IR 05000254/2012002

IR 05000254-12-002, 05000265-12-002; on 01/01/12 - 03/31/12; Quad Cities Nuclear Power Station, Units 1 & 2; Other Activities

ML12128A375
Person / Time
Site:	Quad Cities
Issue date:	05/07/2012
From:	Ring M NRC/RGN-III/DRP/B1
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-12-002
Download: ML12128A375 (45)

Text

UNITED STATES May 7, 2012

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2 -

NRC INTEGRATED INSPECTION REPORT 05000254/2012002 AND 05000265/2012002

Dear Mr. Pacilio:

On March 31, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Quad Cities Nuclear Power Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on April 4, 2012, with T. Hanley and other members of your staff.

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

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

One self-revealed finding of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements. Further, a licensee-identified violation, which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs)

consistent with Section 2.3.2 of the NRC 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 Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Quad Cities Nuclear Power Station. If you disagree with the 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 Quad Cities 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/

Mark A. Ring, Branch Chief Branch 1 Division of Reactor Projects Docket Nos. 50-254 and 50-265 License Nos. DPR-29 and DPR-30

Enclosure:

Inspection Report 05000254/2012002 and 05000265/2012002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-254; 50-265 License Nos: DPR-29; DPR-30 Report No: 05000254/2012002 and 05000265/2012002 Licensee: Exelon Generation Company, LLC Facility: Quad Cities Nuclear Power Station, Units 1 and 2 Location: Cordova, IL Dates: January 1 through March 31, 2012 Inspectors: J. McGhee, Senior Resident Inspector B. Cushman, Resident Inspector J. Draper, Reactor Engineer M. Mitchell, Health Physicist D. Jones, Reactor Inspector C. Mathews, Illinois Emergency Management Agency Approved by: Mark Ring, Branch Chief Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000254/2012002, 05000265/2012002; 01/01/12 - 03/31/12; Quad Cities Nuclear Power

Station, Units 1 & 2; Other Activities.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding was identified by the inspectors.

The finding was considered a non-cited violation (NCV) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Barrier Integrity

Green.

A self-revealed finding of very low safety significance and associated NCV of Technical Specifications 5.4.1.a, Procedures, was identified on November 29, 2011, when operators performing the removal of danger tags for a Unit 1 refuel bridge clearance found that the tag for the main power cable had been incorrectly hung on a phone cord. Followup discussion revealed that the operators that originally placed the tags did not accurately identify the main power cable using the techniques specified in OP-AA-109-101, Clearance and Tagging, for ensuring that the cable was the correct component, and, therefore, did not implement the clearance order as written.

Immediate actions taken were removal of the implementing operators qualifications and shop briefing on the errors with site personnel. The licensee entered this issue into the corrective action program.

Inspectors determined that the issue was more than minor because, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern either through direct damage to safety equipment or degraded physical barriers.

The inspectors performed a SDP Phase 1 screening for the finding using IMC 0609,

Table 4a, and answered the questions under the Barrier Cornerstones No. Therefore, the finding screened as very low safety significance, or

Green.

Inspectors determined that a significant contributor to this finding was the failure of the operator performing the independent verification task to remain in role and ensure the task was executed in accordance with the site standard, HU-AA-101, "Human Performance Tools and Verification Practices." As a result, inspectors identified that this issue had a cross-cutting aspect in the area of Human Performance - Work Practices for failure to use the human performance techniques to ensure that the work tasks are performed safely and individuals do not proceed in the face of uncertainty (H.4(a)).

(Section 4OA2.5)

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 Unit 1 operated at 100 percent thermal power throughout the evaluated period from January 1 through March 24, 2012, with the exception of planned power reductions for routine surveillances, main condenser flow reversals, planned equipment repair, and control rod maneuvers. On March 24 operators reduced power to 90 percent in response to an unplanned feedwater heating transient caused by a switchyard disconnect being closed onto a grounded bus (discussed further in Section 4OA3 of this report). The unit did not trip but generator bearing vibration remained elevated, and the unit was held at 90 percent power until a plan was developed for unit recovery. On March 30 the unit returned to full power after an adverse condition monitoring plan was developed for the generator elevated vibration. The unit operated at full power through the closure of the reporting period.

