IR 05000254/2011003

IR 05000254-11-003, 05000265-11-003, on 04/01/11 - 06/30/11. Quad Cities Nuclear Power Station, Units 1 & 2, Maintenance Risk Assessments and Emergent Work Control, and Other Activities

ML11213A214
Person / Time
Site:	Quad Cities
Issue date:	08/01/2011
From:	Ring M NRC/RGN-III/DRP/B1
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-11-003
Download: ML11213A214 (48)

Text

August 1, 2011

SUBJECT:

QUAD CITIES NUCLEAR POWER STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000254/2011003; 05000265/2011003

Dear Mr. Pacilio:

On June 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Quad Cities Nuclear Power Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on July 6, 2011, with Mr. S. Darin, and other members of your staff.

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

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

Based on the results of this inspection, two self-revealed findings of very low safety significance were identified. The findings involved violations of NRC requirements. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of any NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Quad Cities Nuclear Power Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the 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 document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Mark A. Ring, Chief Branch 1 Division of Reactor Projects

Docket Nos. 50-254; 50-265 License Nos. DPR-29; DPR-30

Enclosure:

Inspection Report 05000254/2011003; 05000265/2011003 w/Attachment: Supplemental Information

REGION III==

Docket Nos:

50-254; 50-265 License Nos:

DPR-29, DPR-30 Report No:

05000254/2011003 and 05000265/2011003 Licensee:

Exelon Generation Company, LLC Facility:

Quad Cities Nuclear Power Station, Units 1 and 2 Location:

Cordova, IL Dates:

April 1 through June 30, 2011 Inspectors:

J. McGhee, Senior Resident Inspector

B. Cushman, Resident Inspector

J. Draper, Reactor Engineer R. Murray, Duane Arnold Resident Inspector M. Mitchell, Health Physicist D. Jones, Reactor Inspector

C. Mathews, Illinois Emergency Management Agency

Approved by:

M. Ring, Chief Branch 1 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000254/2011003, 05000265/2011003; 04/01/11 - 06/30/11; Quad Cities Nuclear Power

Station, Units 1 & 2; Maintenance Risk Assessments and Emergent Work Control, and Other Activities.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified by the inspectors. 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.

A.

NRC-Identified

and Self-Revealed Findings

• Green The inspectors concluded the inadequate assessment and management of risk for the maintenance activity discussed above was a performance deficiency. Failure to identify operational impact and adequately evaluate the risk associated with moving the feedwater clearance activity resulted in tripping the reactor water cleanup pumps and challenging the key shutdown safety function of decay heat removal. This performance deficiency was different from the examples in IMC 0612, Appendix E, Examples of Minor Issues, in that additional reliance on manual actions by operators was required to prevent a more significant challenge to key safety functions. The performance deficiency was more than minor because it could be reasonably viewed as a precursor to a significant event using the minor screening questions of IMC 0612, Appendix B.

Inspectors performed the phase 1 assessment, using both Appendix G and Appendix K of IMC 0609, and determined the finding was Green because sufficient equipment was available to meet the core heat removal guidelines, the licensees ability to recover decay heat removal was not significantly degraded, both subsystems of shutdown cooling were inoperable but available, the licensees procedure contained appropriate direction for depressurizing and placing shutdown cooling subsystems in service, and the operators had the appropriate training and briefings to accomplish the required actions in the time required. The inspectors identified that this finding had a cross-cutting aspect in Human Performance - Work Control, in that, the licensee failed

. A self-revealed finding of very low safety significance and associated NCV of 10 CFR 50.65(a)(4) was identified for failure to adequately assess and manage risks associated with maintenance activities to prevent plant transients that upset plant stability. On May 31, 2011, after a feedwater flush activity was delayed and rescheduled, operators implementing a clearance order supporting the activity failed to identify a conflict with the reactor water cleanup pumps operating in the decay heat removal mode. When the operators closed the feedwater injection valve and shut off the injection flow path, the reactor water cleanup pumps tripped on low flow.

Immediate corrective actions included stopping the feedwater work, opening the feedwater injection valve, and restoring reactor water cleanup flow. The issue has been entered into the licensees corrective action program as Issue Report (IR) 1223075.

to appropriately coordinate work activities by incorporating actions to address the impact of changes in the schedule and conflicts between different work activities (H.3(b)).

(Section 1R13)

• Green Inspectors determined that the licensees failure to follow the procedure as written resulted in Unit 2 surveillance procedure steps being performed on Unit 1 safety-related equipment; therefore, this was a performance deficiency. The inspectors answered the more than minor screening questions of IMC 0612, Appendix B, Figure 2, Block 9, question 2.a, indicating the performance deficiency could be viewed as a precursor to a significant event, and the finding was, therefore, more-than-minor. Inspectors determined that performing procedural action on the wrong unit would impact the Initiating Event Cornerstone objective of limiting the likelihood of upsetting plant stability and challenging critical safety functions during power operations. Specifically, the objective attributes of configuration control equipment performance were negatively impacted. Inspectors performed the SDP phase I screening using IMC 0609,

Attachment 4, Table 4a for transient initiators in the Initiating Events Cornerstone column and answered the question No. The issue was screened as Green or very low safety significance. Inspectors concluded that the finding had a cross-cutting aspect in Human Performance-Work Practices, in that, 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 4OA2)

. A self-revealed finding of very low safety significance and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures. and Drawings, was identified on May 4, 2011, when instrument technicians caused a control room alarm on Unit 2 after receiving permission from the Unit 1 unit supervisor to perform the test on Unit 1. Immediate actions included termination of the surveillance and restoration of the equipment to the correct lineup for plant conditions. The issue was entered into the corrective action program as IR 1211933.

B.

No violations of significance were identified.

REPORT DETAILS

Unit 1

Summary of Plant Status

Unit 1 began the first day of the inspection period at full power, but began reducing power at 11:00 p.m. on April 1, 2011, to perform power suppression testing to identify a leaking fuel assembly. Power was reduced to 62 percent. Power suppression testing identified and suppressed the leaking bundle, and operators returned the unit to 100 percent thermal power at 3:30 p.m. on April 4, 2011.

