearly identified. The inspectors evaluated whether electronic personal dosimeter alarm set-points were in conformance with survey indications and plant policy.

The inspectors reviewed selected occurrences where a workers electronic personal dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately to the off-normal condition. The inspectors assessed whether the issue was included in the Corrective Action Program and dose evaluations were conducted as appropriate.

b. Findings

No findings were identified.

.4 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors observed locations where the licensee monitors potentially contaminated material leaving the radiological control area and inspected the methods used for control, survey, and release from these areas. The inspectors observed the performance of personnel surveying and releasing material for unrestricted use and evaluated whether the work was performed in accordance with plant procedures and whether the procedures were sufficient to control the spread of contamination and prevent unintended release of radioactive materials from the site. The inspectors assessed whether the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.

The inspectors selected several sealed sources from the licensees inventory records and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors assessed whether radiation monitoring devices were placed on the individuals body consistent with licensee procedures. The inspectors assessed whether the dosimeter was placed in the location of highest expected dose or that the licensee properly employed an NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

The inspectors reviewed the following radiation work permits for work within airborne radioactivity areas with the potential for individual worker internal exposures:

• RWP 10014939; D2R23 Refuel Floor Reactor Disassembly/Reassembly and Related Activities;

• RWP 10014940; D2R23 Refuel Floor Reactor in Vessel Activities;

• RWP 10014860; D2R23 Scaffold Installation/Removal Activities (Excluding Drywell); and

• RWP 10014896; D2R23 Drywell Control Rod Drive (CRD) System Maintenance Activities.

For these radiation work permits, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed barrier (e.g., tent or glove box) integrity and temporary high-efficiency particulate air ventilation system operation.

b. Findings

No findings were identified.

.6 Risk-Significant High Radiation Area and Very-High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors evaluated licensee controls for very-high radiation areas and areas with the potential to become a very-high radiation area to ensure that an individual was not able to gain unauthorized access to the very high radiation area.

b. Findings

No findings were identified.

.7 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be human performance errors. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. The inspectors discussed with the radiation protection manager any problems with the corrective actions planned or taken.

b. Findings

No findings were identified.

.8 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all radiation protection work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the radiation work permit controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors reviewed radiological problem reports since the last inspection that found the cause of the event to be radiation protection technician error. The inspectors evaluated whether there was an observable pattern traceable to a similar cause. The inspectors assessed whether this perspective matched the corrective action approach taken by the licensee to resolve the reported problems.

b. Findings

No findings were identified.

.9 Problem Identification and Resolution (02.09)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees Corrective Action Program. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring and exposure controls. The inspectors assessed the licensees process for applying operating experience to their plant.

b. Findings

No findings were identified.

2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls

The inspection activities supplement those documented in NRC Inspection Report 05000237(249)/2012005 and 05000237(249)/2013003, and constitute one complete sample as defined in IP 71124.02-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed site-specific procedures associated with maintaining occupational exposures as-low-as-reasonably-achievable (ALARA), which included a review of processes used to estimate and track exposures from specific work activities.

b. Findings

No findings were identified.

.2 Radiological Work Planning (02.02)

a. Inspection Scope

The inspectors selected the following work activities of the highest exposure significance:

• D2R23 Drywell In Service Inspection Activities;

• D2R23 Refuel Floor Reactor Disassembly/Reassembly and Related Activities; and

• D2R23 Refuel Floor Reactor in Vessel Activities.

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors determined whether the licensee reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.

b. Findings

No findings were identified.

.3 Verification of Dose Estimates and Exposure Tracking Systems (02.03)

a. Inspection Scope

The inspectors reviewed the assumptions and basis (including dose rate and man-hour estimates) for the current annual collective exposure estimate for reasonable accuracy for select ALARA work packages. The inspectors reviewed applicable procedures to determine the methodology for estimating exposures from specific work activities and the intended dose outcome.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

The inspection activities supplement those documented in NRC Inspection Report 05000237(249)/2012004 and constitute one complete sample as defined in IP 71124.05-05.