Unit 2 Unit 2 operated at 100 percent thermal power throughout the evaluated period from January 1 through March 18, 2012, with the exception of planned power reductions for routine surveillances, main condenser flow reversals, planned equipment repair, and control rod maneuvers until the unit entered coast down for the refueling outage. On March 18, 2012 the unit began a normal shutdown from 96 percent power. The unit was shut down on March 19 for refueling outage Q2R21. The outage was still in progress at the end of the reporting period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 External Flooding

a. Inspection Scope

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

As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable. The inspectors also reviewed the abnormal operating procedure (AOP) for mitigating the design basis flood to ensure it could be implemented as written.

This inspection constituted one external flooding sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Condition - High Wind Conditions

a. Inspection Scope

Since high winds were forecast in the vicinity of the facility for February 29, 2012, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. On February 29, 2012, the inspectors walked down the licensees emergency alternating current power systems, because their safety-related functions could be affected or required as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate.

During the inspection the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions.

The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. Inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant.

Additionally, the inspectors reviewed the UFSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of corrective action program (CAP) items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the Attachment to this report.

This inspection constituted one readiness for impending adverse weather condition sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 1 turbine building closed cooling water system with 1A pump out-of-service for maintenance;

• Unit 1 station blackout diesel generator and support systems;

• Unit 1 and Unit 2 drywell pneumatic systems;

• Unit 1/2 B diesel driven fire pump; and

• Unit 1 reactor core isolation cooling system.

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

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

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On March 13, 2012, the inspectors performed a complete system alignment inspection of the Unit 2 reactor core isolation cooling system to verify the functional capability of the system following return to service after major maintenance activities. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment, scaffolding, or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Fire Zone 8.2.1.A, Unit 1 Turbine Building, Elevation 547-0, Condensate Pump Room;

• Fire Zone 8.2.1.B, Unit 2 Turbine Building, Elevation 547-0, Condensate Pump Room;

• Fire Zone 11.2.2, Unit 1 Reactor Building, Elevation 554-0, Southeast Corner Room - 1B Residual Heat Removal Room; and

• Fire Zone 8.2.6.E, Unit 2 Turbine Building, Elevation 595-0, Hallway.

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.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR; engineering calculations; and abnormal operating procedures to identify licensee commitments. The specific documents reviewed are listed in the to this report. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the corrective action program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the Unit 1 high pressure coolant injection room and floor drain sump piping and discharge check valve configuration to assess the adequacy of watertight doors, potential flood paths and to verify drains and sumps were clear of debris and were operable.

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

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees inspection and testing of the 1B residual heat removal room cooler air/water heat exchanger to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria. Inspectors also verified that acceptance criteria considered differences between test conditions, design conditions, and testing conditions.

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

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 March 12 through March 16, 2012, the inspectors conducted a review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system, risk-significant piping and components, and containment systems.

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

.1 Piping Systems Inservice Inspections

a. Inspection Scope

The inspectors observed or reviewed records of the following nondestructive examinations mandated by the American Society of Mechanical Engineers (ASME)

Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement:

• Magnetic Particle Examination of the residual heat removal system heat exchanger weld N8A-F1 RHRHX, Report No. Q2R21-066;

• Magnetic Particle Examination of the residual heat removal system heat exchanger weld N8A-F2 RHRHX, Report No. Q2R21-067;

• Visual Examination (VT-3) of the residual heat removal service water system variable spring can 1003B-W-304, Report No. Q2R21-024;

• Ultrasonic Examination of the containment spray system, elbow to pipe weld 1401-7, Report No. Q2R21-045;

• Ultrasonic Examination of the containment spray system, elbow to pipe weld 1402-5, Report No. Q2R21-046; and

• Ultrasonic Examination of the containment spray system, elbow to pipe weld 1402-7, Report No. Q2R21-047.

