IR 05000237/2011005

IR 05000237-11-005, 05000249-11-005, on 10/01/2011 - 12/31/2011, Dresden Nuclear Power Station, Units 2 & 3, Followup of Events and Notices of Enforcement Discretion

ML120250224
Person / Time
Site:	Dresden
Issue date:	01/25/2012
From:	Jamnes Cameron NRC/RGN-III/DRP/B6
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-11-005
Download: ML120250224 (57)

Text

uary 25, 2012

SUBJECT:

DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3 -NRC INTEGRATED INSPECTION REPORT 05000237/2011005 and 05000249/2011005

Dear Mr. Pacilio:

On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Dresden Nuclear Power Station, Units 2 and 3. The enclosed inspection report documents the inspection results which were discussed on January 19, 2012, with Mr. D. Czufin, and other members of your staff.

The inspections 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.

Two self-revealed findings of very low safety significance (Green) were identified during this inspection. These findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these non-cited violations, 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 copies to the Regional Administrator, 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. If you disagree with a cross-cutting aspect assignment 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. 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. 05000-237; 05000-249 License Nos. DPR-19; DPR-25

Enclosure:

Inspection Report 05000237/2011-005 and 05000249/2011-005 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000237; 05000249 License Nos: DPR-19; DPR-25 Report No: 05000237/2011-005; 05000249/2011-005 Licensee: Exelon Generation Company, LLC Facility: Dresden Nuclear Power Station, Units 2 and 3 Location: Morris, IL Dates: October 1 through December 31, 2011 Inspectors: C. Phillips, Senior Resident Inspector D. Meléndez-Colón, Resident Inspector M. Bielby, Senior Operations Engineer T. Briley, Reactor Engineer J. Corujo-Sandín, Reactor Engineer T. Go, Health Physicist R. Jickling, Senior Emergency Preparedness Inspector B. Kemker, Senior Resident Inspector, Clinton Site R. Langstaff, Senior Reactor Inspector D. Lords, Resident Inspector, Clinton Site F. Ramirez, Resident Inspector, LaSalle Site A. Shaikh, Reactor Inspector P. Smagacz, Reactor Engineer Approved by: J. Cameron, Chief Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000237/2011-005, 05000249/2011-005; 10/01/2011 - 12/31/2011;

Dresden Nuclear Power Station, Units 2 & 3, Followup of Events and Notices of Enforcement Discretion.

This report covers a 3-month period of inspection by resident inspectors. Two Green findings were self-revealed. Both of the findings were considered non-cited violations (NCVs) of NRC regulations. The significance of most findings is indicated by their color (Green, White,

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

Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

A self-revealed finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified on October 24, 2011, when two electrical maintenance technicians performing a clearance boundary safety verification opened a Bus 23 potential transformer (POT)fuse drawer causing an undervoltage load shed signal that resulted in the inoperability of the control room emergency ventilation (CREV) air conditioning system. Corrective actions taken included an electrical maintenance department clock reset and stand down to discuss the event and consequences of taking actions in the plant without proper guidance. Further licensee planned corrective actions include presenting to Operations and the Configuration Control Committee the possibility of installing robust barriers or locking devices on bus POT installations.

The inspectors determined that the finding was more than minor because it was associated with the Initiating Events Cornerstone attribute of Human Performance and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, not following clearance order 89693 instructions and operating plant equipment by opening the upper Bus 23 bus POT fuse drawer without a procedure led to the inoperability of the control room emergency ventilation air conditioning system.

The inspectors evaluated the finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Phase 1 - Operations Checklists for Both PWRs and BWRs, using the Checklist 7, BWR Refueling Operation with Reactor Coolant System Level > 23. The inspectors answered no to each of the checklist items requiring a phase 2 or phase 3 analysis and therefore the finding screened as having very low safety significance (Green). The inspectors concluded that the finding had a cross-cutting aspect in Human Performance-Work Practices. The licensee staff involved in the event failed to utilize human performance error prevention techniques commensurate with the risk of the assigned task to prevent impact to the station (H.4(a)). (Section 4OA3.1)

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated NCV of Technical Specification 5.4.1 was self-revealed when a control rod blade (CRB) disengaged from the lifting tool and gravity fell into an empty cell in the reactor core. The immediate actions taken by licensee personnel were to return equipment to a safe configuration and stop work.

The finding was determined to be more than minor because if left uncorrected it had the potential to lead to a more significant safety concern. Specifically, had the performance deficiency not been corrected and a similar event happened again the CRB could potentially tip over and fall over fuel assemblies rather than on an empty cell. The inspectors determined that the finding could be evaluated in accordance with IMC 0609,

Appendix G, Shutdown Operations Significance Determination Process. The inspectors determined this finding did not meet the definition of Loss of Control as stated in Table 1 of Appendix G. In addition, using Checklist 7, Boiling Water Reactor Refueling Operations with RCS Level >23, contained in Attachment 1, the inspectors determined that the finding did not require a Phase 2 or Phase 3 analysis based on the criteria established on the checklist. Specifically, 1) the finding did not increase the likelihood of a loss of RCS inventory or RCS level instrumentation 2) the finding did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed and 3) the finding did not degrade the licensees ability to recover decay heat removal once it is lost. The issue did not need a quantitative assessment and screened as

Green.

This finding had a cross-cutting aspect in the area of Human Performance,

Work Practices, because the licensee staff did not ensure supervisory and management oversight of work activities such that nuclear safety was supported. (H.4(c))

(Section 4OA3.2)

Licensee-Identified Violations

No violations were identified.

REPORT DETAILS

Summary of Plant Status

Unit 2 The unit operated at or near 100 percent power during the inspection period, with the exception of routine power reductions for planned control rod pattern adjustments, and the planned manual shutdown on October 17 for the D2R22 refueling outage. Following the refueling outage, operators returned the unit to full power operations on November 13.

Unit 3 The unit operated at or near 100 percent power during the inspection period, with the exception of a routine power reduction for planned control rod pattern adjustments and testing activities.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 2B core spray (CS) sub-system during 2A CS logic system functional testing; and

• U2 250V DC breaker restoration after U2 250V DC Battery discharge test.

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, Updated Final Safety Analysis Report (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 two partial system walkdown samples as defined in Inspection Procedure (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 1.1.2.3, Unit 2 reactor water clean-up and shutdown heat exchanger, elevation 545;

• Fire Zone 6.2, auxiliary electric equipment room after halon damper test, elevation 517;

• Fire Zone 8.2.5A, 8.2.5B, and 8.2.6B, Unit 2 low pressure heater bay, elevation 517; and

• Fire Zone 8.2.5A, Unit 2 high pressure heater bay, 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 four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the Unit 2A low pressure coolant injection 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.

1R08 Inservice Inspection Activities

From October 24 to 28, 2011, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the Unit 2 reactor coolant system, emergency feedwater systems, risk significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4, and 1R08.5 below count as one inspection sample as defined by IP 71111.08.

.1 Piping Systems Inservice Inspection Program

a. Inspection Scope

The inspectors observed the following nondestructive examinations (NDE) required by the American Society of Mechanical Engineers (ASME),Section XI, Code and/or 10 CFR 50.55a, to evaluate compliance with the ASME Code Section XI applicable ASME Code Case and Section V requirements and if any indications were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC approved alternative requirement.

• Ultrasonic (UT) examination of the emergency core cooling system (ECCS) Ring Header Pipe-to-Pipe Weld 2/2/1501-24/24-44;

• Ultrasonic examination of Main Steam Line Elbow-to-Pipe Weld 2/1/3001A-20/20-K6; and

• Visual (VT-1) examination of Reactor Pressure Vessel Head Nuts 2/1/RPV UPP HD/HD Nuts (92).