Unit 1 operated at 100 percent thermal power with the exception of planned power reductions for routine surveillances, planned equipment repair, and control rod maneuvers until operators began reducing power on May 8, 2011, for unit shutdown and the beginning of the scheduled refueling outage, Q1R21. Major activities completed during the refueling outage included the replacement of three low pressure rotors and lower casing assemblies, low pressure turbine upper bellows replacement, isophase bus duct upgrade, installation of a leading edge flow monitor in feedwater, 1A recirculation pump impeller and motor replacements, replacement of transformer T19, and recirculation pump adjustable speed drive upgrades.

Unit 1 startup following the refueling outage began at 10:31 p.m. on June 5. The unit operated at low power for several days addressing issues with the new turbine and support equipment.

Power ascension began again on the evening of June 12. At 05:11 a.m., with the unit at 60 percent power, a steam leak developed between turbine control valve 1 and the high pressure turbine. Operators began rapidly reducing power, making the decision to insert a manual reactor scram at 34 percent power to allow the main turbine to be manually tripped in order to isolate the leak. This event was documented in Event Notification 46951 and is discussed further in Section 4OA3 of this report. On June 14, following repair of the steam leak, Unit 1 was restarted finally reaching 100 percent on June 17, 2011.

Unit 1 operated at 100 percent thermal power for the rest of the inspection period except for planned power reductions for routine surveillances, planned equipment repair, and control rod maneuvers.

Unit 2 Unit 2 began the inspection period at 100 percent power and operated at full power for the remainder of the inspection period with the exception of planned power reductions for routine surveillances, planned equipment repair, and control rod maneuvers.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

==1R01 Adverse Weather Protection

==

.1

a.

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

Inspection Scope

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

• The explanations for the events;

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

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

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

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

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

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

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

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

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

b.

No findings were identified.

Findings

.2 a.

Summer Seasonal Readiness Preparations The inspectors performed a review of the licensees preparations for summer weather for selected systems, including conditions that could lead to an extended drought.

Inspection Scope During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions.

Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR)and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures.

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

The inspectors reviews focused specifically on the following plant systems:

• Unit 1 isophase bus duct cooling system, and

• Unit 2 main power transformer temperature monitoring system.

This inspection constituted one seasonal adverse weather sample as defined in IP 71111.01-05.

a.

No findings were identified.

Findings

==1R04 Equipment Alignment

==

.1

a.

Quarterly Partial System Walkdowns The inspectors performed partial system walkdowns of the following risk-significant systems:

Inspection Scope

• Unit 1 125 Vdc safety-related batteries prior to discharge test;

• Unit 1 high pressure coolant injection with Unit 1 reactor core isolation cooling out-of-service for routine surveillance;

• Unit 1 & Unit 2 fuel pool cooling system while in alternate decay heat removal mode of operation; and

• Unit 1 B core spray system after surveillance and unit startup.

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 four partial system walkdown samples as defined in IP 71111.04-05.

b.

No findings were identified.

Findings

==1R05 Fire Protection

==

.1

Routine Resident Inspector Tours a.

(71111.05Q)

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:

Inspection Scope

• Fire Zone 11.3.1, Unit 2 Reactor Building, Elevation 544-0, SW Corner Room - 2B Core Spray;

• Fire Zone 8.2.6.B, Unit 1 Turbine Building, Elevation 595-0, Low Pressure Heater Bay;

• Fire Zone 8.2.7.B, Unit 1 Turbine Building, Elevation 608-6, Low Pressure Heater Bay (West);

• Fire Zone 17.2.2, Unit 2 Transformer Area, Elevation 595-0, Auxiliary Transformer; and

• Fire Zone 17.2.3, Unit 2 Transformer Area, Elevation 595-0, Reserve Auxiliary Transformer.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

Documents reviewed are listed in the Attachment to this report.

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

b.

No findings were identified.

Findings

1R08 Inservice Inspection Activities

From May 9 through May 13, 2011, 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.

(71111.08G)

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

.1 a.

Piping Systems Inservice Inspection 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.

Inspection Scope

• Magnetic Particle Examination of the emergency core cooling system (ECCS),collar - torus shell weld 1025-58, Report No. Q1R21-040;

• Magnetic Particle Examination of the emergency core cooling system (ECCS),collar - torus shell weld 1025-62, Report No. Q1R21-041;

• Ultrasonic Examination of the emergency core cooling system (ECCS), pipe - pipe weld 1025-13, Report No. Q1R21-037;

• Ultrasonic Examination of the emergency core cooling system (ECCS), pipe - pipe weld 1025-26, Report No. Q1R21-038; and

• Ultrasonic Examination of the emergency core cooling system (ECCS), pipe - pipe (2 seam welds) 1025-5, Report No. Q1R21-039.

The inspectors reviewed the following examinations completed during the previous outage with relevant/recordable conditions/indications accepted for continued service to determine if acceptance was in accordance with the ASME Code Section XI or an NRC-approved alternative.

• Evaluation (EC 0000375492) of a liquid penetrant indication found during the examination (Report Number Q1R20-0210 of a hanger attachment to the 1B Recirculation Pump (0200-W-127A), Action Request Number 00917605.

The inspectors reviewed the following pressure boundary weld completed for a risk-significant system since the beginning of the last refuelling outage to determine if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by the ASME Code Section XI. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedure was qualified in accordance with the requirements of the Construction Code and ASME Code Section IX.

• Replacement of Core Spray Piping 1-1410-1.5-DX, Work Order No. 1265266.

b.

No findings were identified.

Findings

.2.3

Not Used

.5 Not Used

a.

Identification and Resolution of Problems 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:

Inspection Scope

• 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.

No findings were identified.

Findings

==1R11 Licensed Operator Requalification Program

==

.1

Resident Inspector Quarterly Review a.

(71111.11Q)

On June 27, 2011, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

Inspection Scope

• 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.

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

b.

No findings were identified.

Findings

==1R12 Maintenance Effectiveness

==

.1

Routine Quarterly Evaluations a.

(71111.12Q)

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

Inspection Scope

• Unit 1 and Unit 2 high pressure coolant injection systems; and

• Unit 1 and Unit 2 station blackout diesel engines, generators, and auxiliaries.

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

b.

No findings were identified.

Findings

==1R13 Maintenance Risk Assessments and Emergent Work Control

==

.1

a.