.1 Problem Identification and Resolution (02.04)

a. Inspection Scope

The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensee Corrective Action Program. The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring instrumentation.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Leakage performance indicator (PI) for Dresden Nuclear Power Station Units 2 and 3 covering the period from the fourth quarter 2012 through third quarter 2013. To determine the accuracy of the 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 7, dated August 2013, were used. The inspectors reviewed the licensees operator logs, RCS leakage tracking data, issue reports, event reports and NRC Integrated Inspection Reports for the period of October 2012 through September 2013 to validate the accuracy of the submittals. 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 two reactor coolant system leakage samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the radiological effluent Technical Specification/Offsite Dose Calculation Manual (RETS/ODCM) radiological effluent occurrences PI for the period from the first quarter 2012 through the third quarter 2013.

The inspectors used PI definitions and guidance contained in the Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the to this report.

This inspection constituted one Radiological Effluent Technical Specification/Offsite Dose Calculation Manual radiological effluent occurrences 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 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, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the period of June through December 2013, 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 one semi-annual trend 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 Hydrogen Leak Into Unit 3 Main Generator Stator Water Cooling System Results In Unit

Shutdown On October 9, 2013 at 0310, the licensee received a Stator Cooling Panel Trouble alarm on Unit 3. Operator response identified local alarm Hydrogen Leak Rate High was active. Over the next 90 minutes operators noted a significant rise (4 to 172 standard cubic feet per day) in hydrogen flow rate as indicated by the stator leak monitoring system (SLMS). These indications led operators to determine that a leak of hydrogen gas into the stator water cooling system inside the main generator housing was occurring. The inspectors observed licensee actions to ensure hydrogen gas was not concentrating in the turbine building and was being safely exhausted to the outside environment as well establishing an adverse condition monitoring plan to include hourly logging of pertinent parameters including SLMS hydrogen flow rate, main generator hydrogen pressure, and stator bar temperatures was being performed and analyzed for negative trends.

On October 18, 2013, the licensee commenced a maintenance outage on Unit 3 to identify and repair the source of the hydrogen leak into the stator water cooling system.

The licensee identified small defects in the stator water cooling system connection ring which is located inside the main generator housing. Due to the normal operating pressure of the hydrogen environment in the main generator (60 psig) and the stator water cooling system (approximately 25 - 30 psig) the hydrogen would be driven through the defects into the stator water cooling system and then eventually out a system vent located at the roof of the turbine building. The licensee was able to repair the two larger defects but was unable to successfully remove a pin hole sized flaw. The inspectors observed portions of the flaw repair and post maintenance vacuum testing utilized to validate the integrity of the repairs made. Prior to restart the licensee evaluated the small defect which remained and determined that safe operation of the main generator was not impacted by continued operation with the flaw. No findings or violations of NRC requirements were identified.

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

.2 (Closed) Licensee Event Report 05000237/2013-003-00; 05000249/2013-003-00,

Secondary Containment Inoperable Due to Two Interlock Doors Being Open Simultaneously On September 23, 2013, between 1655:59 and 1656:05, the secondary containment interlock doors separating the reactor building and the 2/3 emergency diesel generator (EDG) room were simultaneously open resulting in an unplanned entry into secondary containment, TS 3.6.4.1. An operator on scene rapidly shut the secondary containment boundary door on the 2/3 EDG side of the interlock ensuring that reactor building to outside environment differential pressure requirements were maintained at all times. At the time of the event, the operator actuated the reactor building side doorway in order to complete passing through the interlock when they reported hearing clicking noises from the interlock relays followed by both the 2/3 EDG side and reactor building side doors opening. The operator manually closed the 2/3 EDG side door, proceeded to exit the interlock through the reactor side door and then reported the event to the main control room operators.