During the prior outage non-destructive surface and volumetric examinations, the licensee did not identify any relevant/recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute.

The licensee had not performed pressure boundary welding since the beginning of the preceding outage for Unit 2. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if:

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

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

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

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On January 24, 2012, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

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

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

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

Inspectors observed the following operator activities in the main control room that required heightened awareness or were related to increased risk during the inspection period:

• On January 10, 2012, the inspectors observed control room operators during a Unit 1 main condenser circulating water flow reversal evolution being performed to troubleshoot a condition that could potentially have resulted in a turbine trip;

• On March 12 and 13, the inspectors observed reactivity manipulations to support troubleshooting elevated boron concentration in Unit 2 reactor water;

• On March 18, the inspectors observed main control room operators manipulating plant equipment and performing reactivity changes during a planned Unit 2 shutdown for a refueling outage.

The inspectors evaluated the individual operator and crew performance in the following areas during the control room monitoring:

• clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Z3800: Turbine Building Closed Cooling Water System;

• Z6700: 4160 Volt Switchgear; and

• Z4700-2: Drywell Pneumatic System.

The inspectors reviewed events such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

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

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

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

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

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

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Emergent troubleshooting and unavailability of Unit 1/2 emergency diesel generator (EDG) control circuit after a hard ground developed on Unit 1 125 Vdc during a monthly EDG surveillance;

• Emergent corrective maintenance to Unit 2 high pressure coolant injection and control room envelope ventilation system B recirculating compressor unit during scheduled work for Unit 1 station blackout diesel generator and Unit 1 250 Vdc battery charger;

• Revision 0 of the safe shutdown management plan for Unit 2 refueling outage, Q1R21, associated safety profile, and contingency plans;

• Unit 2 reactor core isolation cooling (RCIC) system turbine overhaul, Unit 2 RCIC/2B core spray watertight door, Unit 2 EDG, 2B core spray pump supply breaker, and emergent Unit 2 125 Vdc ground troubleshooting;

• Electrical bus realignment to support outage testing and removal of offsite power line, one offsite supply unavailable, Unit 1/2 EDG unavailable, lowered inventory and fuel movement on Unit 2, switchyard work including ground fault, and Unit 1 online maintenance; and

• Electrical bus realignment to support outage testing and transformer testing, switchyard breaker work, transformer 22 testing and restoration including emergent schedule delays, and Unit 1/2 A standby gas treatment unavailable and delayed return to service.

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

Specific documents reviewed during this inspection are listed in the Attachment to this report. These maintenance risk assessments and emergent work control activities constituted six samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Issue Report (IR) 1317933: Unit 2 EDG Voltage Exceeded 5000V During Load Reject;

• IR 1231568: Received 901-8, 125V Battery Ground Alarm on Unit 1;

• IR 1324066: Unit 2 HPCI Gland Seal Hotwell Pump Overload During QCOS 2300-05;

• IR 1326102: Offsite Supply relaying Scheme;

• IR 1342018: Followup to IR 1272614 - Mode 3 SDC To LPCI Transition; and

• IR 1338287: Increase in Unit 2 Reactor Water Boron.

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

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

• Engineering Change (EC) 385962: Auto Pumpdown of B CR HVAC RCU (permanent);

• EC 387707: Bus 13-1/14-1 Degraded Voltage Relays MCR Alarm Modification (temporary); and

• EC 386613: Provide TMOD to Keep the 1/2 A SBGT System Available While Replacing Power Supplies in Panel 2202-70B During Q2R21 (temporary).