Maintenance Risk Assessments and Emergent Work Control 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:

Inspection Scope

• Work Week (11-15-03) for Unit 2: affected equipment included emergent Unit 2 diesel generator cooling water pump alignment concurrent with hardened vent (2-1699-6) surveillance;

• Work Week (11-20-08) for Unit 2: affected equipment included 345 kV breaker 8-9 and line 0403, Unit 1 auxiliary transformer feeds to bus 13 and bus 14, 1/2 B standby gas treatment (SBGT) system, Unit 1 outage electrical bus realignments and battery transfers, load drop with control rod sequence exchange and turbine testing, and turbine control valve electrical control jumper replacement;

• Work Week (11-21-09) for Unit 2: affected equipment included 1/2 B SBGT system, main control room ventilation, Unit 1 offsite power unavailable to Unit 2, Unit 1 250 Vdc battery test with no 250 Vdc divisional separation on Unit 2, and Unit 1 A/B residual heat removal service water loops;

• Q1R21 Shutdown Safety Management Plan and Unit 2 online risk profile-Revision 1 and associated safety profiles; and

• Q1F63 Shutdown Safety Management Plan and on-line risk profile for Work Week (11-25-13) following reactor scram.

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 five samples as defined in IP 71111.13-05.

b. Findings

Introduction:

A self-revealed finding of very low safety significance (Green) and associated NCV of 10 CFR 50.65(a)(4) was identified for failure to adequately assess and manage risks associated with maintenance activities to prevent plant transients that upset plant stability. On May 31, 2011, operators implementing a clearance order supporting a feedwater system flush failed to identify a conflict with the reactor water cleanup pumps operating in the decay heat removal mode. When the operators closed the feedwater injection valve and shut off the injection flow path, the reactor water cleanup pumps tripped on low flow.

Description On May 31 at 09:46 a.m., operators completed prerequisites for QCOS 0201-08, Reactor Vessel Level Class 1 and Associated Class 2 System Leak Test.

Test conditions maintained reactor pressure of 1005 psig and reactor water temperature at 180 degrees Fahrenheit. Time to boil was calculated to be 137 minutes.

This procedure aligned the plant to support testing in Mode 4 with an operating reactor recirculation pump, control rod drive cooling injection into the vessel and reactor water cleanup (RWCU) system operating in the decay heat removal mode with reject flow in service. Reactor pressure in this mode was controlled with control rod drive system injection and a reject flow path from RWCU. The leak test inspections were completed at 2:41 p.m., and the operator moved on to the portion of the procedure that allowed cold control rod scram timing testing. To support scram timing, reactor pressure was maintained at 980 psig and, although both subsystems of shutdown cooling were available, they were inoperable because of the reactor pressure being maintained by the test above the shutdown cooling high pressure isolation setpoint.

At the 6:00 p.m. outage turnover meeting on May 30, 2011, operating personnel questioned the need to perform a scheduled flush of the feedwater system.

This flush had been included in the schedule each outage as a contingency action to be performed if needed, but had not been performed for several years after being evaluated as not required. The work and clearance orders scheduled to support the work activity were delayed until the need for the flush was verified.

At the 6:00 p.m. outage turnover meeting on May 31, 2011, the operations outage manager verified that the feedwater line flush was required and the schedule had been updated to perform the flush between 3:00 p.m. and 9:00 p.m. on May 31.

The feedwater group supervisor contacted both the control room supervisor and the supervisor coordinating the reactor vessel leak test to see if they knew of any reason that the clearance orders for the feedwater flushes could not be placed. No conflict was identified and the feedwater group supervisor dispatched operators to isolate the equipment and hang the clearance order tags.

At 9:54 p.m. on May 31, 2011, both RWCU pumps tripped off due to a low flow condition. The low flow was the result of operators closing the feedwater inlet valve, 1-0220-57A, and shutting off the RWCU return flow path to the reactor vessel.

Operators immediately recognized the reason for the pump trips and stopped placement of the clearance. They opened the feedwater inlet valves and restarted the RWCU pumps within 36 minutes of the trip. Indicated reactor water temperature did not change because the control rod drive system injection and the RWCU reject flow paths were not affected by the feedwater flow path isolation or the pump trip. The addition of colder water and reject of warmer water provided by the feed and bleed alignment coupled with the time after shutdown delayed the temperature rise and extended the time to boil, thereby limiting the plant upset.

The risk assessment performed for the feedwater activity moving to a later time in the schedule did not identify the conflict with operation of the RWCU pumps in the decay heat removal mode. In addition, the informal review performed by the feedwater group supervisor just before authorizing the activity did not identify the conflict. No risk management actions were in place to protect the RWCU pumps operating in the decay heat removal mode in accordance with OP-AA-108-117, Protected Equipment Program, which would have provided an additional barrier to prevent tripping the pumps.

Analysis Inspectors performed the significance determination using IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, and Appendix K, Maintenance Risk Assessment and Risk Management Significance determination Process. Using Appendix G and its Attachment 1, Checklist 8, BWR Cold Shutdown or Refueling Operation Time to Boil >2 hours: RCS Level 23 Above Top of Flange, and Figure 1, Roadmap for Shutdown Findings, inspectors performed the phase 1 assessment and determined the finding was Green because no quantitative phase 2 analysis was required. That is, sufficient equipment was available to meet the core heat removal guidelines and the licensees ability to recover decay heat removal was not significantly degraded. Appendix K was used to evaluate the failure to implement risk management actions required by the licensees procedure. Since both subsystems of shutdown cooling were available, the licensees procedure contained appropriate direction for depressurizing and placing shutdown cooling subsystems in service, and the inspectors determined that the operators had the appropriate training and briefings to

The inspectors concluded the inadequate assessment and management of risk for the maintenance activity discussed above was a performance deficiency.

Failure to identify operational impact and adequately evaluate the risk associated with moving the feedwater clearance resulted in an unintentional trip of the RWCU pumps, upsetting plant stability and challenging the decay heat removal function during shutdown operations. This performance deficiency was different from the examples in IMC 0612, Appendix E, Examples of Minor Issues, in that additional reliance on manual actions by operators was required to prevent a more significant challenge to key safety functions. The performance deficiency was more than minor because it could be reasonably viewed as a precursor to a significant event using the minor screening questions of IMC 0612, Appendix B.

accomplish the required actions in the time required, there was no risk deficit and the finding screens as Green, or very low safety significance.

