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| issue date = 04/29/2013
| issue date = 04/29/2013
| title = IR 05000454-13-002 and 05000455-13-002; Exelon Generation Company, LLC; 01/01/2013 - 03/31/2013; Byron Station, Units 1 & 2, Identification and Resolution of Problems Other Activities
| title = IR 05000454-13-002 and 05000455-13-002; Exelon Generation Company, LLC; 01/01/2013 - 03/31/2013; Byron Station, Units 1 & 2, Identification and Resolution of Problems Other Activities
| author name = Duncan E R
| author name = Duncan E
| author affiliation = NRC/RGN-III/DRP/B3
| author affiliation = NRC/RGN-III/DRP/B3
| addressee name = Pacilio M J
| addressee name = Pacilio M
| addressee affiliation = Exelon Generation Co, LLC, Exelon Nuclear
| addressee affiliation = Exelon Generation Co, LLC, Exelon Nuclear
| docket = 05000454, 05000455
| docket = 05000454, 05000455
Line 14: Line 14:
| page count = 37
| page count = 37
}}
}}
See also: [[followed by::IR 05000454/2013002]]
See also: [[see also::IR 05000454/2013002]]


=Text=
=Text=
{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION REGION III 2443 WARRENVILLE ROAD, SUITE 210 LISLE, IL 60532-4352  April 29, 2013   Mr. Michael J. Pacilio Senior Vice President, Exelon Generation Company, LLC President and Chief Nuclear Officer (CNO), Exelon Nuclear 4300 Warrenville Road Warrenville, IL  60555 SUBJECT: BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000454/2013002; 05000455/2013002 Dear Mr. Pacilio: On March 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Byron Station, Units 1 and 2.  The enclosed inspection report documents the inspection results which were discussed on April 4, 2013, with Mr. B. Youman and other members of your staff. The inspection examined activities conducted under your license as they relate to safety and  
{{#Wiki_filter:UNITED STATES  
compliance with the Commission's rules and regulations and with the conditions of your license.  The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Two NRC-identified findings of very low safety significance (Green) were identified during this inspection.  One of these findings was determined to involve 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. If you contest 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 Nuclear Regulatory Commission, ATTN:  Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Byron Station.  If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Byron Station.  
NUCLEAR REGULATORY COMMISSION  
M. Pacilio    -2- 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 (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS).  ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). Sincerely,        /RA/  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 05000454/2013002 and 05000455/2013002    w/Attachment:  Supplemental Information cc w/encl: Distribution via ListServ   
REGION III  
Enclosure  U. S. NUCLEAR REGULATORY COMMISSION REGION III Docket Nos: 50-454; 50-455 License Nos: NPF-37; NPF-66 Report No: 05000454/2013002; 05000455/2013002 Licensee: Exelon Generation Company, LLC Facility: Byron Station, Units 1 and 2 Location: Byron, IL Dates: January 1 through March 31, 2013 Inspectors: B. Bartlett, Senior Resident Inspector  J. Robbins, Resident Inspector  J. Bozga, Reactor Inspector  V. Meyers, Health Physicist  V. Meghani, Reactor Inspector  T. Daun, Reactor Engineer  R. Ng, Project Engineer C. Thompson, Resident Inspector, Illinois Emergency  Management Agency  Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects           
2443 WARRENVILLE ROAD, SUITE 210  
Enclosure  TABLE OF CONTENTS SUMMARY OF FINDINGS ......................................................................................................... 1 REPORT DETAILS .................................................................................................................... 3 Summary of Plant Status ........................................................................................................ 3 1. REACTOR SAFETY .................................................................................................... 3 1R01 Adverse Weather Protection (71111.01) ............................................................ 3 1R04 Equipment Alignment (71111.04) ...................................................................... 4 1R05 Fire Protection (71111.05) ................................................................................. 4 1R06 Flooding (71111.06) .......................................................................................... 5 1R11 Licensed Operator Requalification Program (71111.11) .................................... 6 1R12 Maintenance Effectiveness (71111.12) .............................................................. 7 1R13  Maintenance Risk Assessments and Emergent Work Control (71111.13) ......... 8 1R15 Operability Evaluations (71111.15) .................................................................... 8 1R18 Plant Modifications (71111.18) .......................................................................... 9 1R19 Post-Maintenance Testing (71111.19) ..............................................................10 1R20 Outage Activities (71111.20) ............................................................................11 1R22 Surveillance Testing (71111.22) .......................................................................12 1EP6 Drill Evaluation (71114.06) ...............................................................................13 2. RADIATION SAFETY .................................................................................................14 2RS4 Occupational Dose Assessment (71124.04) .....................................................14 4. OTHER ACTIVITIES ...................................................................................................14 4OA1 Performance Indicator Verification (71151).......................................................14 4OA2 Identification and Resolution of Problems (71152)............................................16 4OA5    Other Activities .................................................................................................20 4OA6  Management Meetings .....................................................................................23 SUPPLEMENTAL INFORMATION ............................................................................................. 1 Key Points of Contact ............................................................................................................. 1 List of Items Opened, Closed, and Discussed ........................................................................ 2 List of Documents Reviewed .................................................................................................. 3 List of Acronymns Use ............................................................................................................ 7   