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(s). 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 two temporary modification samples and one permanent plant modification samples as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• QCOS 2300-05: Quarterly HPCI Pump Operability Test following U1 HPCI Gland Seal Hotwell Condensate Pump replacement;

• QCOP 6600-05: Unit 1/2 EDG output breaker functional test to 13-1 and 23-1 following Bus 23-1 outage work;

• QCTS 0600-05: Main Steam Isolation Valve Local Leak Rate Testing for the B Main Steam Line following Inboard/Outboard MSIV maintenance;

• QCTS 0600-07: Feedwater Check Valve Local Leak Rate Test partial for the 2-220-58B; and

• QCOS 6600-39: Unit 2 Emergency Diesel Generator Largest Load Reject Surveillance, partial for the Unit 0 Emergency Diesel Generator to Unit 2.

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 safe shutdown management plan (SSMP) and contingency plans for the Unit 2 refueling outage (RFO), which started on March 19, 2012, and was still in progress at the end of the reporting period, 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 refueling outage 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 Attachment to this report.

• Licensee configuration management, including maintenance of defense-in-depth commensurate with the outage safety plan (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;

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

This inspection is continued into the next reporting period and the remainder of the inspection and documentation of the completed sample will be included in Inspection Report 05000254/2012003, 05000265/2012003.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• QCOS 6600-20: Emergency Diesel Generator Endurance and Margin Full Load Reject and Hot Fast Restart Test for the Unit 2 EDG (Routine);

• QCOS 1600-07: Reactor Coolant Leakage in the Drywell (RCS);

• QCOS 6600-06: Diesel Generator Cooling Water Pump Flow Rate Test for the Unit 1/2 DGCWP (IST);

• QCOS 1400-01: Quarterly Core Spray System Flow Rate Test (IST);

• QCOS 2900-01: SSMP Flow Rate Test (IST);

• QCTS 0600-05: Main Steam Isolation Valve Local Leak Rate Test (CIV);

• QCTS 0600-36: Automatic TIP Ball Valve Local Leak Rate Test (CIV); and

• QCOS 0202-08: Reactor Recirculation Cold Shutdown Power Operated Valve Test (IST).

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

• did preconditioning occur;

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

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

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

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

• measuring and test equipment calibration was current;

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

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

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

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, ASME Code, and reference values were consistent with the system design basis;

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

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

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

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

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

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

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one routine surveillance testing sample, four inservice testing samples, one reactor coolant system leak detection inspection sample, and two containment isolation valve samples as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on January 26, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities.

The inspectors observed emergency response operations in the technical support center and the operations support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the to this report.

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

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted a partial 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 followup. The inspectors reviewed the results of radiation protection program audits (e.g., licensees quality assurance audits or other independent audits). The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection. The inspectors reviewed the results of the audit and operational report reviews to gain insights into overall licensee performance.

b. Findings

No findings were identified.

.2 Radiological Hazard Assessment (02.02)

a. Inspection Scope

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

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

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

• Inboard Main Steam Isolation Valve Overhaul;

• Under-vessel Instrumentation (SRM/IRM/);

• Exelon 2B Recirculation Motor/Pump Replacement; and

• Shaw 2B Recirculation Motor/Pump Replacement.

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

• identification of hot particles;

• the presence of alpha emitters;

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

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

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

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

b. Findings

No findings were identified.

.3 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors selected various containers holding non-exempt licensed radioactive materials that may cause unplanned or inadvertent exposure of workers, and assessed whether the containers were labeled and controlled in accordance with 10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g), Exemptions to Labeling Requirements.

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

• RWP 10012944: Under-Vessel Instrumentation (SRM/IRM/), Revision 0;

• RWP 10011248: Exelon 2B Recirculation Motor/Pump Replacement, Revision 0;

• RWP 10012958: Shaw 2B Recirculation Motor/Pump Replacement, Revision 0; and

• RWP 10013048: Turbine - Sandblasting Activities, Revision 0.

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

For 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.

The inspectors reviewed the licensees procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters. The inspectors assessed whether or not the licensee has established a de-facto release limit by altering the instruments typical sensitivity through such methods as raising the energy discriminator level or locating the instrument in a high-radiation background area.

b. Findings

No findings were identified.