The inspectors identified that this finding had a cross-cutting aspect in Human Performance-Work Control. The licensee failed to appropriately coordinate work activities by incorporating actions to address the need to keep personnel apprised of work activities, the operational impact of work activities, and plant conditions that may affect work activities (H.3(b)). Specifically, the activities did not incorporate limitations, schedule ties, or risk management actions to provide a barrier to having a human performance issue when the clearance activity moved in the schedule.

Enforcement Contrary to the above, on May 31, 2011, the licensee failed to assess and manage the risk associated with work required to support flushing the feedwater injection line concurrent with operation of the reactor water cleanup system in the decay heat removal mode. As a result of implementing the activities without the appropriate assessment of risk or risk management controls, the licensees staff unintentionally tripped off the RWCU pumps, upsetting plant stability and challenging the decay heat removal function during shutdown operations. Because this violation was determined to be of very low safety significance, and these issues have been entered into the licensees corrective action program as IR 1223075, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000254/2011003-01, RWCU Pumps Tripped on Low Flow).

Title 10 CFR 50.65(a)(4) requires, in part, that before performing maintenance activities, the licensee shall assess and manage the increase in risk that may result from the maintenance activity.

Immediate corrective actions included stopping the feedwater work, opening the feedwater injection valve, and restoring reactor water cleanup flow.

==1R15 Operability Evaluations

==

.1

a.

Operability Evaluations The inspectors reviewed the following issues:

Inspection Scope

• Unit 1 main turbine control valve reactor protection system potential non-conformance;

• Pitting observed on 1B core spray injection valve 1-1402-38A;

• Unit 2 leading edge flow monitor feedwater flow in maintenance condition;

• Unit 1B core spray discharge check valve 1-1402-8B will not fully close;

• Q1R21 system leakage test exceptions; and

• Unit 1 control rod drifted out one notch during rod exercising.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors reviewed 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.

No findings were identified.

Findings

==1R18 Plant Modifications

==

.1

a.

Plant Modifications The inspectors reviewed the following modification(s):

Inspection Scope

• EC 364925: Replace Flow Control Valve 0-5741-333 for the B Control Room Heating, Ventilation, and Air Conditioning System; and

• EC 377710: Thermal Performance Test Instrumentation.

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 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 temporary modification sample and one permanent plant modification sample as defined in IP 71111.18-05.

b.

No findings were identified.

Findings

==1R19 Post-Maintenance Testing

==

.1

a. Post-Maintenance Testing

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

Inspection Scope

• Work Order 1260418-02: Unit 1 Emergency Diesel Generator Largest Load Reject Surveillance;

• Work Order 1260418-03: Unit 1/2 Emergency Diesel Generator Largest Load Reject Surveillance;

• QCOS 0250-04: MSIV Closure Timing;

• QCTS 0600-11: HPCI Steam Supply Local Leak Rate Test (MO 1(2)-2301-4, MO 1(2)-2301-5);

• QCTS 0820-14: Unit 1 2B MSIV Leak Repair; and

• QCTS 0820-12: Seat Leakage Test for Core Spray Pressure Isolation Valves 1(2)-1492-9A/B, MO 1(2)-1402-25A/B.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

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

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

b.

No findings were identified.

Findings

==1R20 Outage Activities

==

.1

a.

Refueling Outage Activities The inspectors reviewed the Safe Shutdown Management Plan (SSMP) and contingency plans for the Unit 1 refueling outage (RFO), conducted May 8 - June 9, 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.

Inspection Scope

• Licensee configuration management, including maintenance of defense-in-depth commensurate with the SSMP 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, and accounting for instrument error;

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

• 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;

• 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.

No findings were identified.

Findings

.2 a.

Other Outage Activities The inspectors evaluated outage activities for three unscheduled outages between June 9 and June 15, 2011. The forced outage designated Q1F62 began on June 9, 2011, at 10:17 p.m., when operators manually tripped the Unit 1 main turbine because control valve 4 was not operating properly. Control valve 4 was indicating 3 percent open while all other control valves were indicating 9 percent open. The reactor remained in Mode 1 during the forced outage and the turbine was returned to service at 07:43 a.m. on June 10, 2011, for turbine overspeed testing following troubleshooting of the valve and hydraulics. The turbine was placed online to perform overspeed testing while final preparations for repair of control valve 4 were completed.

Inspection Scope At 10:17 a.m. on June 11, 2011, forced outage Q1F63 began when the Unit 1 main turbine was again tripped to allow planned repair of control valve 4 and emergent repairs to a steam leak near control valves 1 and 2. The steam leak was from a pressure sensing line installed during the refueling outage to monitor turbine efficiency.

Two connections to the steam piping were cut and capped to repair the steam leak.

The reactor remained in Mode 1 during the forced outage and the turbine was returned to service at 1:00 p.m. on June 12, 2011.

At 05:10 a.m. on June 13, 2011, operators scrammed the reactor from 34 percent power and tripped the main turbine to isolate the steam leak following report of a large steam leak in the vicinity of control valve 1. The associated forced outage was designated Q1F64. Shortly thereafter, the licensee decided to take the unit to cold shutdown during investigation and repair of the steam leak. Repairs were completed, and Q1F64 ended on June 15, 2011, at 11:10 a.m., when the generator was synchronized to the grid.

The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedules. The inspectors observed cooldown for Q1F64, and outage equipment configuration and risk management, electrical lineups, control and monitoring of decay heat removal, control of containment activities, startup and heatup activities, and identification and resolution of problems associated with the outage during all of the forced outage periods. Additional discussion of the manual scram that began Q1F64 is provided in Section 4OA3 of this report.

This inspection constituted three other outage samples as defined in IP 71111.20-05.

b.

No findings were identified.

Findings

==1R22 Surveillance Testing

==

.1

a.

Surveillance Testing 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 Inspection Scope function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• QCOS 0500-02: Manual Scram Instrumentation Functional Test (Routine);

• QCOS 2900-04: Safe Shutdown Makeup Pump Reactor Vessel Injection Test At Cold Shutdown (Routine);

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

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

• QCTS 0600-09: RCIC Steam Exhaust Local Leak Rate Test (ISO Valve); and

• QCOS 6600-50: Unit 1 Division II Emergency Core Cooling System Automatic Actuation and Diesel Generator Auto-Start Surveillance (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 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 three routine surveillance testing sample(s), one reactor coolant system leak detection inspection sample(s), and two containment isolation valve sample(s) as defined in IP 71111.22, Sections -02 and -05.

b.