During non destructive surface and volumetric examinations performed since the previous refueling outage, the licensee had not identified any recordable indications.

Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors reviewed the following pressure boundary welds completed for risk significant Unit 2 systems to determine if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the construction Code, ASME Section XI Code and NRC approved Code Cases. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of the ASME Code Section IX.

• Weld Overlay fabrication on the Recirculation Lines Loop A and B.

b. Findings

No findings of significance were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI related problems entered into the licensees CAP 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 (71111.11Q and A)

.1 Resident Inspector Quarterly Review

a. Inspection Scope

The licensee did not perform a simulator evaluation during the fourth quarter of 2011.

The licensee did not perform simulator evaluations due to the scheduled Unit 2 refueling outage. On October 25, 2011, the inspectors performed a review of licensed operator remediation records. The inspectors reviewed the appropriateness, thoroughness, and completion of the recommended remediation for the deficiencies identified, prior to the operators return to duty. The remediation occurred during the calendar year 2011.

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

b. Findings

No findings were identified.

.2 Biennial Written and Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Biennial Written Examination, administered by the licensee from April 14 through July 22, 2011, and the Annual Operating Test, administered by the licensee from April 15 through July 21, 2011, required by 10 CFR 55.59(a). The results were compared to the thresholds established in Inspection Manual Chapter (IMC) 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP)," to assess the overall adequacy of the licensees Licensed Operator Requalification Training program to meet the requirements of 10 CFR 55.59.

This inspection constitutes one biennial licensed operator requalification inspection sample as defined in IP 71111.11A.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• Unit 3 low pressure coolant injection; and

• Unit 2 core spray.

The inspectors reviewed events such as where ineffective equipment maintenance could result in valid or invalid automatic actuations or transients 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

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 2 core spray during core spray logic system functional test;

• Unit 3 Yellow Risk during 4 KV (23-1 to 33-1) X-Tie for TR 22 planned maintenance; and

• De-energization of Unit 3 250v DC Buses 3A and 3B.

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

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

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functional Assessments

a. Inspection Scope

The inspectors reviewed the following issues:

• IR 1277894 and 1184914, Degraded Magnesium Rotor;

• IR 1281725, Cabling in Drywell Not Tied To Correct Temperature Element;

• IR 1277823, Not able to Perform DIS 263-08 in its Entirety;

• IR 1284312, Obstructed Nozzles Identified During DTS 1500-03;

• IR 1281291, Degraded Cable To ERV 2-0203-3E, and IR 1281286,Degraded Cable to ERV 2-0203-3B; and

• IR 1280219, U2 SBLC Tank Bottom Weld Condition.

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 six samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

• WO 1485861, Install Vibration Monitoring Equipment on Feedwater Check Valves 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 plant modification sample as defined in IP 71111.18 05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• WO 1089088, D2 RFL COM PM Clean/Insp/Hydro/Eddy Current A LPCI Hx;

• WO 1399271-03, PMT 2A Core Spray Pump Control Switch Replacement;

• WO 1081407, 2RFL TS Standby Liquid Squib Valve A Replace;

• WO 1089088, D2 RFL TS 1000 psi Reactor Vessel System Leakage Test/Hydro; and

• WO 99117764, D2 12.7Y EQ RWCU Auto-Isolation Panel Trip Unit Replacement.

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 five 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 October 17 through November 13, 2011, 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 cooldown processes and monitored licensee controls over the outage activities listed below. Documents reviewed during the inspection are listed in the to this report.

• 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 sipping to detect fuel assembly leakage.

• 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.

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

This inspection constituted one RFO 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 01453080-01, OP D2 Qtr LPCI System Pump In-service Testing (IST);

• WO 1290616, D2 30M/RFL TS LLRT VLV 2-2001-5 (ISO Valve);

• WO 1290612, D2 30M/RFL TS LLRT VLV 2-2001-6 (ISO Valve);

• WO 1237654-01, D2 24M TS Core Spray System LSFT (routine);

• WO 1082684, D2 48M/RFL TS System I SLC Manual Init to Inj Demin Wtr (routine);

• WO 1295487, D2 RFL TS Bus 24-1 UV and ECCS Integrated Functional Test (routine); and

• WO 393799, D2 10Y RFL TS LPCI Containment Spray Test of DW spray nozzle (routine).

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

• did preconditioning occur;

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

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

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

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the 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, ASMEs 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, two containment isolation valve samples and one inservice testing 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

Since the last NRC inspection of this program area, emergency action level and Emergency Plan Revision 28 was implemented based on your determination, in accordance with 10 CFR 50.54(q), that the changes resulted in no decrease in effectiveness of the Plan, and that the revised Plan as changed continues to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The inspectors conducted a sampling review of the Emergency Plan changes and a review of the Emergency Action Level changes to evaluate for potential decreases in effectiveness of the Plan. However, these reviews do not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety.

This emergency action level and emergency plan changes inspection constituted one sample as defined in IP 71114.04-05.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

The inspection activities supplement those documented in Inspection Report 05000237/2011003; 05000249/2011003 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 selected the following radiologically risk-significant work activities that involved exposure to radiation.

• drywell main-steam activities;

• drywell control rod drive and exchange support activities;

• reactor cavity decontamination activities;

• reactor disassembly and reassembly related activities;

• drywell in-service inspection, and

• drywell scaffold assembly and demobilization activities In review of 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;

• presence of alpha emitters;

• 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.);

• 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 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 CAP and dose evaluations were conducted as appropriate.

In review of these work activities that could suddenly and severely increase radiological conditions, the inspectors assessed the licensees means to inform workers of changes that could significantly impact their occupational dose.

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 reviewed the licensees criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was guidance on how to respond to an alarm that indicates the presence of licensed radioactive material.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls. The inspectors evaluated the licensees use of electronic personal dosimeters in high noise areas as high radiation area monitoring devices.

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.

• drywell main-steam activities;

• drywell control rod drive and exchange support activities;

• reactor cavity decontamination activities;

• reactor disassembly and reassembly related activities;

• drywell in-service inspection; and

• drywell scaffold assembly and demobilization activities.

For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring, including potentials for significant airborne levels (e.g., grinding, grit blasting, system breaches, entry into tanks, cubicles, and reactor cavities). The inspectors assessed the effectiveness of 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 observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors assessed whether workers were aware of the radiological conditions in their workplace and the radiation work permit controls/limits in place, and whether their performance reflected the level of radiological hazards present.

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 CAP. 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-Is-Reasonably-Achievable Planning and Controls

The inspection activities supplement those documented in Inspection Report 05000237/2010005; 05000249/2010005, and constitute one complete sample as defined in IP 71124.02-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed pertinent information regarding plant collective exposure history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants three year rolling average collective exposure.

The inspectors reviewed the site-specific trends in collective exposures (using NUREG-0713, Occupational Radiation Exposure at Commercial Nuclear Power Reactors and Other Facilities, and plant historical data) and source term (average contact dose rate with reactor coolant piping) measurements (using Electric Power Research Institute (EPRI) TR-108737, BWR Iron Control Monitoring Interim Report, issued December 1998, and/or plant historical data, when available).