LISLE, IL 60532-4352  
1 Enclosure  SUMMARY OF FINDINGS Inspection Report (IR) 05000454/2013002 and 05000455/2013002; 01/01/2013 - 03/31/2013; Byron Station, Units 1 & 2; Identification and Resolution of Problems; Other Activities. This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors.  Based on the results of this inspection, two NRC-identified findings of very low safety significance (Green) were identified.  One of these findings had an associated Non-Cited Violation (NCV) of NRC regulations.  The significance of inspection findings is indicated by their color (Greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP) dated June 2, 2011.  Cross-cutting aspects are determined using IMC 0310, "Components Within the Cross-Cutting Areas," dated October 28, 2011.  All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy dated January 28, 2013.  The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process (ROP)," Revision 4. A. NRC-Identified and Self-Revealed Finding Cornerstone:  Mitigating Systems  Green.  The inspectors identified a finding of very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," when licensee personnel failed to properly evaluate the structural steel embedment plate which supported Safety Injection (SI) pipe supports 1SI06025V and 1SI06030S.  Specifically, the licensee failed to demonstrate compliance with the American Institute of Steel Construction (AISC) and Seismic Category I linear elastic requirements.  The
   
licensee entered this issue into their corrective action program (CAP) as Issue Report (IR) 1478188.  As part of their immediate corrective actions, the licensee performed an operability evaluation and concluded the structural steel embedment plate was operable, but nonconforming. The inspectors determined that the performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).  Specifically, the licensee failed to demonstrate compliance with AISC and Seismic Category I linear elastic requirements to ensure the structural steel embedment plate would maintain structural integrity when subjected to a design basis load.  The inspectors determined that because the finding did not result in a loss of operability or functionality, the finding was of very low safety significance (Green).  This finding did not have a cross-cutting aspect as it was not indicative of current performance.  (Section 4OA2.3)  Green.  The inspectors identified a finding of very low safety significance (Green) when licensee personnel failed to develop inspection lists that included all external flood protection features credited in current licensing bases (CLB) documents as specified in Nuclear Energy Institute (NEI) 12-07, "Guidelines for Performing Walkdowns of Plant Flood Protection Features."  Specifically, concrete flood barriers in the fuel handling building (FHB) that protected safety-related equipment in the auxiliary building and flood barriers for the spent fuel pool cooling pumps were not included in the licensee's 
April 29, 2013  
2 Enclosure  flooding inspection lists, although these passive components were a critical element of the licensee's flood mitigation strategy.  The licensee entered this issue into their CAP as IR 1466355.  Corrective actions included plans to perform an inspection of the NRC-identified features that were omitted from the inspection lists and an extent-of-condition review. The inspectors determined that the performance deficiency was more than minor because it was associated with the Protection Against External Factors (Flood Hazard) attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).  Because the finding did not involve the loss or degradation of equipment or function specifically
designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors), the finding was of very low safety
significance (Green).  This finding had a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area because licensee personnel failed to properly apply human error prevention techniques such as peer checking and proper documentation of activities [H.4(a)].  (Section 4OA5.2) B. Licensee-Identified Violations None.   
3 Enclosure  REPORT DETAILS Summary of Plant Status Unit 1 operated at or near full power throughout the inspection period.  Unit 2 operated at or near full power throughout most of the inspection period.  On March 20, 2013, at approximately 7:51 p.m., the Unit 2 reactor was manually tripped when the only available generator stator cooling water pump failed.  All equipment operated as expected with a few minor exceptions.  Unit 2 returned to full power operation on March 25, 2013, after the pump was repaired and returned to service. 1. REACTOR SAFETY Cornerstones:  Initiating Events, Mitigating Systems, Barrier Integrity and Emergency Preparedness 1R01 Adverse Weather Protection (71111.01) .1 External Flooding a. Inspection Scope  The inspectors evaluated the design, material condition, and procedures for coping with the design bases probable maximum flood.  The evaluation included a review to check for deviations from the descriptions provided in the Updated Final Safety Analysis Report (UFSAR) for features intended to mitigate the potential for flooding from external factors.  As part of this evaluation, the inspectors checked for obstructions that could prevent
Mr. Michael J. Pacilio  
draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined whether barriers required to mitigate flooding were in place and operable.  Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site which could inhibit site drainage during a probable maximum precipitation event or allow water ingress past a flood barrier.  The inspectors also walked down underground bunkers/manholes subject to flooding that contained multiple trains or multiple function risk-significant cables.  The inspectors also reviewed the abnormal operating procedure for mitigating the design bases flood to ensure it could be implemented as written.  Specific areas inspected included the Unit 1 emergency diesel generators, main steam tunnels, and the fuel handling building (FHB). This inspection constituted one external flooding sample as defined in Inspection Procedure (IP) 71111.01-05. b. Findings Findings identified during this inspection are documented in Section 4OA5, "Other Activities." 