No findings were identified.

Findings

2RS5 Radiation Monitoring Instrumentation

This inspection constituted one complete sample as defined in IP 71124.05-05.

(71124.05)

.1 Inspection Planning

a.

(02.01)

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

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

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

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

The inspectors reviewed the area radiation monitor alarm setpoint values and setpoint bases as provided in the TS and the USFAR.

The inspectors reviewed effluent monitor alarm setpoint bases and the calculational methods provided in the offsite dose calculation manual.

b.

No findings were identified.

Findings

.2 Walkdowns and Observations

a.

(02.02)

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

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

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

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

The inspectors selected personnel contamination monitors, portal monitors, and small article monitors and evaluated whether the periodic source checks were performed in accordance with the manufacturers recommendations and licensee procedures.

b.

No findings were identified.

Findings

.3 Calibration and Testing Program (02.03)

a.

Process and Effluent Monitors

The inspectors selected effluent monitor instruments (such as gaseous and liquid) and evaluated whether channel calibration and functional tests were performed consistent with radiological effluent Technical Specifications/Offsite Dose Calculation Manual.

The inspectors assessed whether:

(a) the licensee calibrated its monitors with National Institute of Standards and Technology traceable sources;

(b) the primary calibrations adequately represented the plant nuclide mix;

(c) when secondary calibration sources were used, the sources were verified by the primary calibration; and

(d) the licensees channel calibrations encompassed the instruments alarm setpoints.

Inspection Scope The inspectors assessed whether the effluent monitor alarm setpoints were established as provided in the Offsite Dose Calculation Manual and station procedures.

For changes to effluent monitor setpoints, the inspectors evaluated the basis for changes to ensure that an adequate justification existed.

b.

No findings were identified.

Findings a.

Laboratory Instrumentation

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

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

b.

No findings were identified.

Findings a.

Whole Body Counter The inspectors reviewed the methods and sources used to perform whole body count functional checks before daily use of the instrument and assessed whether check sources were appropriate and align with the plants isotopic mix.

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

b.

No findings were identified.

Findings a.

Post-Accident Monitoring Instrumentation

Inspectors selected drywell high-range monitors and reviewed the calibration documentation since the last inspection.

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

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

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

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

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

b.

No findings were identified.

Findings a.

Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors

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

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

b.

No findings were identified.

Findings a.

Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors The inspectors reviewed calibration documentation for at least one of each type of instrument. For portable survey instruments and area radiation monitors, the inspectors reviewed detector measurement geometry and calibration methods and had the licensee demonstrate use of its instrument calibrator, as applicable. The inspectors conducted comparison of instrument readings versus an NRC survey instrument if problems were suspected.

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

b.

No findings were identified.

Findings a.

Instrument Calibrator

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

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

b.

No findings were identified.

Findings a.

Calibration and Check Sources

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

Inspection Scope b.

No findings were identified.

Findings

.4 Problem Identification and Resolution

a.

(02.04)

The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensee corrective action program.

The inspectors assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee that involve radiation monitoring instrumentation.

Inspection Scope b.

No findings were identified.

Findings

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1

a.

Reactor Coolant System Leakage The inspectors sampled licensee submittals for the RCS Leakage performance indicator for Quad Cities Unit 1 and for the period from the 2nd quarter 2010 through the 1st quarter 2011. To determine the accuracy of the Performance Indicator (PI) data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute 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 April 1, 2010, through March 31, 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.

Inspection Scope This inspection constituted two reactor coolant system leakage samples as defined in IP 71151-05.

b.

No findings were identified.

Findings

4OA2 Identification and Resolution of Problems

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection (71152)

.1 a.

Routine Review of Items Entered into the Corrective Action Program 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.

Inspection Scope 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.

No findings were identified.

Findings

.2 a.

Daily Corrective Action Program Reviews 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.

Inspection Scope 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.

No findings were identified. However, inspectors identified examples where the actions of plant personnel indicated breakdowns in power plant operating fundamentals that warranted additional management attention before the behaviors led to more significant events. Some issues, such as the trip of the RWCU pumps during cold scram time testing discussed in Section 1R13 of this report and the two issues discussed as in-depth Problem Identification & Resolution (PI&R) samples in this section of the report:

(1) the wrong unit error; and

(2) turbine control valve closure during cable replacement, indicate that the site is still experiencing problems with procedure use and compliance.

The additional insights discussed in the following examples indicate licensee corrective action efforts have not corrected weaknesses in the rigor site personnel apply in implementing error reduction tools such as questioning attitude and self-checking, user understanding of the technical basis for actions in procedures, preparation of users to respond when an unexpected response occurs, and recognition of risk associated with schedule changes. In addition to the findings and in-depth PI&R samples discussed in this report, some other examples that support the inspectors conclusions are:

Findings

• On May 23, 2011, inspectors observed a loss of communication event between the refuel bridge and the main control room during core alterations. The control room nuclear station operator (NSO) granted permission to the bridge operators via the communication link to perform a fuel move step moving a fuel bundle from the Unit 1 spent fuel pool to the Unit 1 reactor core. The procedure required activities performed by the refuel bridge to execute the performance of the step to be communicated to the main control room as information and a repeat back from the main control room was not required in order to continue execution of the step. At some point during the bridge transition from the pool to the over the core location, communication was lost. When the bridge was positioned over the correct core location, the bridge communicator notified the control room that the bundle was being inserted and began to insert the bundle. The NSO did not receive that transmission, but was monitoring the camera and saw that the bundle was being inserted. The NSO was unable to reach the refuel bridge on the open phone line and asked the unit supervisor to call the refuel bridge on the backup line.

Although the operators performed the actions required by the procedure, they did not perform the core alteration with a sufficiently conservative bias to overcome the process weakness. In this instance, one of the critical steps in this activity was the insertion of the bundle into the core. In the event of an unexpected response by the nuclear instrumentation, the NSO monitoring the instrumentation would be expected to stop the core alteration through this communication link.

Failure to ensure that the communication line was operating immediately before beginning to put the bundle into the core constituted a missed opportunity to identify the failure and demonstrated a lack of sensitivity to the critical role performed by the NSO in the control room. The inspectors concern was entered into the licensees CAP as IR 1219643. As a corrective action, the licensee revised QCFHP 0100-01, Master Refueling Procedure, to require permission from the main control room prior to insertion of a fuel bundle into the reactor core.

This revision provided a step to verify communications with the main control room and ensure the NSO was alerted to the manipulation prior to initiating any core alteration that would affect reactivity.

• On May 12, 2011, the licensee identified water dripping from reactor building ventilation ductwork over Unit 2 safety-related equipment in IR 1215236.

The water was dripping about five drops per minute onto the floor and running to a nearby floor drain. Radiation Protection was asked to determine if the water met the threshold for a contaminated spill and the survey indicated it did not meet the threshold to be treated as contaminated. The licensee initially evaluated this as condensation due to high humidity and high temperature environmental conditions, and closed the issue report to information provided. On May 19, 2011, inspectors, following up on the initial water drip, identified that the leak was still there even though the high humidity and high temperature conditions no longer existed. In addition, another leak was identified in a separate section of ductwork. Chemistry analyzed the water collected from the ductwork and indicated that the small quantities of Cobalt, Cesium and Tritium contained in the sample were consistent with reactor and fuel pool water.

The licensee wrote IR 1219291, and initial investigation determined that the spent fuel pool must have been allowed to overflow into the skimmer ductwork during refuel activities affecting pool level allowing some water to enter the ductwork. The staff concluded this was true even though no evidence could be found to corroborate this conclusion. After additional questions were raised by inspectors concerning the source and quantity of water and the licensees logic in determining that there was not an on-going source of in-leakage that could have detrimental effects on safety-related equipment, the licensee initiated action to install drain ports. The licensee drained about 5 gallons of water from the ductwork. Issue Report 1228633 was written after an expanded search criteria identified a time on May 11 that water may have entered the ductwork.

Followup checks of the ductwork revealed no more water, and actions were assigned to responsible groups to identify additional action to prevent overflow of water into the skimmer ductwork. Site personnel demonstrated a willingness to accept the quick response without establishing followup actions to validate assumptions and reluctance to pursue the complete characterization of the non-conforming condition until prompted by inspectors. Failure to promptly characterize issues and validate assumptions is a behavior that allows issues to linger and potentially have more severe consequences at a different time.

• On June 1, 2011, with the vessel in Mode 4 at approximately 850 psig, inspectors reviewing operating logs identified that the reactor pressure vessel in-service leak test portion of QCOS 0201-08, Reactor Vessel Class 1 and Associated Class 2 System Leak Test, was complete and the licensee was restoring reactor pressure to perform excess flow check valve (EFCV) testing using QCIS 0200-22. The inspectors did not find an expected log entry for limitations imposed by TS 3.4.8, Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown. The TS requires two RHR shutdown cooling subsystems to be operable in Mode 4, but is modified by a note that states this TS is not applicable during hydrostatic testing. Since the vessel pressure testing was complete, inspectors determined that TS 3.4.8 was applicable and since neither loop of RHR was operable because of high pressure isolation, the licensee was required to implement the required actions of TS 3.4.8 Condition A (two subsystems inoperable).

When inspectors raised the question, licensed operators responded that since they were still operating in the conditions established by the vessel pressure test procedure and the EFCV test was allowed to be performed concurrently, the exemption still applied even though they had completed the hydrostatic testing portion of the procedure. Inspectors pointed out the note did not cover other TS testing that required elevated reactor pressure to perform; since the hydrostatic testing was complete, the TS was applicable. Since the procedure established conditions that met the actions required by TS 3.4.8, Condition A, the operators were in non-compliance with licensee administrative procedures, but no violation of TS occurred. However, the conversation raised questions about whether the operators really understood the technical basis for the required actions in the procedure and in the operating license.

• On April 27, 2011, inspectors noted an activity on the work schedule that staged equipment for the impending Unit 1 outage in the Unit 2 reactor core isolation cooling/2B core spray corner room. Inspectors questioned the operating crews intentions regarding room walkdowns following movement of equipment to assess potential interference with local operation of equipment required for emergency procedure and Appendix R actions. Although the crew had not intended to perform any special walkdown, they decided to do so after discussion with inspectors and verified that the staged equipment did not interfere with required operator actions. On May 24, 2011, following completion of the work activity, a member of the site nuclear oversight group toured the room as a followup and determined that the addition and relocation of equipment could potentially impact operator action. He reported his concerns to the operating crew and documented the observation in IR 1220134.

Operators responded and determined that although actions could still be accomplished, some of the staged equipment needed to be moved to ensure that required Appendix R equipment remained accessible under all conditions.

Corrective actions included documenting the appropriate fire impairments and taking prompt action to rearrange the staged equipment appropriately. The failure of the site to effectively manage equipment staging and demobilization to prevent potential impact to emergency actions in areas that contained essential equipment is a breakdown in power plant management and control of plant status and the work control processes. The breakdown was further exacerbated by the failure to ensure appropriate monitoring was in place after the initial risk was identified by inspectors.

While the performance deficiencies associated with the examples discussed above were evaluated individually within the Reactor Oversight Process (ROP) and determined to not be more than minor, they did result in organizational challenges such as the diversion of resources from scheduled activities or suspension of in-progress work resulting in delay or rescheduling of work activities requiring emergent risk evaluation and mitigation.

.3 a.

Selected Issue Followup Inspection: Unit 2 Turbine Control Valve 1 Failed Closed During Maintenance Activity During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documented on May 15, 2011, that the Unit 2 turbine control valve 1 went closed during a work activity to replace a damaged electrical cable.

The work was being performed at about 62 percent during a control rod pattern adjustment power maneuver to minimize the operational risk associated with the work.

The cable was being replaced as part of a troubleshooting work activity under work order 1406720 for linear variable differential transformer (LVDT) 1 on control valve 1.

A dry run of the work activity was performed on Unit 1 prior to actually entering the high radiation area on Unit 2. The dry run was performed on the out-of-service Unit 1 control valves since they were readily accessible and in a low dose area in the shutdown condition. The work was performed by an individual who was familiar with the equipment, and the second person verifier was waived in accordance with site procedures in order to minimize dose.

Inspection Scope The individual verified that he had located the correct valve and junction box. He then removed the end of the pigtail from LVDT 1 and attached the new pigtail. He then moved to the junction box and removed the top connector, as he had on the Unit 1 dry run. When he examined the end of the connector, he realized that the pigtail had 8 pins and the one he was supposed to remove should have had 5 pins. He immediately restored the old pigtail as discussed in the pre-job brief and exited the area to report the error.