The inspectors reviewed site-specific procedures associated with maintaining occupational exposures As-Low-As-Is-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 assessed whether the licensees planning identified appropriate dose mitigation features; considered alternate mitigation features; and defined reasonable dose goals. The inspectors evaluated whether the licensees ALARA assessment had taken into account decreased worker efficiency from use of respiratory protective devices and/or heat stress mitigation equipment (e.g., ice vests). The inspectors determined whether the licensees work planning considered the use of remote technologies (e.g., tele-dosimetry, remote visual monitoring, and robotics) as a means to reduce dose and the use of dose reduction insights from industry operating experience and plant-specific lessons learned. The inspectors assessed the integration of ALARA requirements into work procedure and radiation work permit documents.

The inspectors compared the results achieved (dose rate reductions, person-rem used)with the intended dose established in the licensees ALARA planning for these work activities. The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements, and evaluated the accuracy of these time estimates.

The inspectors assessed the reasons (e.g., failure to adequately plan the activity, failure to provide sufficient work controls) for any inconsistencies between intended and actual work activity doses.

The inspectors determined whether post-job reviews were conducted and if identified problems were entered into the licensees corrective action program.

b. Findings

No findings were identified.

.3 Source Term Reduction and Control (02.04)

a. Inspection Scope

The inspectors used licensee records to determine the historical trends and current status of significant tracked plant source terms known to contribute to elevated facility aggregate exposure. The inspectors assessed whether the licensee had made allowances or developed contingency plans for expected changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

This inspection constituted one complete sample as defined in IP 71124.06-05.

.1 Inspection Planning and Program Reviews (02.01)

Event Report and Effluent Report Reviews

a. Inspection Scope

The inspectors reviewed the radiological effluent release reports issued since the last inspection to determine if the reports were submitted as required by the Offsite Dose Calculation Manual/TSs. The inspectors reviewed anomalous results, unexpected trends, or abnormal releases identified by the licensee for further inspection to determine if they were evaluated, were entered in the CAP, and were adequately resolved.

The inspectors identified radioactive effluent monitor operability issues reported by the licensee as provided in effluent release reports, to review these issues during the onsite inspection, as warranted, given their relative significance and determine if the issues were entered into the CAP and adequately resolved.

b. Findings

No findings were identified.

Offsite Dose Calculation Manual and Final Safety Analysis Report Review

a. Inspection Scope

The inspectors reviewed Final Safety Analysis Report descriptions of the radioactive effluent monitoring systems, treatment systems, and effluent flow paths so they could be evaluated during inspection walkdowns.

The inspectors reviewed changes to the Offsite Dose Calculation Manual made by the licensee since the last inspection against the guidance in NUREG-1301, 1302 and 0133, and Regulatory Guides 1.109, 1.21 and 4.1. When differences were identified, the inspectors reviewed the technical basis or evaluations of the change during the onsite inspection to determine whether they were technically justified and maintained effluent releases ALARA.

The inspectors reviewed licensee documentation to determine if the licensee has identified any non-radioactive systems that have become contaminated as disclosed either through an event report or the Offsite Dose Calculation Manual since the last inspection. This review also provided a list of samples to be used during the onsite inspection to determine whether any 10 CFR 50.59 evaluations were performed by the licensee and to determine whether there were any newly contaminated systems or any unmonitored effluent discharge pathways to the environment. Inspectors also reviewed whether any required Offsite Dose Calculation Manual revisions were made to incorporate these new pathways and whether the associated effluents were reported in accordance with Regulatory Guide 1.21.

b. Findings

No findings were identified.

Groundwater Protection Initiative Program

a. Inspection Scope

The inspectors reviewed reported groundwater monitoring results and changes to the licensees written program for identifying and controlling contaminated spills/leaks to groundwater.

b. Findings

No findings were identified.

Procedures, Special Reports, and Other Documents

a. Inspection Scope

The inspectors reviewed Licensee Event Reports (LERs), event reports and/or special reports related to the effluent program issued since the previous inspection to identify any additional focus areas for the inspection based on the scope/breadth of problems described in these reports.

The inspectors reviewed effluent program implementing procedures, particularly those associated with effluent sampling, effluent monitor set-point determinations, and dose calculations.

The inspectors reviewed copies of licensee and third party (independent) evaluation reports of the effluent monitoring program since the last inspection to gather insights into the licensees program and aid in selecting areas for inspection review (smart sampling).

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down selected components of the gaseous and liquid discharge systems to evaluate whether equipment configuration and flow paths align with the documents reviewed in 02.01 above and to assess equipment material condition.

Special attention was made to identify potential unmonitored release points (such as open roof vents in boiling water reactor turbine decks, temporary structures butted against turbine, auxiliary or containment buildings), building alterations which could impact airborne, or liquid effluent controls, and ventilation system leakage that communicates directly with the environment.

For equipment or areas associated with the systems selected for review that were not readily accessible due to radiological conditions, the inspectors reviewed the licensee's material condition surveillance records, as applicable.

The inspectors walked down filtered ventilation systems to assess for conditions such as degraded high-efficiency particulate air /charcoal banks, improper alignment, or system installation issues that would impact the performance or the effluent monitoring capability of the effluent system.

As available, the inspectors observed selected portions of the routine processing and discharge of radioactive gaseous effluent (including sample collection and analysis) to evaluate whether appropriate treatment equipment was used and the processing activities align with discharge permits.

The inspectors determined if the licensee has made significant changes to their effluent release points, e.g., changes subject to a 10 CFR 50.59 review or require NRC approval of alternate discharge points.

As available, the inspectors observed selected portions of the routine processing and discharge liquid waste (including sample collection and analysis) to determine if appropriate effluent treatment equipment is being used and that radioactive liquid waste is being processed and discharged in accordance with procedure requirements and aligns with discharge permits.

b. Findings

No findings were identified.

.3 Sampling and Analyses (02.03)

a. Inspection Scope

The inspectors selected effluent sampling activities, consistent with smart sampling, and assessed whether adequate controls have been implemented to ensure representative samples were obtained (e.g., provisions for sample line flushing, vessel recirculation, composite samplers, etc.)

The inspectors selected effluent discharges made with inoperable (declared out-of-service) effluent radiation monitors to assess whether controls were in place to ensure compensatory sampling was performed consistent with the radiological effluent TSs/Offsite Dose Calculation Manual and that those controls were adequate to prevent the release of unmonitored liquid and gaseous effluents.

The inspectors determined whether the facility was routinely relying on the use of compensatory sampling in lieu of adequate system maintenance, based on the frequency of compensatory sampling since the last inspection.

The inspectors reviewed the results of the inter-laboratory comparison program to evaluate the quality of the radioactive effluent sample analyses and assessed whether the inter-laboratory comparison program includes hard-to-detect isotopes as appropriate.

b. Findings

No findings were identified.

.4 Instrumentation and Equipment (02.04)

Effluent Flow Measuring Instruments

a. Inspection Scope

The inspectors reviewed the methodology the licensee uses to determine the effluent stack and vent flow rates to determine if the flow rates were consistent with radiological effluent TSs/Offsite Dose Calculation Manual or Final Safety Analysis Report values, and that differences between assumed and actual stack and vent flow rates did not affect the results of the projected public doses.

b. Findings

No findings were identified.

Air Cleaning Systems

a. Inspection Scope

The inspectors assessed whether surveillance test results since the previous inspection for Technical Specification required ventilation effluent discharge systems (high-efficiency particulate air and charcoal filtration), such as the Standby Gas Treatment System and the Containment/Auxiliary Building Ventilation System, met TS acceptance criteria.

b. Findings

No findings were identified.

.5 Dose Calculations (02.05)

a. Inspection Scope

The inspectors reviewed all significant changes in reported dose values compared to the previous radiological effluent release report (e.g., a factor of 5, or increases that approach Appendix I criteria) to evaluate the factors which may have resulted in the change.

