IR 05000237/2012004

IR 05000237-12-004, 05000249-12-004 & 07200037-12-001, Exelon Generation Company LLC, 07/01/2012 - 09/30/2012, Dresden Nuclear Power Station, Units 1, 2 & 3, Integrated Inspection Report

ML12293A352
Person / Time
Site:	Dresden
Issue date:	10/19/2012
From:	Jamnes Cameron NRC/RGN-III/DRP/B6
To:	Pacilio J Exelon Nuclear
References
IR-12-004
Download: ML12293A352 (51)

Text

October 19, 2012

SUBJECT:

DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3, INTEGRATED INSPECTION REPORT 05000237/2012004, 05000249/2012004, AND 07200037/2012001

Dear Mr. Pacilio:

On September 30, 2012, 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 October 17, 2012, with Mr. D. Czufin, 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.

No NRC-identified or self-revealing findings were identified during this inspection. However, a licensee-identified violation which was determined to be of very low safety significance is listed in Section 4OA7 of this report. The NRC is treating this violation as a non-cited violation (NCV)

consistent with Section 2.3.2 of the 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 Dresden 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 Agencywide Document Access and Management System (ADAMS).

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

Sincerely,

/RA/

Jamnes L. Cameron, Chief Branch 6 Division of Reactor Projects Docket Nos. 50-237, 50-249 and 72-037 License Nos. DPR-19 and DPR-25

Enclosure:

Inspection Report 05000237/2012004, 05000249/2012004, and 07200037/2012001 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000237; 05000249; and 0500072037 License Nos: DPR-19 and DPR-25 Report No: 05000237/2012004; 05000249/2012004; 07200037/2012001 Licensee: Exelon Generation Company, LLC Facility: Dresden Nuclear Power Station, Units 1, 2 and 3 Location: Morris, IL Dates: July 1 through September 30, 2012 Inspectors: G. Roach, Senior Resident Inspector C. Phillips, Senior Resident Inspector D. Meléndez-Colón, Resident Inspector T. Go, Health Physicist M. Learn, Reactor Engineer, Materials Control, ISFSI, and Decommissioning Branch (MCID), Division of Nuclear Materials Safety (DNMS)

R. Edwards, Reactor Inspector, MCID, DNMS Approved by: J. Cameron, Chief Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000237/2012004, 05000249/2012004; 07200037/2012001; 07/01/2012 - 09/30/2012; Dresden Nuclear Power Station, Units 1, 2 & 3.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. 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 No NRC-identified or self-revealing findings were identified during this inspection.

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees corrective action program. This violation and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 2 On July 5, 2012, operators reduced power to approximately 83 percent electrical to maintain discharge canal effluent temperatures to stay in compliance with the site's National Pollutant Discharge Elimination System (NPDES) permit. Operators restored power to 100 percent on July 8, 2012.

On July 16, 2012, operators reduced power to approximately 89 percent electrical for an unplanned repair of a suction line leak on the A circulating water pump. Operators restored power to 100 percent following repairs on July 19, 2012.

On August 30, 2012, operators began to downpower for an unplanned shutdown due to circulating water leaking into the condensate section of the main condenser. The licensee repaired a failed condenser waterbox vent line and restored power to 100 percent on September 7, 2012.

Unit 3 On July 4, 2012, operators reduced power to approximately 80 percent electrical to maintain discharge canal effluent temperatures to stay in compliance with the site's NPDES permit.

Operators restored power to 100 percent on July 10, 2012.

On July 15, 2012, operators reduced power to approximately 88 percent electrical to maintain condenser vacuum during a planned condenser flow reversal with high cooling water temperatures. Operators restored power to 100 percent on the same day.

On September 19, 2012, operators reduced power to approximately 87 percent electrical due to air in-leakage which resulted in low condenser vacuum during a condensate demineralizer backwash. Operators restored power to 100 percent on the same day.

On September 21, 2012, operators began a core coastdown.

On September 22, 2012, operators reduced power to approximately 28 percent electrical for a planned oil addition to the A reactor recirculation pump motor. Operators resumed the units core coastdown maximum power level of approximately 99 percent electrical on the same day.

With the exception of short periods for routine maintenance and surveillances, Unit 3 remained in core coastdown for the remainder of the reporting period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - Severe Thunderstorm Watch

a. Inspection Scope

Since thunderstorms with potential high winds were forecast in the vicinity of the facility for September 22, 2012, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. On September 22, 2012, the inspectors walked down scaffolding adjacent to the Unit 3 bus duct cooling system, in addition to the licensees emergency alternating current (AC) power systems, because their safety related functions could be affected or required as a result of high winds or the loss of offsite power. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate.

During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during periods of high winds or a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. 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.

The inspectors also reviewed a sample of corrective action program (CAP) items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in Inspection Procedure (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:

• Unit 2 emergency diesel generator (EDG) during Unit 3 EDG cooling water pump in-service test run;

• Unit 2/3 diesel fire pump (DFP) during Unit 1 DFP capacity test; and

• Unit 2 A core spray during B core spray planned maintenance.

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 CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

During the weeks of September 10 and September 17, 2012, the inspectors performed a complete system alignment inspection of the Unit 3 containment cooling service water (CCSW) 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 lineups; 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 walkdown 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:

• Fire Zone 8.2.6A, Unit 2 Reactor Feed Pump Vent H2 Seal Area, Elevation 538;

• Fire Zone 1.1.1.4, Unit 3 Secondary Containment, Elevation 570;

• Fire Zone 1.1.1.6, Reactor Building Refueling Floor, Elevation 613;

• Fire Zone 8.2.4, Turbine Building 2/3 Cable Tunnel, Elevation 502; and

• Fire Zone 6.2, Auxiliary Electrical Equipment Room, Elevation 517.

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

b. Findings

No findings were identified.

1R06 Flooding

.1 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 bunkers/manholes subject to flooding:

• Station blackout (SBO) number 2 and SBO number 3 cable vaults.

Specific documents reviewed during this inspection are listed in the Attachment to this report. This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the 2B reactor building closed cooling water heat exchanger to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions. Documents reviewed for this inspection are listed in the Attachment to this document.

This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On July 30, 2012, and September 4, 2012, the inspectors observed two separate crews of licensed operators in the plants simulator during licensed operator requalification training 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 two quarterly licensed operator requalification program simulator samples as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On July 5, 2012, the inspectors observed Unit 2 control rod drive exercising; on August 7, 2012, the inspectors observed Unit 3 circulating water flow reversal; and on September 19, 2012, the inspectors observed the operators response to a degraded Unit 3 condenser vacuum and unplanned down power. These were activities that required heightened awareness or were 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;

• correct use and implementation of procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions.

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 samples 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:

• 2/3 standby liquid control (SBLC); and

• 2/3 standby gas treatment (SBGT).

The inspectors reviewed licensee 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 Yellow Risk due to unplanned isolation of the isolation condenser during surveillance testing;

• Unit 2 A circulating water pump emergent repairs;

• Unit 2/3 diesel fire pump (DFP) during Unit 1 DFP inspection and overhaul;

• Unit 2 A core spray during B core spray planned maintenance; and

• Failure to Reset 2 A Recirculation Pump MG-Set Scoop Tube 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.

Specific documents reviewed during this inspection are listed in the Attachment to this report. These maintenance risk assessments and emergent work control activities constituted five 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:

• Operability Evaluation 12-003, Byron Event;

• Issue Report (IR) 1353820, 3-1501-3A Diagnostic Test Required Emergent Evaluations;

• IR 1381008, Part 21 for Rosemount 710DU Trip Units;

• IR 1386885, Group V Isolation During DIS 1300-07; and

• IR 1374428, U2 EDGCWP [emergency diesel generator cooling water pump]

Failed to Start.

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.

These operability inspections constituted five samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

• Auxiliary boiler natural gas line.

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed in the course of this inspection are listed in the Attachment to this report.

This inspection constituted one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 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:

• WO 938055, D1 6Y TSTR PM Diesel Fire Pump Inspection & Overhaul;

• WO 1561514, U1 DFP Relief Valve Does Not Seat;

• 3B Core Spray Fragnet;

• WO 01568135-01, 3A/B Recirc Pump Speed Mismatch; and

• WO 01569605, U2 DW [drywell] Entry Identified Leakage from 2-0220-58B 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 PM 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 five PM testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for a forced mid-cycle outage of Unit 2 that began on August 30, 2012, and continued through September 5, 2012. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The inspectors observed portions of the reactor shutdown and cooldown, outage equipment configuration and risk management, electrical lineups, selected clearances to include containment isolation valve repairs and reactor coolant system leakage repairs, control and monitoring of decay heat removal, control of containment activities, startup and heatup activities, and identification and resolution of problems associated with the outage. The licensee entered Mode 3 and progressed to Mode 4 on August 30 in order to address a rapidly degrading chemistry condition in the Unit 2 condensate and feedwater system. A failure in vent piping associated with the main condenser circulating water south central water box enabled circulating water to enter the steam side of the main condenser. The introduction of the raw circulating water added impurities to the condensate water which would have eventually exhausted condensate demineralizers and spread to the reactor had the plant not been placed in a cold shutdown condition. The licensee plugged the affected piping prior to startup and has generated a work order to remove the vent line, which is no longer utilized when filling the circulating water side of the main condenser, during the next Unit 2 refueling outage.

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

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:

• WO 1533903-01, Dresden Unit 2 Qtr TS 2A SBLC Pump Test for In-Service Testing Surveillance, (IST);

• WO 01403433-01, Dresden Unit 3 18M TS Bus 33-1 Degraded Voltage Surveillance, (routine);

• WO 1450508, Dresden Unit 1 AN TSTR/COM Diesel Fire Pump Flow Capacity Test, (routine);

• WO 1514132, Dresden Unit 2 SAN TS Diesel Generator Fast Start Operability Surveillance, (routine); and

• WO 1530522, Dresden Units 2/3 QTR PM Emergency Diesel Pump (Flood Pump) (routine).

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 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 (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, 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, and one inservice testing sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on September 12, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator and the Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

This inspection constituted a partial sample as defined in IP 71124.05-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the plant UFSAR to identify radiation instruments associated with monitoring area radiological conditions including airborne radioactivity, process streams, effluents, materials/articles, and workers. Additionally, the inspectors reviewed the instrumentation and the associated TS requirements for post-accident monitoring instrumentation including instruments used for remote emergency assessment.

The inspectors reviewed a listing of in-service survey instrumentation including air samplers and small article monitors (SAMs), along with instruments used to detect and analyze workers external contamination. Additionally, the inspectors reviewed personnel contamination monitors (PCMs) and PMs, including whole-body counters, to detect workers internal contamination. The inspectors reviewed this list to assess whether an adequate number and type of instruments were available to support operations.

The inspectors reviewed licensee and third-party evaluation reports of the radiation monitoring program since the last inspection. These reports were reviewed for insights into the licensees program and to aid in selecting areas for review (smart sampling).

The inspectors reviewed procedures that govern instrument source checks and calibrations, focusing on instruments used for monitoring transient high radiological conditions, including instruments used for underwater surveys. The inspectors reviewed the calibration and source check procedures for adequacy and as an aid to smart sampling.

The inspectors reviewed the area radiation monitor (ARM) alarm setpoint values and setpoint bases as provided in the TSs and the UFSAR.

The inspectors reviewed effluent monitor alarm setpoint bases and the calculation methods provided in the Offsite Dose Calculation Manual (ODCM).

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down effluent radiation monitoring systems, including at least one liquid and one airborne system. Focus was placed on flow measurement devices and all accessible point-of-discharge liquid and gaseous effluent monitors of the selected systems. The inspectors assessed whether the effluent/process monitor configurations aligned with ODCM descriptions and observed monitors for degradation and out-of-service tags.

The inspectors selected portable survey instruments that were in use or available for issuance and assessed calibration and source check stickers for currency as well as instrument material condition and operability.

The inspectors observed licensee staff performance as the staff demonstrated source checks for various types of portable survey instruments. The inspectors assessed whether high-range instruments were source checked on all appropriate scales.

The inspectors walked down ARMs and containment atmosphere monitors (CAM) to determine whether they were appropriately positioned relative to the radiation sources or areas they were intended to monitor. Selectively, the inspectors compared monitor response (via local or remote control room indications) with actual area conditions for consistency.

The inspectors selected PCMs, PMs, and SAMs and evaluated whether the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

b. Findings

No findings were identified.

.3 Calibration and Testing Program (02.03)

Laboratory Instrumentation

a. Inspection Scope

The inspectors assessed laboratory analytical instruments used for radiological analyses to determine whether daily performance checks and calibration data indicated that the frequency of the calibrations was adequate and there were no indications of degraded instrument performance.

The inspectors assessed whether appropriate corrective actions were implemented in response to indications of degraded instrument performance.

b. Findings

No findings were identified.

Whole Body Counter

a. Inspection Scope

The inspectors reviewed the methods and sources used to perform WBC functional checks before daily use of the instrument and assessed whether check sources were appropriate and aligned with the plants isotopic mix.

The inspectors reviewed WBC calibration records since the last inspection and evaluated whether calibration sources were representative of the plant source term and that appropriate calibration phantoms were used. The inspectors looked for anomalous results or other indications of instrument performance problems.

b. Findings

No findings were identified.

Post-Accident Monitoring Instrumentation

a. Inspection Scope

The inspectors selected containment high-range monitors and reviewed the calibration documentation since the last inspection.

The inspectors assessed whether that electronic calibration was completed for all range decades above 10 rem/hour and whether at least one decade at or below 10 rem/hour was calibrated using an appropriate radiation source.

The inspectors assessed whether calibration acceptance criteria were reasonable, accounted for the large measuring range and the intended purpose of the instruments.

The inspectors selected two effluent/process monitors that were relied on by the licensee in its emergency operating procedures as a basis for triggering emergency action levels and subsequent emergency classifications, or to make protective action recommendations during an accident. The inspectors evaluated the calibration and availability of these instruments.

The inspectors reviewed the licensees capability to collect high-range, post-accident iodine effluent samples.

As available, the inspectors observed electronic and radiation calibration of these instruments to assess conformity with the licensees calibration and test protocols.

b. Findings

No findings were identified.

Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors

a. Inspection Scope

For each type of these instruments used on site, the inspectors assessed whether the alarm setpoint values were reasonable under the circumstances to ensure that licensed material is not released from the site.

The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine consistency with the manufacturers recommendations.

b. Findings

No findings were identified.

Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors

a. Inspection Scope

The inspectors reviewed calibration documentation for at least one of each type of instrument. For portable survey instruments and ARMs, the inspectors reviewed detector measurement geometry and calibration methods and had the licensee demonstrate use of its instrument calibrator as applicable. The inspectors conducted a comparison of instrument readings versus an NRC survey instrument if problems were suspected.

As available, the inspectors selected portable survey instruments that did not meet acceptance criteria during calibration or source checks to assess whether the licensee had taken appropriate corrective action for instruments found significantly out of calibration (greater than 50 percent). The inspectors evaluated whether the licensee had evaluated the possible consequences of instrument use since the last successful calibration or source check.

b. Findings

No findings were identified.

Instrument Calibrator

a. Inspection Scope

As applicable, the inspectors reviewed the current output values for the licensees portable survey and ARM instrument calibrator unit(s). The inspectors assessed whether the licensee periodically measures calibrator output over the range of the instruments used through measurements by ion chamber/electrometer.

The inspectors assessed whether the measuring devices had been calibrated by a facility using National Institute of Standards and Technology traceable sources and whether corrective factors for these measuring devices were properly applied by the licensee in its output verification.

b. Findings

No findings were identified.

Calibration and Check Sources

a. Inspection Scope

The inspectors reviewed the licensees 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, source term to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

b. Findings

No findings were identified.

.4 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 CAP. 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: Mitigating Systems and Public Radiation Safety

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index - Heat Removal System (MS08)

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Heat Removal System performance indicator (MS08) for Dresden Nuclear Power Station Units 2 and 3 covering the period from the second quarter 2011 through the second quarter 2012. 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 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs,IRs, event reports, MSPI derivation reports, and NRC Integrated IRs for the period of second quarter 2011 through the second quarter 2012 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 IR 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 MSPI heat removal system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Residual Heat Removal System (MS09)

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Residual Heat Removal System performance indicator (MS09) for Dresden Nuclear Power Station Units 2 and 3 covering the period from the second quarter 2011 through the second quarter 2012. 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, IRs, MSPI derivation reports, event reports and NRC Integrated IRs for the period of second quarter 2011 through the second quarter 2012 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 IR 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 MSPI residual heat removal system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Cooling Water Systems performance indicator (MS10) for Dresden Nuclear Power Station Units 2 and 3 covering the period from the second quarter 2011 through the second quarter 2012. 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, IRs, MSPI derivation reports, event reports and NRC Integrated IRs for the period of second quarter 2011 through the second quarter 2012 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 IR 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 MSPI cooling water system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent TS (RETS)/ODCM Radiological Effluent Occurrences PI (PR01) for the period from the first quarter 2011 through the first quarter 2012. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees IR 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 RETS/ODCM radiological effluent occurrences sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

.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 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 to this report 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.

.4 Selected Issue Follow-Up Inspection: Issue Report 1369775, Conflict of Procedures

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a potential for a conflict in procedures between security and fire protection procedures in certain security scenarios in IR 1369775, Conflict of Procedures. The inspectors chose this issue for an in-depth review due to the safety and risk significance involved with potentially conflicting procedures. The inspectors reviewed IR 1369775, Conflict of Procedures, DOA 0010-18, Escalated Security Event/Hostile Force Intrusion, and DSSP 0100-CR, Hot Shutdown Procedure - Control Room Evacuation. In addition, the inspectors interviewed members of the operations department.

The original concern described in IR 1369775, Conflict of Procedures, was that in one procedure operators were directed outside while in the other procedures operators were prevented from going outside. The inspectors determined whether the operators went outside or not would be dependent upon the situation at the time and was not a potential conflict.

The inspectors did identify, however, that there were steps in DOA 0010-18, Escalated Security Event/Hostile Force Intrusion, and DSSP 0100-CR, Hot Shutdown Procedure

- Control Room Evacuation where there was a potential conflict. For example, in DOA 0010-18 if certain circumstances arose the Shift Manager was directed to implement DSSP 0100-CR, Hot Shutdown Procedure - Control Room Evacuation.

From that point DOA 0018 continued on and required similar actions as DSSP 0100-CR.

However, the two procedures required the similar procedures be carried out by different operators. In one case it was the Unit 2 equipment operator and in another case it was the Unit 3 equipment operator. The inspectors concluded that, in the circumstances where operations were being directed from outside the control room, these actions could be performed but the personnel conflicts could result in some actions not being carried out in a timely manner.

On June 29, 2012, the licensee wrote IR 1383557, NRC Questioned the DOA 0010-18 and DSSP 0100-CR Flow Path. The licensee did not identify the issue until pointed out by the inspectors. The licensee planned to make some procedure changes but had neither made procedure changes nor marked up a procedure to review by the end of the inspection period. The due date for the procedure markups was moved twice.

This review constituted one in depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Report 05000237/2011-005-00, Standby Liquid Control

Explosive Valve Failure In August 2009 the licensee upgraded the Unit 2 standby liquid control (SBLC) explosive valve heat tracing under Engineering Change (EC) 373699, Upgrade U2 Standby Liquid Heat Tracing, Revision 0. The licensee replaced the existing heat tracing and insulation on the SBLC suction, discharge, and relief lines, and the injection pumps. The heat tracing was designed to maintain the sodium pentaborate at a temperature of 95.5°F (to provide margin above the TS minimum temperature of 83°F) when the reactor building is at a temperature of 65°F. The heat tracing installation was intended to stop at the spool piece before the squib valve. However, during the modification, the installers wrapped the Unit 2 squib valve 2A with heat tracing. The inspectors determined that the licensee did not perform an appropriate inspection upon completion of the modification that should have identified the inappropriate heat tracing installation. As a result, the trigger and primer of the squib valve were subjected to elevated temperatures.

During an injection test performed on October 28, 2011, the 2A SBLC squib valve in Unit 2 failed to function properly which resulted in no flow of demineralized water from the test tank to the reactor. The licensee entered the issue into their corrective action program as IR 01282544, No Flow to Reactor During DOS 1100-03, SBLC Injection Test, dated October 28, 2011, and subsequently performed equipment apparent cause evaluation (EACE) 1282544-05 to determine the cause of the failure. The licensee determined that the apparent cause of the failure of the squib valve to fire properly was thermal degradation of the primers explosive material. This conclusion was based on a root cause investigation performed by the squib valve vendor. The licensee documented that the primer experienced temperatures above 120°F, the upper storage and installed temperature limit of the primer. The licensee determined that excessive heating resulting from the heat tracing around the 2A squib valve contributed to the thermal degradation. At the time of the Licensee Event Report (LER) submittal the root cause of the problem was unknown. The licensee planned to submit a supplemental LER at a later date.

A Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criteria X, Inspection, was documented in Inspection Report (IR) 05000237/2012008 for the failure to execute an appropriate inspection for work performed on the Units 2 and 3 SBLC pumps and associated equipment. Specifically, the licensee failed to determine via inspection that the heat tracing was properly installed on the Unit 2 2A SBLC components and that insulation material removed around the Unit 3 SBLC pumps was properly reinstalled post maintenance (NCV 05000237/2012008-02).

The licensee had neither determined the root cause nor the corrective actions by the time the LER was due and planned to make a supplemental report to discuss the root cause and corrective actions associated with this event. The inspectors reviewed the corrective actions associated with this event as documented in the licensees IR 1282544 and EACE 1282544-05 and had no concerns. No additional findings or violations of NRC requirements were identified. This LER is closed.

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

.2 (Closed) Licensee Event Report 05000237/2012-001-00, Entire Division of Average

Power Range Monitor Neutron Flux-High Channels Inoperable as a Result of Power Maneuver On February 19, 2012, the licensee entered TS 3.3.1.1 because the flow biased neutron flux-high and the fixed neutron flux-high functions for average power range monitor (APRMs) channels 4, 5, and 6 were inoperable simultaneously. The APRMs 4, 5, and 6 impacted all of Trip System B of the reactor protection system. With APRMs 4, 5, and 6, all inoperable at the same time the reactor would not scram on flow biased neutron flux-high or fixed neutron flux-high within the TS limits. The inspectors reviewed the licensees LER and Apparent Cause Evaluation IR 1328879-03), reviewed Operations procedure OP-AA-112-101, Shift Turnover and Relief, Revision 8, and interviewed licensee operations personnel. An NCV of 10 CFR 50.72(b)(3)(v)(D) was documented in IR 05000237/2012002 for the failure to make a required 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> notification to the Nuclear Regulatory Commission (NCV 05000237/2012002-08). The licensee had not determined corrective action by the time the LER was due and planned to make a supplemental report to discuss the corrective actions associated with this event. The inspectors reviewed the corrective actions associated with this event as documented in the licensees IR 1328879 and apparent cause evaluation and had no concerns. No additional findings or violations of NRC requirements were identified. Documents reviewed in this inspection are listed in the Attachment to this report. This LER is closed.

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

.3 (Closed) Licensee Event Report 05000237, 05000249/2012-002 00: Inlet Steam Drain

Pot Line Leaks Result in High Pressure Coolant Injection Inoperabilities The inspectors reviewed the subject LER to evaluate the licensees response to steam leaks in the Unit 2 high pressure coolant injection (HPCI) system that occurred on May 22, 2012, and the Unit 3 HPCI system on June 10, 2012. On May 22, 2012, plant operators identified a through wall leak in an elbow located on the HPCI inlet drain pot inboard drain line to the main condenser. The Unit 2 HPCI system was isolated and declared inoperable and the appropriate TS action statements were entered and performed. The licensee subsequently determined that the failure mechanism was erosion of the chrome-molybdenum material elbow caused by liquid impingement. On June 10, 2012, while performing additional walkdowns of the HPCI system as a corrective action for the May 22, 2012 event, plant operators discovered that a similar through wall leak on a chrome-molybdenum elbow on the Unit 3 HPCI inlet drain pot inboard drain line to the main condenser had developed. The Unit 3 HPCI system was isolated and declared inoperable and the appropriate TS action statements were entered and performed.

The licensee replaced both chrome-molybdenum elbows with stainless steel elbows as stainless steel is less susceptible to liquid impingement corrosion. In addition the licensee has scheduled work orders to replace both units inlet drain pot inboard drain lines and associated components with stainless steel materials in November 2012 (Unit 3) and March 2013 (Unit 2).

The inspectors review of the LER did not identify any violations of NRC regulations.

Documents reviewed in this inspection are listed in the Attachment to this report. This LER is closed.

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

.4 (Closed) Licensee Event Report 05000249/2012-001-00, Unexpected Isolation of the

Isolation Condenser Due to Test Switch Failure On July 10, 2012, the licensee entered TS 3.5.3 because the Unit 3 isolation condenser Group V containment isolation logic inadvertently actuated during surveillance testing of the isolation condenser high steam flow logic circuit. With a Group V containment isolation actuation in place, the Unit 3 Isolation Condenser became inoperable and incapable of performing its design function of providing cooling to the reactor core when the reactor became isolated from the main condenser. The inspectors reviewed the licensees LER, Apparent Cause Evaluation (IR 1386898-03), Quality Assurance Manual, and corrective actions associated with the event. The inadvertent actuation of the containment isolation logic occurred when the test switch installed in the high steam flow logic circuit failed to provide a continuous path for current flow preventing relay 3-0595-115A from remaining energized. With the relay deenergized, the isolation logic actuated cutting off the isolation condenser from the reactor coolant system. The licensee determined that the switch failed to provide an adequate path for current flow due to grease on the switchs stationary contact. The switch was tested satisfactorily at rated voltage and current conditions with a test circuit prior to installation in the actual flow logic circuit. The inspectors reviewed the corrective actions associated with this event as documented in the licensees IR 1386898 and the apparent cause evaluation and did not identify a licensee performance deficiency nor a finding or violation of NRC requirements. This LER is closed.

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

.5 (Closed) Licensee Event Report 05000249/2010-002-01, Main Steam Isolation Valve

Leakage Exceeds Technical Specifications Allowable Limits On November 1, 2010, Dresden Unit 3 had been shut down for a refueling outage.

After entering Mode 4, plant personnel performed the local leak rate test (LLRT) for the main steam isolation valves (MSIVs). The licensee identified that the leakage rate on three MSIVs exceeded the allowable limits specified in TS Surveillance Requirement 3.6.1.3.10. The 3-0203-1C, 3-0203-1D and 3-0203-2D valves were found to have 52.8, 34.6, and 36.9 scfh leakages, respectively. Based on the as-found leakage rates, Surveillance Requirement 3.6.1.3.10 was not met. The licensee documented this condition in IRs 1133829, 1133832 and 1133833, respectively. The inspectors reviewed EACE 1133833-03. The EACE stated the apparent cause was a non-optimal valve design allows the plug to become misaligned with the seat ring. The valve has a Y-pattern design that inherently forces the plug off center from the seat ring due to gravity. This problem was exclusive to Dresden and Quad Cities; other BWRs utilize other vendor designs. This issue was identified by the licensee as a chronic problem in 2004. There have been multiple failures of MSIVs to pass LLRTs for many years at both Dresden and Quad Cities. However, only one of three valves has failed a previous LLRT in the last 14 years. The EACE identified that although this issue was tracked as Chronic Problem 171393-28 the issue had no definitive owner/manager sponsor responsible for pushing it to completion. As further actions were developed, the actions required substantial resources that were not available. A fix has not yet been established for this chronic problem. A manager was assigned as a sponsor for this program in August 2012 in response to the comments in the EACE. The licensee has stated that this issue is not a significant condition adverse to quality.

Licensee Event Report 05000249/2010-002-00, MSIV Leakage Exceeds TSs Allowable Limits, was closed; and a licensee identified violation for exceeding TS limits was also identified in IR 05000249/2011-03. This LER is closed.

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

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000237/2010004-02; 05000249/2010004-02: Failure to

Seal Holes in the Floor Above the Emergency Core Cooling System Corner Rooms The inspectors identified that there were small holes in the Unit 2 reactor building 517 elevation floor. These holes bypassed the berms that surround the stairways to the Unit 2 emergency core cooling system (ECCS) corner rooms. The inspectors reviewed DR PSA-012, Internal Flood Evaluation Summary and Notebook, dated May 2009.

This document supported the licensees probabilistic risk assessment, but was not part of the licensing basis. This document stated that the berms around the ECCS corner room stairs were credited in the internal flooding analysis. Holes in the reactor building floor would be of concern during an event that included a crack or rupture of the service water line that was in the overhead of the 545 elevation of the reactor building. The inspectors reviewed licensing basis documentation and identified only one reference to flooding caused by service water in the reactor building. A draft safety evaluation from Systematic Evaluation Program Topic III-5.B, Pipe Break Outside Containment, dated January 17, 1980, stated that the protection from a medium energy line break caused by a Reactor Building 545 elevation service water failure was adequate. No further details were provided. The licensee documented the inspectors concern in IR 1108059, NRC Identified Concern. Through calculations performed the licensee concluded that in a worse case service water system break both ECCS corner rooms would flood to a point which would make ECCS equipment inoperable in 35 minutes versus 44 minutes if there were no holes in the floor. The licensee determined that this was sufficient time to isolate the flooding by securing all service water pumps. The licensee sealed the holes in December 2011.

The inspectors determined that there was no violation of regulatory requirements. This item is closed.

.2 (Closed) Unresolved Item 05000237/2011002-03; 05000249/2011002-03: Adequacy of

Control Room Ventilation Smoke Purge Function The inspectors previously identified an Unresolved Item regarding the adequacy of the control room ventilation smoke purge function. The inspectors identified that the inlet and outlet to the control room ventilation A train were around a corner and within 5 feet of one another on the exterior of the turbine building. The inspectors were concerned that some environmental conditions could result in exhausted smoke being drawn back into the intake of the smoke purge system resulting in the failure to purge the smoke from the control room.

Fire Protection Report Section 2.3.1.5, stated, The fresh air supply intakes to areas containing safety-related equipment are located away from the exhaust air outlets and smoke vents of other areas. The UFSAR Section 6.4.4.3 described the smoke purge function. The control room HVAC system was designed to isolate and maintain the design conditions within the control room during fires in either the control room or outside the emergency zone.

The UFSAR stated, smoke detectors, located in the control room return air ducts, will annunciate in the control room and the train A HVAC system will be switched manually to the smoke purge mode. During this mode, the system supplies 100 percent outdoor air. This will prevent the recirculation of smoke into any of the occupied areas in the event of fire while exhausting 100 percent of the return air to the outdoors. The smoke purge capability is only available on train A. The inspectors were concerned that the relative positions of the smoke purge inlet and outlet would make the statement that the recirculation of smoke into occupied areas (control room) would be prevented was inaccurate.

The inspectors reviewed applicable American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) and National Fire Protection Association (NFPA)standards for ventilation systems. Dresden Station was designed and constructed prior to the earliest ventilation standard that the inspectors identified. The earliest addition of NFPA 92A, Smoke Control Systems, 1988, stated that the inlet of the ventilation system should be as far away from the outlet as possible. The licensee was not committed to this standard.

The inspectors reviewed the licensees response to Generic Letter 2003-01, Control Room Habitability. The licensee committed to implementing an administrative TS for assessing and testing the Control Room Envelope (CRE).

Technical Specification 5.5.14, Control Room Envelope Habitability Program, required that a CRE habitability program shall be established and implemented to ensure that CRE habitability is maintained such that, with an operable control room emergency ventilation system, CRE occupants can control the reactor safety under normal conditions and maintain it in a safe condition following a radiological event, hazardous chemical release, or a smoke challenge. The Control Room Envelope Habitability Program was implemented by ER-AA-390-1001, Control Room Envelope Habitability Program Implementation, Revision 6. Procedure ER-AA-390-1001 required a periodic assessment to ensure that the plant maintains the CRE Habitability license and design basis.

The inspectors reviewed the last licensee CRE Habitability assessment which was completed on March 30, 2012. The assessment determined that adequate controls were in place to ensure the operators maintain the ability to safely shut down the plant during a smoke event originating inside or outside the control room. The assessment stated that for a smoke event that initiated in the control room operators would enter DOA 5750-04, Smoke, Noxious Fumes, or Airborne Contaminants in the Control Room, Revision 26. The first step of DOA 5740-04 required that operators don self contained breathing apparatus (SCBA) and control room breathing air be initiated before smoke purge was initiated.

The inspectors concluded that Fire Protection Report Section 2.1.3.5 and UFSAR Section 6.4.4.3 were inaccurate because the fresh air supply intakes to areas containing safety-related equipment were not located away from the exhaust air outlets and smoke vents of other areas, and the location of the air supply inlet and outlet would not prevent the recirculation of smoke into any of the occupied areas in the event of fire. However, there were no standards at the time of construction to prevent the current design and location of the smoke purge inlet and outlet. In addition, the inspectors concluded that the requirement to don SCBAs and initiate control room breathing air at the onset of a smoke event in the control room ensured the operators maintained the ability to safely shut down the plant during a smoke event originating inside the control room even if outside environmental conditions resulted in exhausted smoke being blown back into the smoke purge inlet.

The inspectors concluded that no violation of regulatory requirements occurred. This item is closed.

.3 (Closed) Unresolved Item 05000237/2011005-03: Unplanned Unit 2 Secondary

Containment Technical Specification Entry The inspectors identified an unresolved item regarding the causal factors related to the regulatory requirements associated with the circumstances surrounding the Unit 2 loss of secondary containment event on December 21, 2011. At the end of the inspection period for IR 05000237/2011005, the licensee was still working on a root cause to identify all causal factors related to this issue. The inspectors reviewed the root cause report (IR 1305358-05), interviewed licensee personnel, and discussed the results of the root cause report with licensee management.

On December 21, 2011, WO 1450006-01, DRESDEN UNIT 2 SA PM 517 RB/TB INTLK DOOR (2-5850-52) ELECTRICAL CHECKS, was being performed to ensure the reactor building interlock doors were functioning properly. During the performance of this work, connection point A19 was lifted to measure the in-line current of the door magnet for reactor building interlock door 52 (EPN 2-5850-52). By lifting connection A19, turbine building interlock door 16 (EPN 2-5850-16) lost power to its locking magnets. This loss of power caused both doors of the Unit 2 interlock to be open (door 52 was being held open and did not lose power due to this). This caused alarm 902-4 E-19, RX/TURB 517 INTLK DOORS INOP/BYP to occur. This condition existed for 9 seconds. This caused entry into TS 3.6.4.1, Condition A, Secondary Containment Inoperable in Mode 1, 2, or 3, and resulted in a subsequent event notification report, event number 47540.

The inspectors determined that there was a violation of NRC requirements and that appropriate corrective actions were applied. The violation was documented in IR 05000237/2012-002. This item is closed.

.4 Operation of an Independent Spent Fuel Storage Facility Installation at Operating Plants

(60855.1)

a. Inspection Scope

The inspectors observed and evaluated select licensee loading, processing, and transfer operations of the first and third canister during the licensees 2012 dry fuel storage campaign to verify compliance with the applicable certificate of compliance (CoC)conditions, the associated TS, and Independent Spent Fuel Storage Installation (ISFSI)procedures. Specifically, the inspectors observed: loading and independent verification of the fuel assemblies into the multi-purpose canister (MPC); decontamination and surveying; welding and non destructive testing of the MPC lid; draining of water; and vacuum drying. The licensee used the Holtec International HI-STORM 100 Cask System for this campaign.

The inspectors reviewed procedures used to perform ISFSI preparation, loading, sealing, transfer, monitoring, and storage activities. The inspectors reviewed applicable heavy loads procedures and inspection documentation to determine compliance with the sites heavy loads program. The inspectors reviewed select documents, in part, after the licensee completed certain loading activities.

The inspectors reviewed the licensees evaluations associated with fuel characterization and selection for storage. The inspectors reviewed the licensees evaluation to characterize fuel as intact fuel, damaged fuel, or fuel debris. The licensee did not plan to load any damaged fuel assemblies or fuel debris during this campaign. The inspectors reviewed the campaign cask fuel selection packages to verify that the licensee was loading fuel in accordance with the CoC approved contents.

The inspectors reviewed a number of condition reports and the associated corrective actions since the last ISFSI inspection. The inspectors also reviewed 72.48 screenings and changes to the licensees 10 CFR 72.212 evaluations since the last ISFSI inspection.

The licensee maintains two ISFSI pads at the Dresden Nuclear Power Station. The East ISFSI pad stores HI-STAR 100 and HI-STORM 100 storage casks The West ISFSI pad stores HI-STORM 100 storage casks. The inspectors performed tours of both ISFSI pads to assess the material condition of the pads and the loaded HI-STAR 100 and HI-STORM 100 storage casks. The inspectors reviewed the licensees evaluations of flammable materials near the ISFSI and their radiation monitoring program. Additionally, the inspectors performed independent radiation surveys around the ISFSI pad and storage casks.

b. Findings

No findings of significance were identified.

.5 (Discussed) NRC Temporary Instruction 2515/187, Inspection of Near-Term Task

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

a. Inspection Scope

Inspectors accompanied the licensee on a sampling basis, during their flooding and seismic walkdowns, to verify that the licensees walkdown activities were conducted using the methodology endorsed by the NRC. These walkdowns are being performed at all sites in response to a letter from the NRC to licensees, titled 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). The inspectors also observed a simulation of a portion of the licensees flood response procedure DOA 0010-04, Floods, Revision 32 and performed independent walkdowns of structures, systems, and components that would most impact the safe shutdown of the Units 2 and 3 reactors during a flooding or seismic event.

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.

4 of the letter requested licensees to perform external flooding walkdowns using an NRC-endorsed walkdown methodology (ADAMS Accession No.

ML12056A050). Nuclear Energy Industry Document 12-07 titled, Guidelines for Performing Verification Walkdowns of Plant Protection Features, (ADAMS Accession No. ML12173A215) provided the NRC-endorsed methodology for assessing external flood protection and mitigation capabilities to verify that plant features, credited in the CLB for protection and mitigation from external flood events, are available, functional, and properly maintained.

b. Findings

The inspectors determined that additional information is needed regarding the external flooding scenario in order to fully assess the viability of the external flooding procedure.

Findings or violations associated with the flooding and seismic walkdowns, if any, will be documented in a future integrated IR.

4OA6 Management Meetings

.1 Exit Meeting Summary

On October 17, 2012, the inspectors presented the inspection results to Mr. D. Czufin, 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.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The areas of radiation monitoring instrumentation; and RETS/ODCM radiological effluent occurrences PI verification with D. Czufin, Site Vice President, on July 27, 2012.

• The ISFSI operational inspection on August 2, 2012. The inspectors presented the inspection results to members of the licensee management and staff.

The inspectors confirmed that none of the potential report input discussed was considered proprietary

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green or SLIV) was identified by the licensee and is a violation of NRC requirements, which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy, NUREG 1600, for being dispositioned as an NCV.

10 CFR Part 50 Appendix B, Criterion III, Design Control, states, in part, that the design control measures must provide for verifying or checking the adequacy of design by methods such as design reviews, alternate or simplified calculational methods, or by a suitable testing program. Contrary to the above the licensee failed to verify adequacy of the design for HI-STORM 100 cask system laydown areas in the reactor building. The licensee identified that during various stages of fuel transfer operations inside the plant, analysis shows that the casks would uplift during a seismic event resulting in additional impact loads on the structural floors as well as the low profile transporter. The licensee, however, did not evaluate the affected structures for the additional impact loads. The licensee entered this issue into the CAP as IR 01251532, IR 01266469, and IR 01268258 and completed revised analyses and plant modifications where necessary.

The finding was determined to have very low safety significance.

10 CFR 72.146 Design Control, states, in part, that the design control measures must provide for verifying or checking the adequacy of design by methods such as design reviews, alternate or simplified calculational methods, or by a suitable testing program.

Contrary to the above the licensee failed to verify adequacy of the design of the HI-STORM 100 lift yoke. The licensee identified that they failed to adequately determine the bending stresses in lifting pins and shear stresses in the pin supporting plate and the definition of a dual load path component was incorrectly applied to the strong back components of the lift yoke. The finding was determined to have very low safety significance because the revised calculations decreased the rating of the lift yoke from 125 tons to 110 tons, and the maximum lifted load is less than 110 tons. The licensee entered this issue into the CAP as IR 1327578 and IR 1293137 and implemented the corrective actions to revise the calculations and de-rate the lift yoke.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

D. Czufin, Site Vice President

S. Marik, Station Plant Manager

D. Anthony, NDES Manager

T. Barren, Sr. Program Manager - Dry Cask Storage

J. Biegelson, Engineering

H. Bush, Radiation Protection Manager

J. Cady, Radiation Protection Manager

P. Chambers, Dresden Licensed Operator Requalification Training Lead

P. DiSalvo, GL 89-13 Program Owner

H. Do, Corporate ISI Manager

D. Doggett, Emergency Preparedness Coordinator

H. Dodd, Regulatory Assurance Manager

J. Fox, Design Engineer

J. Freeman, Corporate Engineering

G. Gates, Operations

D. Glick, Radioactive Material Shipping Specialist

G. Graff, Nuclear Oversight Manager

M. Hosain, Site EQ Engineer

R. Johnson, Chemist RETS/ODCM

L. Jordan, Training Director

B. Kapellas, Operations Director

D. Ketchledge, Engineering

J. Knight, Director, Site Engineering

M. Knott, Instrument Maintenance Manager

J. Kish, Site ISI

S. Kvasnicka, NDE Level III

D. Leggett, Chemistry Manager

G. Lupia, Corporate Buried Pipe Engineer

T. Mohr, Supervisor, Engineering Programs

P. Mankoo, Radiation Protection

G. Morrow, Operations

M. McDonald, Maintenance Director

T. Mohr, Engineering Program Manager

P. OBrien, Regulatory Assurance - NRC Coordinator

D. OFlanagan, Security Manager

M. Otten, Operations Training Manager

M. Pavey, Health Physicist

P. Quealy, Emergency Preparedness Manager

B. Rakes, Project Manager - Dry Cask Storage

R. Ruffin, Licensing Engineer

D. Schiavoni, Engineering

J. Sipek, Work Control Director

R. Stachniak, Engineering

R. Sisk, Buried Pipe Program Owner

Attachment

L. Torres, Engineering

J. Wegner, Engineer - Dry Cask Storage

Nuclear Regulatory Commission

S. West, Director, Division of Reactor Projects

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

IEMA

R. Zuffa, Illinois Emergency Management Agency

Attachment

LIST OF ITEMS

Opened

None.

Closed

05000237/2011-005-00 LER Standby Liquid Control Explosive Valve Failure (4OA3)

05000237/2012-001-00 LER Entire Division of APRM Neutron Flux-High Channels Inoperable as a Result of Power Maneuver (4OA3)

05000237/2012-002-00 LER Inlet Steam Drain Pot Line Leaks Result in HPCI

05000249/2012-002 00 Inoperabilities (4OA3)

05000249/2012-001-00 LER Unexpected Isolation of the Isolation Condenser Due to Test Switch Failure (4OA3)

05000249/2010-002-01 LER MSIV Leakage Exceeds Technical Specifications Allowable Limits (4OA3)

05000237/2010004-02 URI Failure to Seal Holes in the Floor Above the Emergency

05000249/2010004-02 Core Cooling System (ECCS) Corner Rooms (4OA5)

05000237/2011002-03 URI Adequacy of Control Room Ventilation Smoke Purge

05000249/2011002-03 Function (4OA5)

05000237/2011005-03 URI Unplanned Unit 2 Secondary Containment Technical Specification Entry (4OA5)

Discussed

NRC Temporary TI NRC TI 2515/187, Inspection of Near-Term Task Force Instructions 2515/187 Recommendation 2.3 Flooding Walkdowns, and NRC TI and 2515/188 2515/188, Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns (4OA5)

Attachment