The cable he removed from the junction box provided power to the servo that positioned control valve 1. When power was lost to the servo, the valve control logic closed the valve in the suicide mode. In this mode, the control logic limits the valve closure rate to minimize the pressure change caused by valve closure; the logic must be reset to return the valve to normal control. Operators entered the appropriate procedures and monitored the changes in pressure, power, and control valve position. When the valve traveled closed, the plant responded as expected: reactor pressure increased by 16 psig to 996 psig, reactor power increased by 9 MWth to 2170 MWth, and the other three control valves opened slightly to control turbine generator load.

The licensees investigation determined that although the cables were correctly labeled on both ends, the arrangement of the connectors at the junction box on Unit 1 was different than on Unit 2. The worker did not remove the junction box connector for LVDT 1 as required by the work instructions, but instead removed the top connector because that was the LVDT 1 connector on Unit 1. He failed to verify that the top connector on the Unit 2 junction box was the LVDT 1 connector before removal.

The inspectors identified a performance deficiency in that the worker failed to follow procedural guidance, and this issue was within the licensees ability to control. The most significant consequence evaluated was the small transient that occurred when control valve 1 closed. Inspectors reviewed the performance deficiency, using the criteria in both Appendix B and Appendix E of IMC 0612, and determined that because the initial conditions of the work established controls that prevented the transient from having any safety consequence, the performance deficiency was minor in the ROP process.

The licensees corrective actions included replacement of the original cable and restoration of CV# 1 to normal control. The workers qualifications were removed pending remedial training.

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

b.

No findings were identified.

Findings

.4 During the Unit 1 refueling outage, Q1R21, in-vessel visual inspection, inspectors

identified two indications on jet pump 13/14 riser. The licensee examined the indications using the boiling water reactor vessel and internals project (BWRVIP) guidelines for flaw evaluation and determined that the flaw was indicative of inter-granular stress corrosion cracking. The inspection was subsequently expanded per BWRVIP guidelines to include all 10 risers on that recirculation loop with no other flaws identified. The inspectors reviewed the licensees flaw evaluation and concluded that the methodology used was consistent with the BWRVIP guidelines. The licensee took immediate actions to install auxiliary wedges and slip joint clamps as an interim measure to limit stress loads on the riser section to provide additional operating margin.

Selected Issue Followup Inspection: Jet Pump 13/14 Riser Flaw Indication Identified During In-vessel Visual Inspection This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

a.

No findings were identified.

Findings

.5 a.

Selected Issue Followup Inspection: Wrong Unit Error During Instrument Maintenance Surveillance Activity During a review of items entered in the licensees CAP, the inspectors recognized a corrective action item documenting a wrong unit error during instrument maintenance department surveillance testing in the main control room. Technicians performing a Unit 2 surveillance procedure presented a work package to the Unit 1 unit supervisor and then installed a test box on the wrong unit. This box bypassed one channel of the Unit 1 reactor protection trip logic and inserted a test signal on one channel of the Unit 2 reactor protection trip logic.

Inspection Scope 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 NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified on May 4, 2011, when instrument technicians caused a control room alarm on Unit 2 after receiving permission from the Unit 1 unit supervisor to perform the test on Unit 1. Inspectors determined that failure to follow the surveillance procedure as written resulted in performance of portions of a Unit 2 surveillance procedure on Unit 1 safety-related equipment and was a performance deficiency.

Discussion In the main control room, the technicians presented the impact statement to the Unit 1 unit supervisor for authorization to commence work and to have the unit supervisor sign the impact statement acknowledging the impact to the unit. The unit supervisor knew that the activity was not scheduled for Unit 1, but he had already received several calls during the shift to perform activities that had been scheduled for the previous night, so instead of questioning whether the activity was scheduled, he focused on what was required for it to proceed. Neither the IMD technicians nor the unit supervisor identified that the impact statement was clearly designated for Unit 2. The unit supervisor reviewed the impact statement, completed the necessary tracking paperwork, and authorized the surveillance to proceed. The unit supervisor did not review the impact statement with sufficient rigor to identify that the technicians were on the wrong unit even though Unit 2 was identified in four different places on the impact statement.

Four instrument maintenance department (IMD) technicians were scheduled to perform several surveillances during day shift on May 4, 2011. The crew of three technicians and a lead was briefed for all of the surveillance at the beginning of the shift, but after performing one of the surveillances, was redirected to perform a high priority Unit 1 surveillance that had been scheduled for the previous night shift, but was not completed as scheduled. After lunch, they picked up the originally scheduled surveillances, but did not perform another pre-job brief. Two of the technicians went to the main control room with the work package impact statement for MA-QC-741-223, Unit 2 Division 1 High Reactor Pressure RPS [reactor protection system] Master Trip Unit (MTU) Calibration and Functional Test, and a black and white copy of the procedure steps to be performed in the control room. The other technician and the lead took the work package to the cable spreading room to set up for the surveillance.

After receiving authorization to start work, the two technicians in the control room established communication with the technicians in the cable spreading room and installed the test box on the Unit 1 reactor protection system (RPS) channel in Panel 901-5, in spite of the fact that the step they signed off said it should be installed on Unit 2 RPS in Panel 902-5 (the 902-5 designator signifies electrical panel 5 in the Unit 2 main control room). When the technicians in the cable spreading room inserted the test signal into Unit 2, the trouble alarm sounded on Unit 2. The Unit 1 reactor operator noted the alarm and stopped the surveillance. The technicians backed out of the surveillance and restored all equipment to the normal status and wrote IR 1211933.

Analysis Inspectors determined that performing procedural action on the wrong unit would impact the Initiating Event Cornerstone objective of limiting the likelihood of upsetting plant stability and challenging critical safety functions during power operations. Specifically, the objective attributes of configuration control equipment performance were negatively impacted. Inspectors performed the SDP phase I screening using IMC 0609, 4, Table 4a, for transient initiators in the Initiating Events Cornerstone column and answered the question No. The issue was screened as Green or very low safety significance.