The inspectors reviewed radioactive liquid and gaseous waste discharge permits to assess whether the projected doses to members of the public were accurate and based on representative samples of the discharge path.

Inspectors evaluated the methods used to determine the isotopes that are included in the source term to ensure all applicable radionuclides are included within detectability standards. The review included the current Part 61 analyses to ensure hard-to-detect radionuclides are included in the source term.

The inspectors reviewed changes in the licensees offsite dose calculations since the last inspection to evaluate whether changes were consistent with the Offsite Dose Calculation Manual and Regulatory Guide 1.109. Inspectors reviewed meteorological dispersion and deposition factors used in the Offsite Dose Calculation Manual and effluent dose calculations to evaluate whether appropriate factors were being used for public dose calculations.

The inspectors reviewed the latest Land Use Census to assess whether changes (e.g.,

significant increases or decreases to population in the plant environs, changes in critical exposure pathways, the location of nearest member of the public or critical receptor, etc.) have been factored into the dose calculations.

For the releases reviewed above, the inspectors evaluated whether the calculated doses (monthly, quarterly, and annual dose) are within the 10 CFR Part 50, Appendix I, and TS dose criteria.

The inspectors reviewed, as available, records of any abnormal gaseous or liquid tank discharges (e.g., discharges resulting from misaligned valves, valve leak-by, etc.)

to ensure the abnormal discharge was monitored by the discharge point effluent monitor. Discharges made with inoperable effluent radiation monitors, or unmonitored leakages were reviewed to ensure that an evaluation was made of the discharge to satisfy 10 CFR 20.1501 so as to account for the source term and projected doses to the public.

b. Findings

No findings were identified.

.6 Groundwater Protection Initiative Implementation (02.06)

a. Inspection Scope

The inspectors reviewed monitoring results of the Groundwater Protection Initiative to determine if the licensee had implemented its program as intended and to identify any anomalous results. For anomalous results or missed samples, the inspectors assessed whether the licensee had identified and addressed deficiencies through its CAP.

The inspectors reviewed identified leakage or spill events and entries made into 10 CFR 50.75

(g) records. The inspectors reviewed evaluations of leaks or spills and reviewed any remediation actions taken for effectiveness. The inspectors reviewed onsite contamination events involving contamination of ground water and assessed whether the source of the leak or spill was identified and mitigated.

For unmonitored spills, leaks, or unexpected liquid or gaseous discharges, the inspectors assessed whether an evaluation was performed to determine the type and amount of radioactive material that was discharged by:

Assessing whether sufficient radiological surveys were performed to evaluate the extent of the contamination and the radiological source term and assessing whether a survey/evaluation had been performed to include consideration of hard-to-detect radionuclides.

Determining whether the licensee completed offsite notifications, as provided in its Groundwater Protection Initiative implementing procedures.

The inspectors reviewed the evaluation of discharges from onsite surface water bodies that contain or potentially contain radioactivity, and the potential for ground water leakage from these onsite surface water bodies. The inspectors assessed whether the licensee was properly accounting for discharges from these surface water bodies as part of their effluent release reports.

The inspectors assessed whether on-site ground water sample results and a description of any significant on-site leaks/spills into ground water for each calendar year were documented in the Annual Radiological Environmental Operating Report for the radiological environmental monitoring program or the Annual Radiological Effluent Release Report for the Radiological Effluent TSs.

For significant, new effluent discharge points (such as significant or continuing leakage to ground water that continues to impact the environment if not remediated), the inspectors evaluated whether the offsite dose calculation manual was updated to include the new release point.

b. Findings

No findings were identified.

.7 Problem Identification and Resolution (02.07)

a. Inspection Scope

Inspectors assessed whether problems associated with the effluent monitoring and control program were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensee corrective action program. In addition, the licensee evaluated the appropriateness of the corrective actions for a selected sample of problems documented involving the effluent monitoring and control program.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system (RCS)

Leakage performance indicator for Unit 2 and Unit 3 for the period from the third quarter 2010 through the second quarter 2011. 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 logs, RCS leakage tracking data, issue reports, event reports and NRC Integrated Inspection Reports for the period of September 2010 through September 2011 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 RCS leakage samples as defined in IP 71151 05.

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the occupational radiological occurrences performance indicator (PI) for the period from the first quarter 2010 through the third quarter of 2011. 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 assessment of the PI for occupational radiation safety to determine if indicator related data was adequately assessed and reported. In order to assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry dose rate and accumulated dose alarms and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of several locked high radiation area entrances to determine the adequacy of the controls in place for these areas.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one occupational exposure control effectiveness sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the radiological effluent TS/Offsite Dose Calculation Manual radiological effluent occurrences PI for the period from the first quarter 2010 through the third quarter 2011. 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 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 between the first quarter 2010 through the third quarter 2011 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 Attachment to this report.

This inspection constituted one Radiological Effluent TS/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 that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

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

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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

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

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6 month period of May 1, 2011, through November 1, 2011, although some examples expanded beyond those dates where the scope of the trend warranted.

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

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

b. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 Bus 23 POT Fuse Drawer Resulting in the Inoperability of the Control Room Emergency

Ventilation Air Conditioning System

Introduction:

A self-revealed finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified on October 24, 2011, when two electrical maintenance technicians performing a clearance boundary safety verification opened a Bus 23 potential transformer (POT) fuse drawer causing an undervoltage load shed signal that resulted in the inoperability of the control room emergency ventilation (CREV) air conditioning system. The inspectors determined that failure to follow clearance order instructions and operating plant equipment without a procedure was a performance deficiency.

Description:

On October 24, 2011, two electrical maintenance technicians were performing a safety verification clearance order walkdown to support a boundary swap of the main generator out-of- service (OOS) clearance order (CO 89693) on Unit 2. The technicians had verified that the Bus 23 and Bus 24 clearance boundary isolation cards were placed appropriately per the CO safety verification check list. When the technicians performed the safety verification of Bus 22 a non-licensed operator (NLO),observed the technicians verifying the clearance boundary isolation cards by looking at the cards placed on the outside of Transformer 21 to Bus 21 pot fuse drawer. The NLO suggested the technicians physically open the drawers and verify the fuses had actually been removed. Previous station practice had been to leave the fuses with the clearance boundary isolation cards attached in the bottom of the cubicle after they were removed.

This practice changed due to the requirements of critical parts storage. The practice at the time of the event was to store the fuses in the Operations Work Execution Center when removed. The bus POT fuse drawers were closed with the OOS cards attached externally.

The two electrical maintenance technicians decided to go back to Bus 23 to physically verify that the fuses had actually been removed. At that time the technicians changed places as to who performed the actual verification and who provided peer checking.

Bus 23 has two sets of bus POTs, both located in the same compartment. The first set contained in the lower Bus 23 transformer POT fuse drawer was part of the clearance order safety verification walkdown. The second set contained in the upper Bus 23 bus POT fuse drawer was not part of the clearance order but was part of the Bus 23 relay protection scheme at the time of the event. The electrical maintenance technician opened the lower Bus 23 transformer POT fuse drawer. Then the electrician proceeded, without first verifying the location of the clearance order tags and prior to a peer check, by opening the upper Bus 23 bus POT fuse drawer. Opening the upper Bus 23 bus POT fuse drawer caused an undervoltage (UV) load shed signal to be sent to all Bus 23 loads including Bus 25. Unit 2 RPS Bus B was supplied from MCC 25-2. On the Bus 23 load shed a RPS B 1/2 SCRAM was received along with a trip of Unit 2 and 3 reactor building ventilation and a standby gas treatment (SBGT) auto start. Due to the momentary loss of Bus 23, the Division 1 Containment Cooling Service Water (CCSW) pumps were unavailable resulting in a loss of the CREV system. This condition affected both Dresden Units 2 and 3. The upper Bus 23 bus POT fuse drawer was inserted 7 seconds later by the electrical maintenance technician and the undervoltage condition cleared.