.5 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors evaluated ambient radiological conditions (e.g., radiation levels or potential radiation levels) during tours of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, radiation work permits, and worker briefings.

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

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

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

• RWP 10012941: U2 Drywell Safety Relief Valve Remove/Replace (Q2R21)

Exelon, Revision 0;

• RWP 10012958: Unit 2 Drywell Replace 2B Recirculation Pump and Motor (Q2R21 Shaw, Revision 0; and

• RWP 10013048: Turbine - Sandblasting Activities, Revision 0.

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

The inspectors examined the posting and physical controls for selected high-radiation areas and very high-radiation areas to verify conformance with the occupational performance indicator.

b. Findings

No findings were identified.

.6 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.

.7 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.

b. Findings

No findings were identified.

2RS2 Occupational As-Low-As-Is-Reasonably-Achievable (ALARA) Planning and Controls

This inspection constituted a partial 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 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 ALARA, which included a review of processes used to estimate and track exposures from specific work activities.

b. Findings

No findings were identified.

.2 Radiological Work Planning (02.02)

a. Inspection Scope

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

• Inboard Main Steam Isolation Valve Overhaul;

• Drywell Safety Relief Valve Remove/Replace (Q2R21) Exelon;

• Unit 2 Drywell Replace 2B Recirculation Pump and Motor; and

• Reactor Disassembly/Reassembly/Cavity Work.

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

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., teledosimetry, 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.

b. Findings

No findings were identified.

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

a. Inspection Scope

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

The inspectors evaluated whether the licensee had established measures to track, trend, and if necessary, to reduce occupational doses for ongoing work activities.

The inspectors assessed whether trigger points or criteria were established to prompt additional reviews and/or additional ALARA planning and controls.

b. Findings

No findings were identified.

.4 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.

.5 Radiation Worker Performance (02.05)

a. Inspection Scope

The inspectors observed radiation worker and radiation protection technician performance during work activities being performed in radiation areas, airborne radioactivity areas, or high-radiation areas. The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice (e.g., workers are familiar with the work activity scope and tools to be used, workers used ALARA low-dose waiting areas) and whether there were any procedure compliance issues (e.g., workers are not complying with work activity controls). The inspectors observed radiation worker performance to assess whether the training and skill level was sufficient with respect to the radiological hazards and the work involved.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours performance indicator (PI) for Quad Cities Units 1 and 2 for the period from the first quarter 2011 through the fourth 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 narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 2011 through December 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.

This inspection constituted two unplanned scrams per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications performance indicator for Quad Cities Units 1 and 2 for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 2011 through December 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.

This inspection constituted two unplanned scrams with complications samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Transients per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours performance indicator for Quad Cities Units 1 and 2 for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC integrated inspection reports for the period of January 2011 through December 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.

This inspection constituted two unplanned transients per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

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

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify 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 followup, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

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

b. Findings

No findings were identified.

.3 Annual Sample: Review of Operator Workarounds

a. Inspection Scope

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

The inspectors performed a review of the cumulative effects of OWAs. The documents listed in the Attachment to this report were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP, and proposed or implemented appropriate and timely corrective actions, which addressed each issue.

Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.

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

b. Findings

No findings were identified.

.4 Selected Issue Followup Inspection: Issue Report 1275820, Adverse Trend in U2

DWFD Sump In-Leakage

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting an increase for the Unit 2 unidentified leakage.

On October 12, 2011, systems engineering documented this trend during their periodic system trend review. Unidentified leakage for Unit 2 remained unchanged until a downpower was performed for turbine instrument line maintenance in December 2011.