Following the event, the licensee performed troubleshooting on the interlock to determine the cause. Licensee troubleshooting included a voltage test of the interlock circuit relays, visual inspection of electrical connections, resistance readings across applicable relay contacts, and monitoring of relay voltages via a chart recorder while functionally testing the interlock doors. The interlock doors were challenged more than 500 times in all conceivable operational scenarios but a re-creation of the failure experienced on September 23, 2013 did not occur. In addition, the latch bolt monitor (LBM) switch tripper associated with the 2/3 EDG room door strike which was the faulted component in the June 28, 2013 failure of this interlock was shown to be successfully performing its function. The licensee also performed an Equipment Apparent Cause Evaluation (EACE) 1545683-02 in support of the troubleshooting performed in the field and was not able to identify a definitive cause for this event. Licensee engineering identified intermittent relay malfunction or intermittent limit switch failure as the two most likely failure modes. Based on the report of relay clicking prior to both doors opening, it is surmised that an intermittent relay malfunction degraded the voltage to the diesel side door strike resulting in the failure.

The licensee installed a permanent modification to the circuit logic for the reactor building to 2/3 EDG interlock in November 2013. The modification includes ladder logic circuitry which addresses the previously identified need to establish an XOR gate style logic ensuring that both doors do not open when simultaneously operated. In addition the new logic is designed to prevent interlock failure due to a loss of power (125 VDC and 120 VAC) and addresses parts obsolescence concerns. The inspectors reviewed the licensees corrective actions and had no concerns. No findings or violations of NRC requirements were identified.

The licensee reported this event in accordance with 10 CFR 50.73(a)(2)(v)(C), as an event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

This LER is closed.

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

.3 (Closed) Licensee Event Report 05000237/2013-001-01: 05000249/2013-001-01,

Secondary Containment Inoperable Due to Two Interlock Doors Being Open Simultaneously The licensee submitted supplemental LER 05000237/2013-001-01; 05000249/2013-001-01 in order to describe the results of EACE 1545683-02 performed following the 2/3 EDG to reactor building interlock failures of June 28, 2013 and September 23, 2013.

In addition, the supplemental LER describes corrective actions taken to address the failures including redesign of the 2/3 EDG door strike latch bolt monitor switch tripper which was specifically identified as the failed component directly responsible for the June 28, 2013, event and the relay circuitry modification addressing latent design vulnerabilities for the interlock logic circuit. No findings or violations of NRC requirements were identified.

The licensee reported this event in accordance with 10 CFR 50.73(a)(2)(v)(C), any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material.

Licensee LER 05000237/2013-001-00; 05000249/2013-001-00 was reviewed and closed in NRC Inspection Report 05000237/2013004; 05000249-2013004.

This supplemental LER is closed.

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

4OA5 Other Activities

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

Recommendation 2.3 Seismic Walkdowns

a. Inspection Scope

The inspectors continued to accompany the licensee, on a sampling basis, during their seismic walkdowns to verify that the licensees walkdown activities were conducted using the methodology endorsed by the NRC. Specifically, the inspectors observed the licensee inspect components in the Unit 2 Drywell and Torus areas during refueling outage D2R23. The licensee will periodically continue to walkdown identified components as they become accessible. These walkdowns are being performed at all sites in response to a letter from the NRC to licensees, entitled Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident, dated March 12, 2012 (ADAMS Accession No.

ML12053A340).

3 of the March 12, 2012, letter requested licensees to perform seismic walkdowns using an NRC-endorsed walkdown methodology. Electric Power Research Institute (EPRI) document 1025286 titled, Seismic Walkdown Guidance, (ADAMS Accession No. ML12188A031) provided the NRC-endorsed methodology for performing seismic walkdowns to verify that plant features, credited in the current licensing basis (CLB) for seismic events, are available, functional, and properly maintained.

The inspectors closed Temporary Instruction 2515/188 in Dresden NRC Inspection Report 05000237/2012005; 05000249/2012005 following a review of the licensees initial walkdown of identified components. The licensee continues to perform these seismic walkdowns as components located in inaccessible areas become available.

b. Findings

No findings were identified.

.2 (Closed) Temporary Instruction 2515/190 - Inspection of the Proposed Interim Actions

Associated with Near-Term Task Force Recommendation 2.1 Flooding Hazard Evaluations.

a. Inspection Scope

The inspectors independently verified that the licensees proposed interim actions as described in a letter submitted to the NRC titled Supplemental Response to NRC Request for Information Pursuant to 10 CFR 50.54(f) Regarding the Flooding Aspects of Recommendation 2.1 of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated August 28, 2013 (ADAMS Accession No.