The licensees failure to follow procedure MA-QC-741-223 resulted in performance of portions of Unit 2 surveillance actions on Unit 1 safety-related equipment and was a performance deficiency. Inspectors determined that the issue sufficiently differed from IMC 0612, Appendix E examples for procedural errors in that multiple units were affected and the licensee actions involved programmatic breakdowns in the station work control and configuration control processes that were in place to ensure equipment readiness and operability while the unit is operating at power. The inspectors answered the more than minor screening questions of IMC 0612, Appendix B, Figure 2, Block 9, question 2.a, indicating the performance deficiency could be viewed as a precursor to a significant event; therefore, the finding was more-than-minor.

Inspectors concluded that the finding had a cross-cutting aspect in Human Performance-Work Practices. 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)). Communications between the two groups of technicians and between the technicians and operators was not complete and formal enough to prevent wrong unit/wrong panel errors. The technicians made a decision to forego the pre-job brief after the original schedule was disrupted. The technicians did not present the work package to the unit supervisor for review and the unit supervisor did not request it. During the authorization process, neither the technicians nor the unit supervisor identified that the impact statement was clearly designated for Unit 2.

Self-check and peer check techniques for both the technicians and the operators were insufficient to identify that individuals were on the wrong unit/wrong panels.

Enforcement Contrary to the above, individuals performing MA-QC-741-223 on May 4, 2011, did not follow the procedure as written and did in fact perform steps on the wrong unit.

Because this violation was determined to be of very low safety significance and the issue

Title 10 CFR 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.

was entered into the licensees corrective action program as IR1211933, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000254/2011003-02; 05000265/2011003-02, Wrong Unit Error During Surveillance).

Immediate actions included termination of the surveillance and restoration of the equipment to the correct lineup for plant conditions. Station management reinforced expectations for human performance tool use through human performance stand downs and tailgate meetings with the staff. Performance issues at the individual level were also addressed by station management.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1

a.

Unit 1 Manual Scram The inspectors reviewed the plants response to a manual reactor scram of Unit 1 on June 13, 2011. With the unit at 60 percent power during power ascension, a main steam system leak was identified downstream of turbine control valve 1. Operators reduced power to 34 percent and subsequently inserted the manual scram prior to tripping the main turbine in order to isolate the leak. The steam leak occurred at a recently repaired sensing line. Operators took action in accordance with station procedures and verified the leak was isolated following the turbine trip. The RPS actuation and expected containment isolation signals that followed the vessel water level transient were reported to the NRC in Event Notification 46951. No unmonitored release of radioactive steam occurred.

Inspection Scope 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.

No findings were identified.

Findings 4OA5

.1 Other Activities

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

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

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

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

(4) an assessment of the thoroughness of the walkdowns and inspections of important equipment needed to mitigate fire and flood events, which were performed by (Closed) NRC Temporary Instruction 2515/183, Followup to the Fukushima Daiichi Nuclear Station Fuel Damage Event the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

Inspection Report 05000254/2011010; 05000265/2011010 (ML111320357) documented detailed results of this inspection activity. Following issuance of the report, the inspectors conducted detailed followup on selected issues.

.2 On May 18, 2011, the inspectors completed a review of the licensees severe accident

management guidelines (SAMGs), implemented as a voluntary industry initiative in the 1990s, to determine:

(1) whether the SAMGs were available and updated;

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

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

(4) licensee personnels familiarity with SAMG implementation.

(Closed) NRC Temporary Instruction 2515/184, Availability and Readiness Inspection of Severe Accident Management Guidelines

The results of this review were provided to the NRC task force chartered by the Executive Director for Operations to conduct a near-term evaluation of the need for agency actions following the Fukushima Daiichi fuel damage event in Japan.

Plant-specific results for Quad Cities Nuclear Plant Units 1 and 2 were provided as an to a Memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and Regional Support, dated June 1, 2011, (ML111520396).

.3 a.

(Closed) Temporary Instruction 2515/179, Verification of Licensee Responses to NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

The inspectors confirmed that the licensee has reported the initial inventories of sealed sources pursuant to 10 CFR 20.2207 and verified that the National Source Tracking System database correctly reflects the Category 1 and 2 sealed sources in custody of the licensee. Inspectors interviewed personnel and performed the following:

Inspection Scope

• Reviewed the licensees source inventory;

• Verified the presence of any Category 1 or 2 sources;

• Reviewed procedures for and evaluated the effectiveness of storage and handling of sources;

• Reviewed documents involving transactions of sources; and

• Reviewed adequacy of licensee maintenance, posting, and labeling of nationally tracked sources.

b.

No findings were identified, Findings 4OA6

.1 Management Meetings

On July 6, 2011, the inspectors presented the inspection results to Mr. S. Darin, 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 exits were conducted for:

Interim Exit Meetings

• Radiation Monitoring Instrumentation and Temporary Instruction 2515/179, Verification of Licensee Responses to NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System, with Mr. M. Prospero, Plant Manager, on April 22, 2011.

• The results of the in-service inspection with Mr. M. Prospero, Plant Manager, on May 13, 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

T. Hanley, Site Vice President

Licensee

M. Prospero, Plant Manager

D. Barker, Operations Director

W. Beck, Regulatory Assurance Manager

D. Collins, Radiation Protection Manager

S. Darin, Engineering Director

J. Garrity, Work Control Director

K. Moser, Training Director

P. Summers, Maintenance Director

Nuclear Regulatory Commission

M. Ring, Chief, Reactor Projects Branch 1

Illinois Emergency Management Agency (IEMA)

C. Settles, IEMA

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

50-254/2011003-01 NCV

RWCU Pumps Tripped on Low Flow

Opened

(Section 1R13.1)

50-254/2011003-02; NCV

Wrong Limit Error During Surveillance 50-265/2011003-02

(Section 4OA2.5)

50-254/2011003-01 NCV

RWCU Pumps Tripped on Low Flow

Closed

(Section 1R13.1)

50-254/2011003-02; NCV

Wrong Limit Error During Surveillance 50-265/2011003-02

(Section 4OA2.5)

2515/183

TI

Followup to the Fukushima Daiichi Nuclear

Station Fuel Damage Event (Section 4OA5.1)

2515/184

TI

Availability and Readiness Inspection of Severe

Accident Management Guidelines (Section 4OA5.2)

2515/179

TI

Verification of Licensee Responses to NRC

Requirement for Inventories of Materials Tracked in

the National Source Tracking System Pursuant to

Title 10, Code of Federal Regulations, Part 20.2207

(10 CFR 20.2207) (Section 4OA5.3)