Bus 25 automatically tied to Bus 26. Subsequently Bus 25 was restored to Bus 23 and RPS Bus B power was restored.

The pre-job brief was conducted for a non-intrusive, visual safety verification walkdown of Unit 2 CO 89693 with the expectation that the physical fuses that were removed as part of the clearance boundary were expected to be in the bottom of the cubicles out in the field. The two electrical maintenance technicians and their supervisor, who conducted the pre-job brief, were unaware of the change in critical parts storage practices. When the fuses were not identified out in the field, the technicians did not use a questioning attitude and notify their supervisor of the unexpected condition.

Additionally, the supervisor was not notified of the change from a non-intrusive, visual only walkdown to an intrusive safety verification walkdown by physically opening the bus POT fuse drawers recommended by the NLO. The CO instructions specifically stated STAR [stop, think, act, review] when opening the transformer POT fuse drawers, they are in the same bus compartment as the bus POT fuse drawers. Opening the bus POT fuse drawer will de-energize the bus. In addition, there was a placard on the upper Bus 23 POT fuse drawer that stated CAUTION DO NOT OPEN, Opening this door will De-Energize the BUS. These cautions were not put into practice by the electrical maintenance technician who opened the upper Bus 23 bus POT fuse drawer.

Analysis:

The inspectors reviewed this finding using the guidance contained in Appendix B, Issue Screening, of IMC 0612, Power Reactor Inspection Reports. The inspectors determined that the licensees failure to follow CO instructions and operating plant equipment without a procedure was a performance deficiency that was reasonably within the licensees ability to foresee and correct and should have been prevented. The inspectors determined that the finding was more than minor because it was associated with the Initiating Events Cornerstone attribute of Human Performance and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, not following CO 89693 instructions and operating plant equipment by opening the upper Bus 23 bus POT fuse drawer without a procedure led to the inoperability of the control room emergency ventilation air conditioning system. The inspectors evaluated the finding using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Phase 1 - Operations Checklists for Both PWRs and BWRs, using the Checklist 7, BWR Refueling Operation with RCS Level > 23.

The inspectors answered no to all of the checklist items requiring a phase 2 or phase 3 analysis and therefore the finding screened as having very low safety significance (Green).

The inspectors concluded that the finding had a cross-cutting aspect in Human Performance, Work Practices. The licensee staff involved in the event failed to utilize human performance error prevention techniques commensurate with the risk of the assigned task to prevent impact to the station (H.4(a)). The two electrical maintenance technicians proceeded in the face of uncertainty or unexpected circumstances without notifying their supervisor when the bus pot fuses were not out in the field as expected, did not follow the pre-job brief instructions for a non-intrusive, visual safety verification walkdown, and did not use appropriate self and peer checking practices.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings states, in part, that activities affecting quality shall be prescribed by procedures appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to the above, on October 24, 2011, two electrical maintenance technicians did not follow CO 89693 instructions and operated plant equipment without a procedure. Corrective actions taken included an electrical maintenance department clock reset and stand down to discuss the event and consequences of taking actions in the plant without proper guidance. Further licensee planned corrective actions include presenting to Operations and the Configuration Control Committee the possibility of installing robust barriers or locking devices on bus pot installations. Because this violation was determined to be of very low safety significance and the issue was entered into the licensees CAP as IR 1280681, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000237/2011005-01, Bus 23 POT Fuse Drawer Resulting in the Inoperability of the Control Room Emergency Ventilation Air Conditioning System)

.2 Control Rod Blade Disengages from Lifting Tool and Drops Over Reactor Core into an

Empty Cell

Introduction:

A finding of very low significance (Green) involving a NCV of TS 5.4.1 was self-revealed on October 24, 2011. During the course of maintenance activities, a control rod blade disengaged from its lifting tool while suspended over Unit 2s reactor core. The control rod blade experienced a gravity fall into an empty cell in the reactor core. The event occurred when licensee staff performed a series of steps, in support of the maintenance activity, which were not covered by their maintenance procedure.

Description:

On October 24, 2011, Dresden Unit 2 was undergoing refueling outage D2R22. Unit 2 was in Mode 5 with fuel in the core. At the time of the event the licensee was performing a control rod drive (CRD) guide tube (GT) vacuuming evolution. The evolution required control rod blade (CRB) 58-31 and its associated fuel support piece (FSP) to be removed from their cell in order for the GT vacuuming to proceed. The licensee used a special lifting tool (REM*Take-2 tool) to remove these core components.

By design, the lifting tool could carry a CRB and FSP at the same time. While suspended from the lifting tool each of these core components was held in place by independent grapple mechanisms. The grapple hook holding the CRB would remain engaged, even when the lifting tools control was set to open, as long as the weight of the CRB was suspended from the grapple hook. For the FSP to disengage from the lifting tool, the FSP needed to be properly aligned with an alignment pin on the lower core plate. The entire lifting tool and core components were suspended via a main cable hoist from the units refuel bridge.

While the CRB and FSP were suspended from the lifting tool, the licensees staff on the refuel bridge decided to disconnect the air lines used to control the open/close functions of the lifting tool. This process was required in order to vent water that had accumulated in the air lines and untangle said lines. The air lines tended to tangle and wrap around the lifting tools main cable hoist during normal operation of the tool. Per discussions with licensee staff, untangling and venting of the air lines had to be performed on a regular basis to allow the lifting tool to operate correctly. Disconnecting the air lines for the purpose of untangling and venting them was a common practice. With a suspended load on the lifting tool and the CRBs grapple hook engaged the air system is not providing any function to the lifting tool.

After disconnecting and untangling the air lines, the licensees staff cycled the tools controls (i.e. open and close function of the CRBs grapple) in order to vent water accumulated in the air lines. Cycling the controls of the latch does not cause the core components (CRB and FSP) to disengage from the lifting tool. When the licensee finished untangling, venting and re-attaching the air lines they failed to restore the lifting tool to the correct configuration. Specifically, they failed to return the open/close pushbuttons for the CRBs grapple hook to the closed position. This error meant that once the air lines were re-attached the CRBs grapple hook was trying to retract (i.e.

release the CRB). The only thing preventing the CRB from dropping at that moment was the weight of the CRB being exerted on the grapple hook, stopping it from retracting.

Following these events, and after completing the vacuuming for the CRD GT the licensee began the process of aligning the CRB back to its appropriate cell location. In the process of aligning the CRB, the bottom of the CRB momentarily rested on the edge of the cells top guide. This allowed the weight of the CRB to be released from the lifting tool and permitted the grapple hook to retract. Unaware of this condition, the licensees staff on the refuel bridge pulled on the lifting tools hoist in order to align the CRB over the destination cell. This action removed the bottom of the CRB from the edge of the cells top guide, effectively releasing the CRB and allowing gravity to take over. The CRB dropped through the Top Guide, fell approximately 12 feet, and came to rest in the vertical position on top of the lower core plate. There were no fuel assemblies in the cell where the CRB fell. However, there were about five fuel assemblies in the adjacent cells. Immediately following the event the licensee returned equipment to a safe configuration and stopped work.