ML13241A288) would perform their intended function for flooding mitigation.

The inspectors verified that the licensees proposed interim actions were acceptable through:

• Visual inspection of the flood protection feature looking for indications of degradation that would prevent its credited function from being performed.

• Visual observation and by review of technical documents when appropriate to validate flood protection feature functionality.

• Reasonable simulation in the case of deploying the Aqua Dam, Isolation Condenser Make-up Pump House flood barriers, and reactor building flood barriers.

The inspectors verified that issues identified were entered into the licensee's corrective action program.

b. Findings

No findings were identified.

.3 Licensee Strike Contingency Plans

a. Inspection Scope

The inspectors reviewed the licensees work stoppage plans to determine if the plans adequately addressed the areas of reactor operations, emergency planning, facility security, fire protection, technical specifications, and other regulatory requirements in the event of an employee strike or management lockout. The inspectors reviewed records and conducted interviews with licensee staff to verify that qualified personnel would be available to meet the minimum requirements for safe operation of the plant, if a strike or lockout were to occur. No actual work stoppage occurred during the inspection period.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 7, 2014, the inspectors presented the inspection results to Mr. S. Marik, and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the inservice inspection with Site Vice President, Mr. S. Marik, on November 18, 2013.

• The inspection results for the areas of radiological hazard assessment and exposure controls; occupational as-low-as-reasonably-achievable planning and controls; and RETS/ODCM radiological effluent occurrences performance indicator verification with Mr. J. Washko, Plant Manager, on November 22, 2013.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Marik, Site Vice President, Former Station Plant Manager

J. Washko, Station Plant Manager

D. Anthony, NDE Services Manager

J. Biegelson, Engineering

H. Bush, Radiation Protection Manager

P. Chambers, Dresden Licensed Operator Requalification Training Lead

P. DiGiovanna, Training Director

H. Do, Engineering Manager

D. Doggett, Emergency Preparedness Manager

J. Fox, Design Engineer

G. Graff, Nuclear Oversight Manager

M. Hosain, Site EQ Engineer

G. Howard, Engineering

B. Kapellas, Operations Director

J. Knight, Director, Site Engineering

M. Knott, Instrument Maintenance Manager

J. Kish, Site ISI

G. Morrow, Regulatory Assurance Manager

M. McDonald, Maintenance Director

C. Mckean, NDE Level III

D. OFlanagan, Security Manager

M. Otten, Operations Training Manager

M. Overstreet, RP General Supervisor

M. Pavey, RP Technical Support

R. Schmidt, Chemistry and Environmental Manager

J. Sipek, Work Control Director

D. Throne, Operations

D. Walker, Regulatory Assurance - NRC Coordinator

B. Weight, Design Engineering

Nuclear Regulatory Commission

J. Cameron, Chief, Branch 6, Division of Reactor Projects

J. Rutkowski, Project Engineer, Branch 6

IEMA

R. Zuffa, Illinois Emergency Management Agency

M. Porfirio, State Resident Inspector

Attachment

LIST OF ITEMS

Opened

05000237/2013005-01 NCV Inadvertent Lo-Lo Reactor Water Level Indication

05000249/2013005-01 Received During Maintenance Resulting in Unavailability of the 2/3 EDG to Unit 3 (1R20)

Closed

05000237/2013005-01 NCV Inadvertent Lo-Lo Reactor Water Level Indication

05000249/2013005-01 Received During Maintenance Resulting in Unavailability of the 2/3 EDG to Unit 3 (1R20)

05000237/2013-003-00 LER Secondary Containment Inoperable Due to Two

05000249/2013-003-00 Interlock Doors Being Open Simultaneously

05000237/2013-001-01 LER Secondary Containment Inoperable Due to Two

05000249/2013-001-01 Interlock Doors Being Open Simultaneously NRC Temporary Instruction 2515/190 Inspection of the Proposed Interim Actions Associated with Near-Term Task Force Recommendation 2.1 Flooding Hazard Evaluations.

Discussed

NRC Temporary Instruction 2515/188 Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns