IR 05000454/2011003

IR 05000454-11-003, 05000455-11-003; 04/01/2011-06/30/2011; Byron Station, Units 1 & 2; Operability Evaluations

ML11209C336
Person / Time
Site:	Byron
Issue date:	07/28/2011
From:	Eric Duncan Region 3 Branch 3
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-11-003
Download: ML11209C336 (41)

Text

July 28, 2011

SUBJECT:

BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000454/2011003; 05000455/2011003

Dear Mr. Pacilio:

On June 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Byron Station, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on July 14, 2011, with Mr. T. Tulon 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, one NRC-identified finding of very low safety significance (Green) was identified. The finding was determined to be a violation of NRC requirements. However, because of its very low safety significance, and because the issue was entered into your corrective action program, the NRC is treating this violation as a non-cited violation (NCV) in accordance with Section 2.3.2 of the NRC Enforcement Policy. Additionally, a licensee-identified violation is listed in Section 4OA7 of this report.

If you contest the subject or severity of this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Byron Station. In addition, if you disagree with the characterization of 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 Inspectors at Byron 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/

Eric R. Duncan, Chief Branch 3 Division of Reactor Projects

Docket Nos. 50-454; 50-455 License Nos. NPF-37; NPF-66

Enclosure:

Inspection Report 05000454/2011003; 05000455/2011003 w/Attachment: Supplemental Information

REGION III==

Docket Nos:

05000454; 05000455 License Nos:

NPF-37; NPF-66 Report No:

05000454/2011003; 05000455/2011003 Licensee:

Exelon Generation Company, LLC Facility:

Byron Station, Units 1 and 2 Location:

Byron, IL Dates:

April 01, 2011, through June 30, 2011 Inspectors:

B. Bartlett, Senior Resident Inspector

J. Robbins, Resident Inspector

N. Feliz-Adorno, Reactor Engineer

V. Meghani, Reactor Engineer

J. Neurauter, Senior Reactor Inspector

A. Shaikh, Reactor Inspector C. Thompson, Resident Inspector, Illinois Department of Emergency Management

Approved by:

E. Duncan, Chief Branch 3 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000454/2011003, 05000455/2011003; 04/01/2011-06/30/2011; Byron Station, Units 1 & 2;

Operability Evaluations.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding and an associated non-cited violation (NCV) was identified by the inspectors. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process (SDP). Assigned cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas. 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 finding was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Protection Against External Events and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as having very low safety significance because it was a design deficiency confirmed not to result in a loss of operability or functionality. The inspectors determined that there was no cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency. (Section 1R15.1.b(1))

. The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when licensee personnel failed to analyze whether the design of the auxiliary feedwater system ensured that air entrained into the system following a postulated seismic or tornado event did not prevent the system from performing its safety function.

Specifically, licensee personnel failed to evaluate the failure of non-seismically qualified condensate storage tank suction piping during an earthquake or tornado that would cause the operating auxiliary feedwater pumps to draw air from the break location, potentially air-binding the pumps. The licensee entered this issue into their corrective action program to determine the required changes to the design of the system and performed an operability evaluation.

B.

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

REPORT DETAILS

Unit 1 was in a refueling outage at the beginning of the inspection period and returned to service on April 24, 2011. Unit 1 operated at or near full power for the remainder of the inspection period.

Summary of Plant Status

Unit 2 operated at or near full power for most of the inspection period. On May 21, 2011, the unit was shut down to replace a leaking pressurizer safety relief valve. The unit was returned to service on May 26, 2011 and operated at or near full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

==1R01 Adverse Weather Protection

==

.1

a.

Readiness of Offsite and Alternate AC 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.

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

Documents reviewed are listed in the Attachment.

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. 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 CAP in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant systems:

• Auxiliary Building Ventilation System; and

• Unit Auxiliary, Station Auxiliary, and Main Power Transformers.

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

b.

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 2 Essential Service Water System (SX) During Testing of the Train A and Train B Cross-Tie Valve 2SX033;

• Unit 2 Train B Safety Injection (SI) During Planned Maintenance on Valve 2SI8821A;

• Unit 2 Train B Residual Heat Removal (RH) while Unit 2 Train A RH was Out-of-Service for Maintenance; and

• Unit 1 Train B Containment Spray (CS) while Unit 1 Train A CS was Out-of-Service for Maintenance.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work orders, 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

.

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

• Unit 1 Train B Diesel Generator and Day Tank Room (Fire Zones 9.1-1 and 9.4-1);

• Unit 1 Division 12 ESF Switchgear Room (Fire Zone 5.1-1);

• Unit 2 Division 22 ESF Switchgear Room (Fire Zone 5.1-2); and

• Unit 2 Train A Diesel Fuel Oil Storage Tank Room (10.2-2).

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, 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.

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

b.

No findings were identified.

Findings

==1R06 Flooding

==

.1

a.

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

Inspection Scope

• Unit 1 and Unit 2 Diesel Generator Rooms;

• Unit 1 and Unit 2 Diesel Generator Fuel Oil Storage Tank Rooms;

• Unit 1 and Unit 2 Auxiliary Feedwater Pump Rooms and General Area;

• Unit 1 and Unit 2 Main Steam Isolation Valve Rooms; and

• Ultimate Heat Sink Cooling Tower Switchgear Rooms.

This inspection constituted five internal flooding samples as defined in IP 71111.06-05.

b.

No findings were identified.

Findings

1R08 Inservice Inspection Activities

From March 16 to April 26, 2011, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the Unit 1 reactor coolant system, steam generator tubes, emergency feedwater systems, risk significant piping and components and containment systems.

(71111.08P)

The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4, and

==1R08.5 below constitute one inspection sample as defined in IP 71111.08-05.

==

.1 a.

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

Inspection Scope

• Ultrasonic examination of weld 1RC21AA-8 on the 8 reactor coolant loop line A;

• Ultrasonic examination on the pressurizer surge line nozzle weld overlay PN-01-F1S;

• Bare metal visual examination of the 78 upper head penetrations;

• Ultrasonic examination of the 78 upper head penetrations;

• Liquid Penetrant examination of upper head penetrations 31, 43, 64, and 76; and

• Ultrasonic examination of the reactor coolant system hot leg and cold leg following implementation of the Mechanical Stress Improvement Process.

The inspectors reviewed the following examination records with relevant and/or recordable conditions and/or indications identified by the licensee to determine if acceptance of these indications for continued service was in accordance with the ASME Code Section XI or an NRC-approved alternative:

• Report No. B1R16-PT001, Surface examination on RH heat exchanger to support skirt weld 1RH-02-AB-RHES-01; The inspectors reviewed the following pressure boundary welds completed for risk-significant Unit 1 systems to determine if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by the construction code, ASME Section XI Code and NRC approved Code Cases. Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of the ASME Code Section IX.

• Weld Fabrication During Replacement of SI Check Valve 1SI8819D and 1SI8819A; and

• Weld Fabrication During Replacement of SI Valve 1SI8900D.

b.

No findings were identified.

Findings

.2 a.

Reactor Pressure Vessel Upper Head Penetration Inspection Activities For the Unit 1 reactor pressure vessel upper head, a volumetric (ultrasonic examination)and bare metal visual examination on all 78 upper head penetrations was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

Inspection Scope The inspectors observed and reviewed records of the bare metal visual examination conducted on the Unit 1 reactor vessel head at penetrations 31, 43, 64, and 76 to determine if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed that:

• the required visual examination scope/coverage was achieved and limitations (if applicable were recorded) in accordance with the licensee procedures;

• the licensee criteria for visual examination quality and instructions for resolving interference and masking issues were adequate; and

• if indications of potential through-wall leakage were identified, the licensee entered the condition into the corrective action system and implemented appropriate corrective actions.

The inspectors observed and reviewed records of the volumetric (ultrasonic)examinations conducted on the Unit 1 reactor vessel upper head at penetrations 31, 43, 64, and 76 to determine if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed that:

• the required examination scope (volumetric and surface coverage) was achieved and limitations (if applicable were recorded) in accordance with the licensee procedures;

• the ultrasonic examination equipment and procedures used were demonstrated by blind demonstration testing;

• if indications or defects were identified, the licensee documented the conditions in examination reports and/or entered this condition into the corrective action system and implemented appropriate corrective actions; and

• if indications were accepted for continued service the licensee evaluation and acceptance criteria were in accordance with the ASME Section XI Code, 10 CFR 50.55a(g)(6)(ii)(D) or an NRC-approved alternative.

The inspectors observed and reviewed records of welded repairs on the upper head penetrations 31, 43, 64, and 76 completed during the current outage to determine if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by the construction Code, NRC approved Code Case, NRC approved Code relief request or 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(s) used were qualified in accordance with the Construction Code and the ASME Code Section IX requirements.

b.

No findings were identified.

Findings

.3 a.

Boric Acid Corrosion Control On March 15, 2011, the inspectors observed the licensee staff performing visual examinations of the Unit 1 reactor coolant and emergency core cooling systems within containment to determine if these visual examinations focused on locations where boric acid leaks could cause degradation of safety-significant components.

Inspection Scope The inspectors reviewed the following licensee evaluations of reactor coolant system components with boric acid deposits to determine if degraded components were documented in the corrective action system. The inspectors also evaluated corrective actions for any degraded reactor coolant system components to determine if they met the ASME Section XI Code.

• ER-AP-331-1002, Attachment 2, Active Leakage Discovered Unit 1 Filter Valve Aisle; and

• ER-AP-331-1002, Attachment 2, Boron Leak at Valve 1RH031.

The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

• IR 1107864, 1SI8923A Has Packing that Looks Extruded;

• IR 1067371, Boron Leak at Valve 1RH031; and

• IR 1163585, Dry Boron on Valve 1SI8814 Packing and Body to Bonnet Area.

b.

No findings were identified.

Findings

.4 a.

Steam Generator Tube Inspection Activities The NRC inspectors observed acquisition of eddy current testing (ET) data, interviewed ET data analysts, and reviewed documentation related to the Steam Generator (SG) ISI program to determine if:

Inspection Scope

• In-Situ SG tube pressure testing screening criteria used were consistent with those identified in the Electric Power Research Institute (EPRI) TR-107620, Steam Generator In-Situ Pressure Test Guidelines and that these criteria were properly applied to screen degraded SG tubes for in-situ pressure testing;

• the numbers and sizes of SG tube flaws/degradation identified was bound by the licensees previous outage Operational Assessment predictions;

• the SG tube ET examination scope and expansion criteria were sufficient to meet the TSs, and the EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• the SG tube ET examination scope included potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to these SG tubes;

• the licensee identified new tube degradation mechanisms and implemented adequate extent of condition inspection scope and repairs for the new tube degradation mechanism;

• the licensee implemented repair methods which were consistent with the repair processes allowed in the plant TS requirements and to determine if qualified depth sizing methods were applied to degraded tubes accepted for continued service;

• the licensee implemented an inappropriate plug on detection tube repair threshold (e.g. no attempt at sizing of flaws to confirm tube integrity);

• the licensee primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons-per-day or the detection threshold during the previous operating cycle;

• the ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI 1003138, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 6;

• the licensee performed secondary side SG inspections for location and removal of foreign materials; and

• inaccessible foreign objects were left within the secondary side of the SGs, and if so, that the licensee implemented evaluations, which included the effects of foreign object migration and/or tube fretting damage.

The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute.

b.

No findings were identified.

Findings

.5 a.

Identification and Resolution of Problems The inspectors performed a review of ISI/SG 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/SG 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.

b.

No findings were identified.

Findings

==1R11 Licensed Operator Requalification Program

==

.1

Resident Inspector Quarterly Review a.

(71111.11Q)

On May 3, 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. Documents reviewed are listed in the Attachment.

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

• Pressurizer Safety Valve 2A Leak By that Resulted in a Maintenance Outage to Replace the Valve; and

• Unit 1 and Unit 2 Process Radiation Monitor 11J Multiple Spurious Alarms.

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.

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

• Unit 2 Train A RH Out of Service during a Power Range Drawer Calibration and with Degraded Miscellaneous Electrical Equipment Room Ventilation;

• Unit 2A Circulating Water (CW) Box Out of Service with CW Makeup Pump Full Flow Recirculation Out of Service and with Elevated Temperature on the 2A Heater Drain Pump;

• Risk Management with Unit 1 in Extended Refueling Outage and Operations Crew Shortage Due to Training Requirements; and

• Work Week Schedule for June 13, 2011 including Unit 2 SI Pump and SX Valve Work.

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 four samples as defined in IP 71111.13-05.

b.

No findings were identified.

Findings

==1R15 Operability Evaluations

==

.1

a.

Operability Evaluations The inspectors reviewed the following issues:

Inspection Scope

• Power Range Detector Operability due to an Unexpected Alarm during Power Ascension;

• Damaged Vent Screens on Dry Fuel Storage Casks;

• Replacement of Feedwater Venturi Instrumentation with Leading Edge Flow Meter Instruments for On-line Calorimetric Calculations;

• Auxiliary Feedwater Pump Suction Concerns, EC 384067, OpEval 11-007;

• Revised Feedwater Venturi Discharge Coefficients for Process Computer Unit 1 and Unit 2; and

• Unit 1 Lower Plenum Flow Anomaly following Reactor Coolant Pump Replacement.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and the 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 sample 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

.

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

b.

(1) Findings Failure to Ensure that the Design of the Auxiliary Feedwater Suction Piping Was Adequate to Prevent Air Entrainment Following a Seismic or Tornado Event

Introduction:

A finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified by the inspectors when licensee personnel failed to analyze whether the design of the auxiliary feedwater (AF) system ensured that air entrained into the system following a seismic or tornado event did not prevent the system from performing its safety function.

Description To prevent air binding of the auxiliary feedwater pumps, switchover from the condensate storage tank supply to the essential service water system occurs when low pressure is detected on the suction side. Pressure switches are installed on all four auxiliary feedwater pumps. The switches function to:

1) alarm low AF pump suction pressure in the main control room, 2) switch the AF pump suction source from the CST to the essential service water system, and 3) trip the respective AF pump on low suction pressure to prevent damage to the pump.

The function of the AF system is to provide adequate cooling water to the steam generators during certain abnormal or accident events. The AF pumps are normally aligned to take suction from the condensate storage tank (CST).

Section 10.D.3.4 for the UFSAR, NRC Recommendation GL-4, stated:

Switchover from the CST to the SX system is automatically accomplished on low pressure (18.1 pound per square inch absolute (psia)) in the suction pipe to the AF pumps. The AF pumps will trip when the low-low pressure setpoint of 16.5 psia for longer than 2.5 seconds is reached.

The inspectors identified a scenario in which the AF switchover setpoint and pump trip logic used to prevent air binding had not been previously evaluated and was questionable. Specifically, the inspectors identified that if the non-seismically qualified portion of the CST suction piping catastrophically failed due to a tornado or seismic event, the AF suction pressure would likely decrease below the low pressure (suction switchover) and low-low pressure (pump trip) setpoints. The inspectors determined the pumps would remain running for 2.5 seconds with a flow velocity of about 11 feet per second and that this would potentially result in air being entrained into the AF pumps before the pumps tripped on low-low pressure. Then, as the switchover valves opened, the pump suction pressure would increase to 17 psia, the pump restart setpoint.

However, because the motor-driven AF pump can accelerate to full speed in about 1 second, this pump start could result in suction pressure fluctuations causing pressure to decrease below the low-low pressure setpoint (pump trip) and then increase above the pump restart setpoint. In addition, as suction pressure decreases, the check valve in the seismically-qualified portion of the piping from the CST may open resulting in more air being introduced into the system. At some point, the switchover valves would open sufficiently to support continuous pump operation and maintain the suction piping pressurized such that the CST check valve remained closed. The licensee indicated that the pumps were expected to trip and restart up to four times on a complete loss of CST head.

The licensee captured the inspectors concerns in their CAP as IR 1202766, and performed an operability evaluation of the AF suction piping from the CST due to an impact from a seismic event or a tornado missile. The licensees evaluation addressed the piping in the turbine and auxiliary buildings as well as the buried piping from the CST to the turbine building. The evaluation concluded that the piping was operable, but non-conforming. Specifically, the evaluation concluded that the piping would remain operable under a design basis seismic event and would not be adversely affected by the failure of other adjacent piping, equipment, or structures. The evaluation also concluded that the piping location and the surrounding structure, including concrete floors and walls, provided adequate protection from a potential tornado missile impact. The corrective actions that were being considered by the licensee at the end of this inspection were to determine the required changes to the design basis documentation and/or plant hardware to restore the design basis of the AF system.

Analysis:

The inspectors determined that the failure to analyze whether air entrained into the AF system following a postulated seismic or tornado event would prevent the system from performing its safety function was contrary to 10 CFR Part 50, Appendix B, Criterion III, Design Control, and was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of Protection Against External Events and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the inspectors had reasonable doubt on the operability of the AF system because its design did not ensure that air would not enter the system following a seismic or tornado event. The failure of the AF design to ensure that the system will not experience significant air entrainment could result in air binding or degraded performance of the AF pumps and, thus, did not ensure the availability, reliability, and capability of the AF system.

The inspectors determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 3b for the Mitigating Systems Cornerstone. The finding screened as of very low safety significance (Green) because the finding involved a design or qualification deficiency that did not result in a loss of operability or functionality.

Specifically, the licensee concluded that the piping would remain operable during a design basis seismic event and was adequately protected from a tornado missile impact.

There was no cross-cutting aspect associated with this finding because it was not confirmed to reflect current performance due to the age of the performance deficiency.

Enforcement Contrary to the above, as of April 7, 2011, the licensee's design control measures failed to verify the adequacy of the AF design. Specifically, licensee personnel failed to ensure that air entrained into the AF system as a result of failed non-seismically qualified condensate storage tank suction piping following a postulated design basis seismic or tornado event would not prevent the AF system from performing its safety function, as required. As part of the licensees immediate corrective actions, an operability evaluation was performed that concluded the AF system was operable, but non-conforming. Because this violation was of very low safety significance and was entered into the licensees CAP as IR 1202766, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000454/2011003-01, NCV 05000455/2011003-01: Failure to Ensure that the Design of the AF Suction Piping Was Adequate to Prevent Air Entrainment Following a Seismic or Tornado Event)

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that design control measures shall provide for verifying or checking the adequacy of design.

==1R19 Post-Maintenance Testing

==

.1

a. Post-Maintenance Testing

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

Inspection Scope

• Unit 2 Train A Diesel Generator following Bearing Temperature Pressure Switch Replacement;

• Unit 2 Main Feedwater System Containment Isolation Valves Full Stroke Test;

• Unit 2 Control Rod Bank Overlap Testing following Card Replacement;

• Unit 2 Train A SX Pump Cubicle Coolers following Bearing Replacement; and

• Unit 2 Train Cross-Tie Valve 2SX033 following Replacement of Motor Starter and Thermal Overload Relay.

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 TS, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with PM tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety.

Documents reviewed are listed in the Attachment.

This inspection constituted five PM testing samples as defined in IP 71111.19-05.

b.

No findings were identified Findings

==1R20 Outage Activities

==

.1

a.

Refueling and Other Outage Activities-Crane and Heavy Lifts Inspection During the period from April 25, 2011 through May 27, 2011, the inspector performed a review of the licensees control of heavy loads program in accordance with the NRCs Operating Experience Sample (OpESS) FY 2007-03, Revision 2, Crane And Heavy Lift Inspection, Supplemental Guidance for IP 71111.20. Specifically, the inspector reviewed the licensees control of cranes and heavy loads including removal and installation of the reactor pressure vessel head during refueling operations. In addition, the inspector reviewed licensee design documentation completed and approved at the time of the inspection supporting the in-progress upgrade of the polar crane load handling system to single-failure-proof equivalency for reactor vessel head lifts.

Inspection Scope Guidelines for control of heavy loads detailed in industry initiative Nuclear Energy Institute (NEI) 08-05, Industry Initiative on Control of Heavy Loads, Revision 0, dated July 2008 was endorsed by the NRC in NRC Regulatory Issue Summary 2008-28, Endorsement of Nuclear Energy Institute Guidance for Reactor Vessel Head Heavy Load Lifts, dated December 1, 2008. The inspection included review of the following industry initiative actions:

• the licensees implementation of safe load paths, load handling procedures, and industry standards addressing the following topics: training of crane operators; use of special lifting devices; use of slings; inspection, testing, and maintenance of the polar crane; and the design of the polar crane;

• the licensees load drop analysis that bounded reactor vessel head lifts with respect to load weight, load height, and medium present under the load;

• the licensees design documentation, completed and approved at time of the inspection, supporting the in-progress upgrade of the polar crane load handling system to single-failure-proof equivalency for reactor vessel head lifts;

• the licensees management of the risk associated with maintenance involving movement of heavy loads; and

• the summary description related to the basis for conducting safe heavy load movements in the licensees final safety analysis report.

Documents reviewed during the inspection are listed in the Attachment. This inspection is considered part of the inspection activities under Unit 1 refueling outage activities listed below.

b.

No findings were identified.

Findings

.2 a.

Refueling Outage Activities - Unit 1 The inspectors had previously documented their review of the Outage Risk Management Plan and contingency plans for the Unit 1 refueling outage (RFO) in Inspection Report 05000454/2011002. The licensee completed their planned Refueling Outage and returned the unit to service on April 24, 2011. Documents reviewed during the inspection are listed in the Attachment.

Inspection Scope This inspection constituted one outage activity sample as defined in IP 71111.20-05.

b.

No findings were identified.

Findings

.3 a.

Maintenance Outage Activities - Unit 2 The inspectors reviewed the Outage Risk Management Plan and contingency plans for the Unit 2 maintenance outage (B2M05). The inspector confirmed 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. The maintenance outage began May 21, 2011, and the licensee spent nearly 5 days replacing the Unit 2 A Pressurizer Code Safety Relief Valve. The unit was returned to service on May 26, 2011. Documents reviewed during the inspection are listed in the

.

Inspection Scope This inspection constituted one outage activity sample 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 function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

Inspection Scope

• Unit 2 Train A Diesel Generator Relay Start Surveillance;

• Unit 2 Train B Diesel Generator Relay Start Surveillance;

• Unit 2 Train B Solid State Protection System Bi-Monthly Surveillance;

• Unit 2 Train A RH Valve 2RH610 ASME Surveillance; and

• Unit 1 Reactor Coolant System Seal Injection Flow Verification Monthly Surveillance.

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 were in accordance with TSs, the UFSAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

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

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

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

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, 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.

This inspection constituted four routine surveillance testing samples, and one inservice testing sample, as defined in IP 71111.22, Sections -02 and -05.

b.

No findings were identified.

Findings 1EP6 Drill Evaluation

.1

a.

Emergency Preparedness Drill Observation The inspectors evaluated the conduct of a routine licensee emergency drill on June 15, 2011, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Simulator Control Room and Technical Support Center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment.

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

b.

No findings were identified.

Findings

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1

a.

Unplanned Scrams Per 7000 Critical Hours The inspectors sampled licensee submittals for the Unplanned Transients Per 7000 Critical Hours Performance Indicator (PI) for Unit 1 and Unit 2 for the period from the Inspection Scope second quarter 2010 through the first quarter 2011. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC Integrated Inspection Reports for the period of April 2010 through March 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. Documents reviewed are listed in the Attachment.

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

b.

No findings were identified.

Findings

4OA2 Identification and Resolution of Problems

.1

a.

Routine Review of Identification and Resolution of Problems As 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 corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Some minor issues were entered into the licensees corrective action program as a result of the inspectors observations; however, they are not discussed in this report.

Inspection Scope This inspection was not considered to be an inspection sample as defined in IP 71152.

b.

No findings were identified.

Findings

.2 a.

Annual In-Depth Review Sample During a review of items entered in the licensees CAP, the inspectors questioned a determination by the licensee that one of the nuclear instrumentation (NI) overpower trip setpoints on Unit 1 was set at 109 percent instead of the expected 85 percent. At the end of the Unit 1 refueling outage, instrument technicians were resetting the NI trip setpoints from 85 percent to the normal full power value of 109 percent when they determined that Power Range Channel 1 (1NR-8041) was already set at 109 percent.

The channel had remained operable in accordance with TS 3.1, Table 3.3.1-1. The inspectors verified that the required channels of NI had remained operable and that the licensees Apparent Cause Evaluation (ACE) was performed in accordance with their corrective action program. The ACE determined that when the technician transferred Inspection Scope data to the calibration sheet that he accidently placed the as-found data in the as-left position. When the front line supervisor reviewed the data, he failed to identify the error.

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

b.

No findings were identified.

Findings

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

.1

(Closed) Licensee Event Report 05000454/2011-002 During the spring 2011 refueling outage, volumetric and surface examinations were performed on the reactor vessel head penetration (VHP) nozzles. Several flaws were identified for VHP Nozzles 64, 76, 31 and 43 that did not meet acceptance criteria and therefore had to be repaired prior to returning the head to service. Some of the flaws were considered to be within the reactor coolant system pressure boundary region; however no through-wall leakage was detected. The cause of the flaws was attributed to Primary Water Stress Corrosion Cracking (PWSCC). Therefore, in accordance with 10 CFR 50.55a(g)(6)(ii)(D)(5), the frequency of PWSCC inspections of the head penetration nozzles has been increased to every refueling outage for Byron Unit 1.

Byron Station Unit 1 Reactor Pressure Vessel Head Penetration Nozzle Weld Flaws Attributed to Primary Water Stress Corrosion Cracking.

The inspectors that were onsite conducting ISI during the spring 2011 refueling outage observed and reviewed the flaw repair process ensuring that the repairs were implemented in accordance with NRC-approved methods. The results of that inspection including the head repair activities are documented in Section 1R08, Inservice Inspection Activities (71111.08P), of this report.

The inspectors reviewed the Licensee Event Report (LER) and had no further questions.

In addition, the inspectors concluded the LER was completed in accordance with 10 CFR 50.73. Therefore, this LER is closed.

.2 (Closed) Licensee Event Report 05000455/2010-002

On February 3, 2010, a licensee engineer performing routine walkdowns of plant equipment determined that the supports for the containment chillers were not welded as required by design drawings. This had the potential to add stresses not previously accounted for to the safety-related SX piping during a postulated event. The licensee immediately declared the affected equipment inoperable and welded the equipment as required. The licensee also performed an extent of condition review and determined that no other equipment was missing the required support welds. The licensee performed an assessment of the consequences of the additional stresses due to the missing welds and pending the results of that assessment, this LER remained open.

Essential Service Water System Inoperable Due to Inadequate Seismic Restraint from Original Construction Error.

On March 15, 2011, the licensee submitted a letter to the NRC which withdrew LER 05000455/2010-002, following the completion of their analysis. The results showed that the SX piping would have been able to perform its design function and would have remained operable.

The NRC inspectors performed a review of the licensees extent of condition and forwarded the results of the analysis of the missing welds to regional personnel for a more detailed review. The NRC inspectors did not have any significant comments on the licensees results. This LER is closed.

.3 (Closed) Licensee Event Report 05000454/455-2011-003-00

In February 2011, the NRC questioned past evaluations relating to the AF drained section of piping that existed between two section valves in the essential SX system for Unit 1 and Unit 2. The voided section of piping is intentionally drained and monitored for leak-by to ensure that raw water from the SX system does not intrude into the AF system and challenge the integrity of the steam generator tubes, which is a fission product barrier.

Drained Sections of Piping in Auxiliary Feedwater Suction Lines Result on System Inoperability Due to Inadequate Technical Evaluation.

On March 29, 2011, results of a preliminary analysis indicated that the void fraction at the pump inlet would be in excess of the maximum void acceptance criteria.

Subsequently, the licensee filled the voided sections of piping and planned to conduct full scale testing to resolve questions regarding pump performance under this configuration.

As discussed in NRC Inspection Report 05000456/2011012; 05000457/2011012; 05000454/2011015; 05000455/2011015; Section 4OA5.1.7.b, the inspectors reviewed this LER and opened Unresolved Items05000456/2011012-01; 05000457/2011012-01; 05000454/2011015-01; 05000455/2011015-01. The NRC is currently reviewing the results obtained from full scale testing.

The inspectors reviewed the LER and concluded it was completed in accordance with 10 CFR 50.73. The technical issue will be tracked by the referenced Unresolved Items.

Therefore, this LER is closed.

These event follow-up reviews constituted three samples as defined in IP 71153-05.

4OA5

.1 Other Activities

(Closed) NRC Temporary Instruction 2515/183 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;

Followup to the Fukushima Daiichi Nuclear Station Fuel Damage Event 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 the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

Inspection Report 05000454/455-2011014 (ML111320288) documented detailed results of this inspection activity. Following issuance of the report, the inspectors conducted detailed follow-ups on selected issues.

.2 (Closed) NRC Temporary Instruction 2515/184

On May 27, 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.

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 Byron Station were provided as an Enclosure to a memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and Regional Support, dated June 1, 2011 (ML111520396).

4OA6

.1 Management Meetings

On July 14, 2011, the inspectors presented the inspection results to Mr. T. Tulon, 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

• The results of an inservice inspection with Mr. B. Adams on April 26, 2011;

• The results of a Refueling and Other Outage Activities - Crane and Heavy Lifts Inspection with Mr. T. Tulon on April 27, 2011.

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

4OA7 The following violation of very low safety significance (Green) was identified by

the licensee and is a violation of NRC requirements, which meets the criteria of Section 2.3.2 of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited violation.

Licensee-Identified Violations License Condition 2.C.(1) stated, in part, that the licensee is authorized to operate both units at reactor core power levels not to exceed 3586.6 megawatts thermal. Contrary to this, both units exceeded their license thermal power limits since original construction by approximately 0.5 percent. The licensee identified that the flow coefficient utilized in the reactor power calorimetric calculation was not conservative during a post-maintenance calibration of a new flow instrument. The finding was determined to have very low safety significance because it only involved the potential to affect the fuel barrier. The licensee entered this issue into the CAP as IR 1217236 and implemented the correct flow coefficients.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

T. Tulon, Site Vice President

Licensee

B. Youman, Operations Manager

Elmer Hernandez, Engineering Director

B. Spahr, Maintenance Director

D. Gudger, Regulatory Assurance Manager

C. Wilson, Nuclear Oversight

B. Barton, Radiation Protection Manager

R. Gayheart, Training Director

L. Askren, Security Director

A. Creamean, Chemistry Manager

Eric Duncan, Chief, Reactor Projects Branch 3

Nuclear Regulatory Commission

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

05000454/2011003-01

Opened

05000455/2011003-01 NCV Failure to Ensure that the Design of the AF Suction Piping was Adequate to Prevent Air Entrainment Following a Seismic or Tornado Event (Section 1R15.1.b(1))

05000454/2011002-02

Closed

LER Unit 1 Reactor Pressure Vessel Head Penetration Nozzle Weld Flaws Attributed to Primary Water Stress Corrosion Cracking (Section 40A3)

05000454/2011003-01;

05000455/2011003-01 NCV Failure to Ensure that the Design of the AF Suction Piping Was Adequate to Prevent Air Entrainment Following a Seismic or Tornado Event (Section 1R15.1.b(1))

05000454/2011-003-00;

05000455/2011-003-00

LER Drained Sections of Piping in Auxiliary Feedwater Suction Lines Result on System Inoperability Due to Inadequate Technical Evaluation

05000455/2010-002-00 LER Essential Service Water System Inoperable Due to Inadequate Seismic Restraint from Original Construction Error 2515/183 TI Followup to the Fukushima Daiichi Nuclear Station Fuel Damage Event 2515/184 TI Availability and Readiness Inspection of Severe Accident Management Guidelines (SAMGs)

None