The licensee was using Procedure DFP 0800-47, Exchanging Control Rod and/or Fuel Support Pieces Within the Reactor Vessel Using the REM*TAKE-2 Grapple Tool, Revision 07, for moving the reactor components. However, this procedure does not prescribe the process for untangling and venting the air lines. Per discussions with licensee staff venting/untangling the air lines was considered a G.E. best practice but was not covered under any procedures. The periodic untangling of the air lines was necessary, for the proper operation of the lifting tool as these become significantly tangled around the main hoist.

The licensee entered the issue into their CAP as IR 01280766. A prompt investigation and an Apparent Cause Evaluation (ACE) were performed. As an interim measure, while the ACE was being performed the licensee issued guidance to its staff to prevent them from performing the untangling/venting with a suspended load. Based on the results of the ACE the licensee implemented a number of corrective actions. Corrective actions included: 1) Procedure changes to DFP 0800-47 to provide specific instructions for performing the air lines untangling and venting; 2) Reviewed REM*Take-2 training in order to develop potential enhancement; 3) The dropped CRB was removed from the core and was retired from service; and 4) Assigned actions for other Exelon BWR sites to review this event and apply corrective actions as necessary. Additionally, before restarting the unit, the licensee performed an inspection of the affected cell and surrounding fuel assemblies. The visual inspection was reviewed by the licensees in-house staff, Exelons Corporate Fuel Reliability Engineer (This individual holds additional qualifications on core components design and manufacturing) and the fuel vendor (Westinghouse). Based on their review no issues were identified. Their reviews were documented on the ACE and Westinghouse proprietary letter BTK 11-1456.

Analysis:

The inspectors determined that untangling and venting of the lifting tools air lines was a maintenance activity affecting quality, as described in Regulatory Guide 1.33, which was not prescribed by procedures, therefore it was a performance deficiency (PD). The performance deficiency was determined to be more than minor because if left uncorrected it had the potential to lead to a more significant safety concern. Specifically, had the PD not been corrected and a similar event happened again, the CRB would have the potential to tip over and fall over fuel assemblies rather than on an empty cell. This could result in the potential damage of fuel assemblies or other core components.

The inspectors determined that the finding could be evaluated in accordance with Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process. The inspectors determined this finding did not meet the definition of Loss of Control as stated in Table 1 of Appendix G. In addition, using Checklist 7, BWR Refueling Operations with RCS Level >23, contained in 1, the inspectors determined that the finding did not require a Phase 2 or Phase 3 analysis based on the criteria established on the checklist. Specifically, 1) the finding did not increase the likelihood of a loss of RCS inventory or RCS level instrumentation; 2) the finding did not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; and 3) the finding did not degrade the licensees ability to recover decay heat removal (DHR) once it is lost. The issue did not need a quantitative assessment and screened as having very low safety significance (Green) using Figure 1 of IMC 0609, Appendix G.

This finding had a cross-cutting aspect in the area of human performance, work practices, because the licensee staff did not ensure supervisory and management oversight of work activities such that nuclear safety was supported. Specifically, the failure of licensee management to identify fuel handling activities performed as skill-of-the-craft versus those activities requiring procedures allowed for the tacit acceptance that activities affecting quality (i.e. untangling/venting of air lines) were performed without procedural guidance. The inspectors reached this conclusion based on discussions with licensee staff and reviewing the licensees ACE. H.4(c)

Enforcement:

The inspectors determined that the licensees failure to prescribe procedures regarding the proper method to untangle and vent air lines for the CRB lifting tool was a violation of Dresden Nuclear Power Station TS Section 5.4.1, Procedures.

Section 5.4.1 states, in part, that written procedures shall be established, implemented, and maintained covering applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, issued February 1978. Procedures for Performing Maintenance are recommended in Section 9 of Appendix A to this Regulatory Guide.

Contrary to the above, on October 24, 2011, the licensee failed to provide a procedure that prescribed the steps required to safely untangled/vent the air lines and return the lifting tool to its correct configuration. Specifically, the procedure did not address when, how and under which conditions the untangling and venting of the lifting tools air lines could be performed. This failure resulted in the accidental drop of CRB 58-31 in the reactor vessel and into an empty cell in the core. This event was entered into the licensees corrective action program as IR 01280766, CRD Disengages From REM*TAKE-2 Grapple. Corrective actions by the licensee included revising procedure DFP 0800-47 to include specific instructions on how and where to untangle the lifting tools air lines. Because this violation was of very low safety significance and it was entered into the licensees corrective action program, this violation is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000237/2011005-02, Control Rod Blade Disengages from Lifting Tool and Drops Over Reactor Core into an Empty Cell)

.3 Unplanned Unit 2 Secondary Containment Technical Specification Entry

Introduction:

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.

Description:

On December 21, 2011, WO 1450006-01, D2 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 reactor building serves as the secondary containment structure. The primary purpose of the secondary containment is to minimize the ground level release of airborne radioactive materials and to provide for a controlled, elevated release of the building atmosphere under accident conditions.

There are two personnel air locks between the turbine building and reactor buildings at grade elevation (i.e., 517 feet). Each pair of personnel access control doors is electrically interlocked so that only one of the pair may be open at a given time.

At the end of the inspection period, the licensee was still working on a root cause to identify all causal factors related to this issue. The inspectors plan to review the root cause report and determine if there were any violations of NRC requirements and that appropriate corrective actions were applied. The inspectors considered this issue to be an unresolved item (URI) pending evaluation efforts. (URI 05000237/2011005-03)

.4 (Closed) Licensee Event Report 05000237/2011-002-00: Steam Leak Results in High

Pressure Coolant Injection Inoperability The inspectors reviewed the subject Licensee Event Report (LER) to evaluate the licensees response to a steam leak in the Unit 2 High Pressure Coolant Injection (HPCI) System that occurred on August 12, 2011. Specifically, air-operated valve 2-2301-29, HPCI Inlet Drain Pot Inboard Drain line to the Main Condenser, developed a through-wall leak. 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 carbon steel valve material caused by two-phase flow. Additionally, it was determined that the periodic inspection procedure for this valve contained instructions to inspect its internal parts but did not provide adequate guidance to ensure that the valve body was inspected for degradation. Furthermore, the licensee identified other components of this system that have not been inspected for degradation either.

In addition to replacing the valve body and testing the valve satisfactorily, the licensees corrective actions included revising the inspection instructions to ensure adequate inspection for degradation and to ensure proper scope of susceptible valves.

The inspectors review of this event was documented in Inspection Report 2011-004.

One finding of very low safety significance (Green) and an associated NCV were documented. Specifically, a NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was documented as self-revealed for the failure to have an adequate procedure to ensure quality during the preventive maintenance performed on the 2-2301-29 valve. The inspectors review of the LER did not identify any additional violations of NRC regulations. Documents reviewed in this inspection are listed in the to this report. This LER is closed.

.5 (Closed) Licensee Event Report 05000249/2010-003 00: Steam Leak Results in High

Pressure Coolant Injection Inoperability The inspectors reviewed the subject LER to evaluate the licensees response to a steam leak in the Unit 3 HPCI System that occurred on November 26, 2010, during a plant startup following a refueling outage. Specifically, when the HPCI system was being tested per the plants TSs, the HPCI turbine developed a steam leak from the turbine steam chest. The HPCI turbine was manually tripped and the testing secured until repairs were completed. The licensee subsequently determined that the cause of the steam leak was less than adequate torque on four studs/nuts on the turbine steam chest. Even though the specific cause of the steam leak could not be confirmed, the licensee subsequently concluded that three different factors could have potentially contributed to the torque values being less than required. The bolts could have relaxed in between the low and high pressure surveillance tests, the torque wrench could have been used improperly or no additional torque was applied to the bolts following the first pass.

Following the event, the licensee adjusted the torque values on the steam chest and satisfactorily tested the HPCI system. Although the licensee evaluated the other factors, it was concluded that no additional corrective actions were necessary because any issues as a result of those factors would be caught by the high pressure HPCI run (which is the test performed following the low pressure HPCI run) and corrected prior to the HPCI system being restored back to service.

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

4OA5 Other Activities

.1 (Closed) Unresolved Item 05000237/2010004-01; 05000249/2010004-01, Failure to

Address NRC Concerns Regarding a Reactor Building Closed Cooling Water Line Break in the Unit 3 Reactor Building The inspectors reviewed URI 05000237/2010004-01; 05000249/2010004-01. In the third quarter of 2010 (3Q2010), during a routine internal flooding inspection, the inspectors identified an issue associated with the potential failure to address NRC concerns regarding a Reactor Building Closed Cooling Water (RBCCW) line break in the Unit 3 Reactor Building. Specifically, the inspectors noted that there were RBCCW pipes directly above the safety-related busses 23-1, 24-1, 33-1, and 34-1. This area containing these buses was surrounded by a berm. If those pipes were to fail and break, the berm around the busses would hold water in potentially resulting in the failure of power to all the low pressure ECCS pumps.

The inspectors reviewed a letter from the NRC to Commonwealth Edison (the licensee)dated August 20, 1982. The subject was, SEP [Systematic Evaluation Program]

Topic III-5.B, Pipe Break Outside Containment - Dresden Nuclear Power Station Unit 2.

The enclosure to the letter included the NRCs Safety Evaluation Report (SER) for SEP Topic III-5.B. In the safety evaluation, the NRC reviewed the licensees response to a previously documented NRC concern (which was documented as a result of the SEP)regarding a break of the RBCCW piping above the 23-1 and 24-1 safety-related switchgear on Unit 2 and the potential flooding consequences. The licensee evaluated the flooding scenario and concluded that even though an RBCCW line failure would flood the area containing the safety-related switchgear (due to the berms), there were floor drains and several floor penetrations inside the bermed area around busses 23-1 and 24-1. The floor penetrations would aid in directing the water to the elevation below.

However, the largest floor penetration had a one and one-half inch sleeve around it that would cause the water to accumulate to a higher volume before draining. As part of the corrective action from this evaluation, the licensee stated the sleeve would be notched and concluded that the penetration holes would be sufficient to let the water drain before it could get high enough to impact the safety-related busses.

When the inspectors performed a walkdown of the Unit 3 safety-related busses 33-1 and 34-1 they noticed that there was only one floor penetration (not several) inside the bermed area around the busses. In addition, that floor penetration in Unit 3 still had a one and one-half inch sleeve around it. This configuration for Unit 3 did not appear to have been evaluated at the time the SER was written. The licensee entered this issue into its CAP as IR 1108059 and performed an evaluation after the inspectors brought this condition to their attention. The inspectors reviewed the licensees evaluation which concluded that based on the flow through the floor penetration (calculated included the sleeve around it) the water would not reach a height that could impact the safety-related busses. As part of the corrective actions and to minimize the risk of this flooding scenario, the licensee plans to notch the sleeve around the floor penetration in Unit 3.

No violations of NRC requirements were identified.

The inspectors review of this issue was considered to be a part of the original inspection effort, and as such did not constitute any additional inspection samples. This URI is closed.

.2 (Closed) Unresolved Item 05000237/2010005-03; Drywell Equipment Drain Sump

Discharge Valves 2-2001-5 and 2-2001-6 Body to Diaphragm Leakage On October 19, 2010, the Unit 2 drywell floor drain sump outboard discharge air operated valve, 2-2001-106, was declared inoperable due to local observation of a pinhole water leak between the body of the valve and the diaphragm while the valve was stroking closed after pumping the Unit 2 drywell floor drain sump (DWFDS).

The licensee generated issue report (IR) 1127948, PCIV 2-2001-106 DWFDS DISCH VLV INOP, to address this issue. The licensee determined that the cause of the leak was relaxation of the valve bolting torque. Air operated valve 2-2001-106 was repaired by torquing the bolts back to the original torque value. In addition, the licensee generated operability evaluation (OpEval) number 10-007, Drywell Primary Containment Isolation System - Equipment and Floor Drain Valves. The licensee determined that the leakage noted was not indicative of a diaphragm leak, which would originate from between the bonnet and diaphragm or the stem and bonnet of the valve.

On October 27, 2010, the Unit 2 DWEDS inboard discharge air operated valve, 2-2001-5, and the Unit 2 drywell equipment drain sump pump outboard discharge air operated valve, 2-2001-6, exhibited pinhole leaks, 20 drops and 1 drop respectively, between the body of the valve and the lower side of the diaphragm while the valves were stroking closed after pumping the Unit 2 DWEDS. The licensee generated IR 1131662, DWEDS 2-2001-5 and 2-2001-6 BODY-DIAPHRAGM LEAKAGE, to address the issue.

The licensee determined that based on OpEval 10-007, the leakage was not indicative of a diaphragm leak; therefore, valves 2-2001-5 and 2-2001-6 remained operable. As a compensatory action, the licensee performed weekly inspection of the valves during the pumping operation.

The inspectors questioned the licensee regarding the ability of these valves to meet the local leak rate test (LLRT) acceptance criteria and TS 3.6.1.3, Primary Containment Isolation Valves (PCIVs). The ability of the Unit 2 drywell equipment drain sump inboard and outboard discharge air operated valves to perform their function as primary containment isolation valves was considered an URI.

On October 18 and 19, 2011, the inspectors observed the performance of WO 1288325, D2 30M/RFL TS LLRT VLV 2-2001-106 DWFDS, WO 1290616, D2 30M/RFL TS LLRT VLV 2-2001-5, and WO 1290612, D2 30M/RFL TS LLRT VLV 2-2001-6 DWEDS. The inspectors reviewed the results of the local leak rate tests. All three valves met the acceptance criteria; therefore, they were able to perform their function as primary containment isolation valves. This URI is closed.

.3 (Closed) Unresolved Item 05000249/2010005-04, Adequacy of High Pressure Core

Injection System Low Pressure Testing On February 1, 2011, inspectors documented an unresolved item (URI 05000249-2010005) regarding the November 26, 2010, low pressure test of the Unit 3 HPCI System following the Unit 3 refueling outage. The purpose of this test is to verify that HPCI is able to provide the required amount of flow (5000 gpm) when reactor pressure is at the low end of the range HPCI is required to function (150 psig).

During the low pressure test on November 26, the computer points associated with the HPCI system showed abnormal parameters including system flow cycling between about 4000 gpm and 7000 gpm and pump discharge pressure cycling between 300 psig and 500 psig. The instrumentation seen by the Nuclear Safety Operator (NSO) in the control room did not show as severe of readings, but still indicated oscillations between 5000 and 5600 gpm. These oscillations resulted in severe vibration of the system discharge piping as reported by NLOs in the field during the test. The licensee determined that despite the oscillations, the HPCI system was operable because the control room instrumentation indicated that the HPCI system met its acceptance criteria of providing greater than 5000 gpm at a discharge pressure higher than the pressure needed to inject into the vessel for a time period greater than the mission time of the pump.

Subsequently when the licensee performed the high pressure test on November 27, 2010, no oscillations or abnormalities were identified and the HPCI system met the acceptance criteria. Additionally, the licensee performed walkdowns of the HPCI system piping to look for damage caused by the vibrations, and found none.

The URI was documented pending inspector review of the licensees evaluation of the HPCI performance during low pressure operations. The licensee performed an Apparent Cause Evaluation (ACE 1152867-02) to evaluate the flow and pressure oscillations during the low pressure test. In this ACE, the licensee determined that the apparent cause of the flow and pressure oscillations was flow through the 3-2301-10 valve with the valve fully open. During HPCI testing, the flowpath of the HPCI system is modified so as to not send water into the reactor, which could cause an unnecessary transient on the plant. The 3-2301-10 valve is a globe valve used in this modified test lineup to throttle flow and provide backpressure on the pump to simulate the backpressure that would be present if the HPCI system were injecting into the reactor.

Normally during testing, this test valve is slowly throttled open until a condition is reached that shows that the system is providing an adequate amount of flow at a pressure high enough to simulate actual conditions during an injection. During the November 26 low pressure test, however, the NSO performing the test throttled the valve fully open, attempting to lower to discharge pressure of the pump to the lowest pressure allowed by the test procedure. The licensee determined that this valve had never been fully opened during a test, and that the flow characteristics through the valve at this position apparently caused the flow and pressure oscillations in the HPCI system.

The licensee determined that this condition is only present during testing because during an actual injection, the 3-2301-10 valve is fully closed, and instead the flow goes through the injection valve, a gate valve that fully opens during an injection. The flow characteristics are significantly different through a gate valve than a globe valve in that a gate valve provides very little resistance to flow when fully open. Based on this determination, the licensee modified the test procedures to instruct operators to throttle the test valve to achieve the proper flow and verify that the discharge pressure remains acceptable, whereas the procedure previously instructed the operators to throttle the test valve to achieve an adequate discharge pressure while trying to attain adequate flow.

In their review of the ACE, the inspectors examined a couple concerns. First, the inspectors questioned whether the oscillations that the HPCI system experience were from the pump being in a runout condition caused by low pump discharge pressure during the November 26 low pressure test and if this could be repeated during an actual HPCI injection into the reactor. Upon further review of the HPCI system and discussions with the Component Performance and Testing Branch in the Office of Nuclear Reactor Regulation (NRR), the inspectors determined that the HPCI system is designed such that the steam supply to the HPCI pump turbine is automatically throttled based on the flowrate downstream of the pump. Therefore, if the discharge pressure were lowered such that the flowrate increased above the setpoint, the HPCI turbine control valves would close, slowing the pump and decreasing the flowrate. Based on the pump curves for the HPCI pump, as the pump speed decreases, the discharge pressure at which the pump would experience runout also decreases such that if the control system performs as designed, the pump would not experience runout over its operating range. Based on reviews of pump runs before and after the low pressure test, and through reviews of calibration records, the licensee determined that the control system was operating as designed. Therefore, pump runout is an unlikely scenario for the HPCI pump.

The other question the inspectors had was whether the test procedure was appropriate to test the low pressure operations of the HPCI system. Specifically, the inspectors were questioning why the surveillance test does not require operators to lower the discharge pressure of the pump to the pressure that would reasonably simulate the backpressure of the reactor during an actual low pressure injection. The licensees current testing method is to achieve the adequate flowrate and verify that the pressure is greater than or equal this required discharge pressure, with no requirement that they get as close to the value as reasonable achievable. The basis for this method is that if the pump can achieve the required flowrate at a higher discharge pressure, it can meet or exceed this flowrate at a lower discharge pressure, and as stated above, because of the design of the HPCI system, the pump will not experience runout at lower discharge pressures.

The inspectors discussed this with the TSs Branch in NRR and concluded that the surveillance test is adequate to test the low pressure operations of the HPCI system.

Based on the review of the available information, the inspectors did not identify any findings or violations. This URI is closed.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 19, 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. Proprietary material received during the inspection was returned to the licensee.

.2 Interim Exit Meetings

Interim exit meetings were conducted for:

• The results of the inservice inspection with Site Vice-President D. Czufin on October 28, 2011.

• Radiological hazard assessment and exposure control, occupational ALARA planning and control and performance indicator verification under the occupational radiation safety cornerstone with Mr. D. Czufin, Site Vice President on November 4, 2011

• The licensed operator requalification training biennial written examination and annual operating test results were discussed with the Operators Training staff, Pat Chambers, via telephone on December 5, 2011.

• The annual review of Emergency Action Level and Emergency Plan changes with the licensee's Emergency Preparedness Coordinator, Mr. D. Doggett, via telephone on December 8, 2011.

• The inspection results for radioactive gaseous and liquid effluent treatment and performance indicator verification under the public radiation safety cornerstone with Mr. Shane Marik, Plant Manager, on December 16, 2011.

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

D. Czufin, Site Vice President

S. Marik, Station Plant Manager

D. Anthony, NDES Manager

H. Bush, 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

J. Fox, Design Engineer

G. Gates, Operations

G. Graff, Nuclear Oversight Manager

D. Gronek, Operations Director

M. Hosain, Site EQ Engineer

R. Johnson, Chemistry

L. Jordan, Training Director

B. Kapellas, Work Control Director

D. Ketchledge, Engineering

J. Knight, Chemistry Manager

M. Knott, Instrument Maintenance Manager

J. Kish, Site ISI

S. Kvasnicka, NDE Level III

D. Leggett, Regulatory Assurance Manager

T. Loch, Design Engineering Manager

P. Mankoo, Chemistry Supervisor

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, Sr. Rad Pro. Technical Specialist

P. Quealy, Emergency Preparedness Manager

R. Ruffin, Licensing Engineer

J. Sipek, Engineering Director

Nuclear Regulatory Commission

S. West, Director, Division of Reactor Projects

M. Ring, Chief, Division of Reactor Projects, Branch 1

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

IEMA

R. Schulz, Illinois Emergency Management Agency

R. Zuffa, Illinois Emergency Management Agency

LIST OF ITEMS

Opened

05000237/2011005-01 NCV Bus 23 Pot Fuse Drawer Resulting in the Inoperability of the Control Room Emergency Ventilation Air Condition System (4OA3)

05000237/2011005-02 NCV Control Rod Blade Disengages from Lifting Tool and Drops Over Reactor Core into an Empty Cell (4OA3)

05000237/2011005-03 URI Unplanned Unit 2 Secondary Containment TS Entry (4OA3)

Closed

05000237/2011005-01 NCV Bus 23 Pot Fuse Drawer Resulting in the Inoperability of the Control Room Emergency Ventilation Air Condition System (4OA3)

05000237/2011005-02 NCV Control Rod Blade Disengages from Lifting Tool and Drops Over Reactor Core into an Empty Cell (4OA3)

05000237/2011-002 00 LER Steam Leak Results in High Pressure Coolant Injection (HPCI) Inoperability

05000249/2010-003-00 LER Steam Leak Results in HPCI Inoperability

05000237/2010004-01; URI Failure to Address NRC Concerns Regarding a Reactor

05000249/2010004 01 Building Closed Cooling Water (RBCCW) Line Break in the Unit 3 Reactor Building

05000237/2010005-03 URI Drywell Equipment Drain Sump Discharge Valves 2-2001-5 and 2-2001-6 Body to Diaphragm Leakage

05000249/2010005-04 URI Adequacy of High Pressure Core Injection System Low Pressure Testing

Discussed

None