After the power ascension, Unit 2 unidentified leakage began a linear increase of about

.03 gpm/day. IMC 2515, Appendix D Attachment 1, was used as guidance by the

inspectors. Chemistry performed analysis of the water pumped from the Unit 2 floor drain sump and confirmed that the water was consistent with reactor water, but was at a lower temperature found in either control rod drive water or seal water from the reactor recirculation pump. Chemistry also performed a review of Unit 2 containment particulate activity and confirmed that particulate activity had not changed over the course of the cycle and did not indicate the presence of a reactor grade steam leak in containment.

Unit 2 unidentified leakage reached and stabilized at near 2 gpm late February 2012 and remained at this level until Unit 2 shut down for a refueling outage on March 18, 2012.

Upon entry into the Unit 2 drywell, operations noted a water spray emitting from the 2B reactor recirculation pump flange. This water was subcooled water originating from the mechanical mating surface where the motor stand and seal casing mount to the flange of the 2B reactor recirculation pump. This pump was scheduled to be overhauled during this outage, and maintenance was performed to machine the surfaces that constitute the metal to metal sealing surfaces. Since the leakage was originating from a mechanical sealing surface, this leak does not constitute pressure boundary leakage as defined by TS. Retest during the vessel pressure test confirmed that the leak had been repaired.

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

b. Findings

No findings were identified.

.5 Selected Issue Followup Inspection: Issue Report 1295770, Level Three Clearance and

Tagging Error - Unit 1 Refuel Bridge

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting a failure to correctly implement the site clearance and tagging procedure while removing the Unit 1 refueling bridge from service.

On November 29, 2011, operators hung a tag on the wrong electrical cable.

The protective tagging error was identified after the covered work on the bridge was complete and during tag removal/power restoration process. The licensee staff completed the investigation for the error, and management approved the corrective action plan in January 2012.

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

b. Findings

Introduction:

A self-revealed finding of very low safety significance (Green) and associated non-cited violation of Technical Specifications 5.4.1.a, Procedures, was identified on November 29, 2011, when operators performing the removal of danger tags for a Unit 1 refuel bridge clearance found that the tag for the main power cable had been incorrectly hung on a phone cord. Subsequent discussion revealed that the operators hanging the tags did not use the techniques specified in OP-AA-109-101, Clearance and Tagging, for ensuring that the cable was the cable specified on the tag.

Description:

During the early morning hours of November 29, 2011, the operator hanging tags for Clearance Order 96565, Unit 1 Refuel Bridge, entered the contaminated area surrounding the bridge while the second operator, who was there to perform independent verification of the tag placement, waited outside the contaminated area. The first operator tagged the bridge main disconnect switch and the air compressor main disconnect open as specified on the clearance order and moved to tag the cable. He did not see the main power cable (disconnected and lying alongside the bridge rails) and went straight to what looked like a power cable hanging off the side of the bridge. This cable was later determined to be a multi-line phone cord. This was the first time that this operator had tagged out the bridge, and since there was no equipment identification label on the cable, he was reluctant to hang the tag.

The second operator entered the area to perform the independent verification of the component positioning and tag placement. He verified the first two tags had been properly placed. He also did not see the main power cable lying next to the rail.

Recognizing the apparent confusion of the first operator on whether or not he had the right cable, the second operator engaged the first to assist in determining if the tag should be hung on the cable. The two operators then talked themselves into hanging the tag because it was the only cable so it must have been the right one.

The first operator then verified the cable was disconnected as required by the tag and attached the tag to the cable. The second operator then signed for the independent verification. The clearance order was authorized at 0241 on November 29, and at 1000 that same day, mechanical maintenance personnel performed the safety verification prior to beginning work. The mechanics went to the bridge main power cord and verified the equipment part number and noun name on the label, but did not find the danger tag the clearance order said was hung at that location. They then determined that the tag they were looking for was hanging on a different cable. Believing this was a different power supply and that the tag on the main disconnect provided an adequate boundary for the main power cable (which it did), they convinced themselves that the discrepancy didnt matter and that the work could go forward. They completed the repair without incident. At 2200 that same day, the operators performing the final clear of the tags identified that the danger tag was on the phone cord, not the main power cable.

The licensee removed the qualifications of the two operators involved in hanging the tags and briefed workers on the importance of immediately identifying discrepancies in the clearance order to the Operations department.

Analysis:

While performing the clearance order, the operators hung the tag on the wrong component. The operators actions did not meet the performance requirements of OP-AA-109-101 Clearance and Tagging, step 10.1.10, which states the following:

"If the equipment information on a C/O [clearance order] Tag does not match the equipment label such that there is a reasonable doubt of the identity of the equipment, then Shift Management shall be contacted to make a determination if the C/O Tag should be placed or not.

1. Data revision should be initiated.

2. If a labeling discrepancy is identified, then INITIATE a labeling change request."

Neither the operators hanging the tags nor the mechanics performing the safety verification notified shift management when the equipment number on the tag could not be matched to the cable. The operators had enough doubt that they compromised the independent verification of their assigned task to discuss whether or not they were on the right cable. They also did not follow through with the procedure requirement to initiate a labeling change prior to hanging the tag. The label change process would have engaged supervision and provided the additional engagement of supervision to ensure the component was properly identified. Inspectors determined the issue was more than minor because, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern either through direct damage to safety equipment or degraded physical barriers.

The inspectors performed a SDP Phase 1 screening for the finding using IMC 0609, Table 4a, and answered the questions under the Barrier Cornerstones No. Therefore, the finding screened as very low safety significance, or Green.

Inspectors determined that a significant contributor to this finding was the failure of the operator performing the independent verification task to remain in role and ensure the task was executed in accordance with the site standard, HU-AA-101, "Human Performance Tools and Verification Practices." As a result, the inspectors identified that this issue had a cross-cutting aspect in the area of Human Performance - Work Practices for failure to use the human performance techniques to ensure that the work tasks were performed safely and individuals do not proceed in the face of uncertainty (H.4(a)).

Enforcement:

Technical Specifications 5.4.1.a required that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operation)."

Regulatory Guide 1.33, Appendix A, Section 1, Administrative Procedures, listed equipment control (e.g., locking and tagging) as one of the specified procedures.

Contrary to the above, on November 29, 2011, operators failed to implement the requirements of OP-AA-109-101, Clearance and Tagging, in that the operators positioning the components and hanging the danger tags did not accurately identify the main power cable and, therefore, did not hang the tag as required by the clearance order. Subsequently, mechanics performed maintenance on the refuel bridge with the tags hung incorrectly. While the bridge was electrically isolated so that danger to people and equipment as a result of the error was minimal in this instance, the behavioral weaknesses associated with the procedural non-compliance, if manifested during placement of another clearance order, could have resulted in significant equipment damage or personnel injury. Because this violation was determined to be of very low safety significance and this issue has been entered into the licensees corrective action program as IR 1295770, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000254/2012002-01, Failure to Follow Clearance Order Instructions). Immediate corrective action was to remove qualifications of the operators involved in placing the clearance and all operators were briefed on the errors, the procedural requirements, and the actions the operators should have taken in this circumstance. Additional briefings were conducted with maintenance personnel concerning their responsibility for resolving questions or discrepancies that arise during the clearance safety verification.

4OA3 Follow Up of Events and Notices of Enforcement Discretion

.1 Switchyard 345 Kilovolt Disconnect Closed in to Ground

a. Inspection Scope

The inspectors reviewed the plants response to a switchyard event when a 345 kilovolt disconnect was closed in on an energized bus with grounding cables still in place.

On March 24, 2012, a live switchyard disconnect was closed in on a grounded bus, resulting in a voltage transient on Unit 1. Unit 2 was not adversely impacted by the voltage transient in the switchyard.

The Unit 1 voltage transient resulted in a half-scram, a partial loss of feedwater heating, low voltage on Bus 18 and an increase in main generator bearing vibration. In response to the partial loss of feedwater heating, operators implemented the abnormal procedure and took action to lower reactor power to 90 percent of rated. As a result of the low bus voltage on Bus 18, the Unit 1 emergency core cooling system tripped. The pump trip was quickly followed by a low discharge pressure alarm in both the 2A and 2B core spray systems. Operators promptly restored the keepfill pump and vented affected systems with no loss of operability. Unit 1 main turbine vibration on generator bearings 9 and 10 was elevated after the event and remained at 6.0 and 7.0 mils respectively after condition in the secondary plant stabilized. Reactor protection system A motor generator set tripped during the voltage transient, resulting in an invalid actuation signal, which caused containment isolation valves for several systems to close. Inspectors evaluated the operators and plant equipment response to the event and did not identify any issues. The unit remained at 90 percent power until a recovery plan was developed on March 30 that included administrative limits for the generator bearing vibration.

Power was then returned to 100 percent of rated until the end of the reporting period.

The event was entered into the licensees corrective action program as IR 1345302, and the cause evaluation was still underway at the end of the reporting period.

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

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

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Institute of Nuclear Power Operations (INPO) Accreditation Report Review

a. Inspection Scope

The inspectors reviewed the reports for the most recent INPO accreditation assessments conducted for all accredited programs at Quad Cities Nuclear Power Station. The maintenance, chemistry, radiation protection and engineering technical program accreditation report for the November 2009 assessment and the operations programs accreditation report for the 2011 assessment were reviewed. The inspectors reviewed the reports to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC followup.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 3, 2012, the inspectors presented the inspection results to Site Vice President, T. Hanley, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The results of the inservice inspection with Site Vice President, Mr. T. Hanley, on March 16, 2011;

• The inspection results for the areas of radiological hazard assessment and exposure controls; and occupational ALARA planning and controls with Mr. S. Darin, Acting Plant Manager, on March 23, 2012.

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.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements, which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV:

• Title 10 CFR 50, Appendix B, Criterion V states, in part, that activities affecting quality shall be prescribed by documented procedures appropriate to the circumstances and shall be accomplished in accordance with these instructions.

Contrary to the above, on January 5, 2012, the licensee failed to implement written procedures that ensure proper documentation of quality parts used during maintenance. Specifically, electrical maintenance department technicians replaced the charging module in an Appendix R emergency light pack (ELP)without the proper work order documentation. The technicians inappropriately used the provisions of MA-AA-716-003, Tool Pouch/Minor Maintenance, to complete the work activity. MA-AA-716-003 states that quality level parts cannot be worked under tool pouch or minor maintenance and directs the user to generate a work order for resolution. This issue was identified by an electrical maintenance supervisor on the next shift while reviewing work logs from the previous shift, and documented in IR 1315674. This issue is more than minor because the performance deficiency, if left uncorrected, would have the potential to lead to a more significant safety concern. The finding is of very low safety significance or Green because the emergency light pack satisfactorily passed post-maintenance testing and would have provided the required lighting if needed. Therefore, the degradation rating for the deficiency is low and the finding screened as Green in accordance with IMC 0609, Appendix F, Task 1.3.1, qualitative screening questions.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Hanley, Site Vice President

S. Darin, Acting Plant Manager

W. Beck, Regulatory Assurance Manager

D. Collins, Radiation Protection Manager

J. Kopacz, Operations Shift Manager

V. Neels, Chemistry/Environ/Radwaste Manager

K. OShea, Acting Operations Director

S. Piepenbrink, Security Manager

T. Wojcik, Online Work Control Manager

Nuclear Regulatory Commission

M. Ring, Chief, Reactor Projects Branch 1

Illinois Emergency Management Agency (IEMA)

C. Settles, IEMA

LIST OF ITEMS

Opened

05000254/2012002-01 NCV Failure to Follow Clearance Order Instructions

Closed

05000254/2012002-01 NCV Failure to Follow Clearance Order Instructions

Discussed

None.

Attachment