Senior Vice President, Exelon Generation Company, LLC  
4 Enclosure  1R04 Equipment Alignment (71111.04) .1 Quarterly Partial System Walkdowns a. Inspection Scope The inspectors performed partial system walkdowns of the following risk-significant systems:  Unit Common Train 'A' Control Room Chiller with Train 'B' Control Room Chiller Out of Service for Maintenance;  Unit 2 Instrument Inverter 212 with Instrument Inverter 214 Out of Service for Maintenance; and  Unit 2 Train 'A' Essential Service Water (SX) with Unit 2 Train 'B' SX 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, the UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), issue reports (IRs), 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 function(s).  The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable.  The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies.  The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program (CAP) with the appropriate significance characterization.  Documents reviewed are listed in the Attachment. This inspection constituted three partial system walkdown samples as defined in IP 71111.04-05. b. Findings No findings were identified. 1R05 Fire Protection (71111.05) .1 Routine Resident Inspector Tours (71111.05Q) a. Inspection Scope The inspectors conducted fire protection walkdowns which were focused on the availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas: 
President and Chief Nuclear Officer (CNO), Exelon Nuclear  
5 Enclosure  Division 11 Miscellaneous Electrical Equipment and Battery Room Fire Area 5.6-1;  Division 21 Miscellaneous Electrical Equipment and Battery Room Fire
4300 Warrenville Road  
Area 5.6-2;  Division 12 Miscellaneous Electrical Equipment and Battery Room Fire
Warrenville, IL  60555  
Area 5.4-1; and  Division 22 Miscellaneous Electrical Equipment and Battery Room Fire          Area 5.4-2. 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 licensee's fire plan.  The
SUBJECT:  
inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's 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 plant's 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 licensee's CAP.  This inspection constituted four quarterly fire protection inspection samples as defined in IP 71111.05-05. b. Findings No findings were identified 1R06 Flooding (71111.06) .1 Internal Flooding a. Inspection Scope The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events.  The inspectors reviewed flood analyses and design documents,
BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION  
including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments.  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
REPORT 05000454/2013002; 05000455/2013002  
circulating water systems.  The inspectors also reviewed the licensee's corrective action documents with respect to past flood-related items identified in the CAP 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 
Dear Mr. Pacilio:  
6 Enclosure  sumps were clear of debris and were operable, and that the licensee complied with existing commitments:  Unit 1 and Unit 2 SX Pump Rooms Documents reviewed are listed in the Attachment.  This inspection constituted one internal flooding sample as defined in IP 71111.06-05. b. Findings No findings were identified.  1R11 Licensed Operator Requalification Program (71111.11) .1 Resident Inspector Quarterly Review (71111.11Q) a. Inspection Scope On January 31, 2013, the inspectors observed a crew of licensed operators in the plant simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures.  The inspectors evaluated the following areas:  licensed operator performance;  crew's 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 crew's performance in these areas was compared to pre-established operator action expectations, procedural compliance, and successful critical task completion requirements.  Documents reviewed are listed in the Attachment. In addition, the inspectors observed licensed operator performance in the actual plant and the main control room during this calendar quarter. This inspection constituted one quarterly licensed operator requalification program sample as defined in IP 71111.11-05. b. Findings No findings were identified. 
On March 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated  
7 Enclosure  .2 Resident Inspector Quarterly Observation of Heightened Activity or Risk (71111.11Q) On March 12, 2013, the inspectors observed control room operators during the emergent failure of Unit 1 core exit thermocouple 50, and on March 22, 2013, the inspectors observed plant startup following the Unit 2 forced outage.  These were activities that required heightened awareness and was related to increased risk.  The inspectors evaluated the following areas:  licensed operator performance;  crew's clarity and formality of communications;  ability to take timely actions in the conservative direction;  prioritization, interpretation, and verification of annunciator alarms;  correct use and implementation of procedures;  control board manipulations;  oversight and direction from supervisors; and  ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications. The crew's performance in these areas was compared to pre-established operator action expectations, procedural compliance, and successful critical task completion requirements.  Documents reviewed are listed in the Attachment. This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11-05. b. Findings No findings were identified. 1R12 Maintenance Effectiveness (71111.12) .1 Routine Quarterly Evaluations (71111.12Q) a. Inspection Scope The inspectors evaluated degraded performance issues involving the following risk-significant systems:  Failure of Unit 1 Power Range Channel N43; and  Review of Maintenance Rule Assessment for the Period of January 2011 to June 2012. 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. 
inspection at your Byron Station, Units 1 and 2.  The enclosed inspection report documents the  
8 Enclosure  b. Findings No findings were identified. 1R13  Maintenance Risk Assessments and Emergent Work Control (71111.13) .1 Maintenance Risk Assessments and Emergent Work Control a. Inspection Scope The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:  Unit 2 Train 'A' Charging Pump Emergent Failure with the Unit 1 Train 'A' SX Pump Out of Service for Planned Maintenance;  Unit 1 Power Range Channel N43 Emergent Failure with Unit 2 Train 'B' SX Inoperable for Planned Maintenance; and  Unit 1 Train 'B' Auxiliary Feedwater Pump Work Window. 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 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. This inspection constituted three maintenance risk assessments and emergent work control samples as defined in IP 71111.13-05. b. Findings No findings were identified. 1R15 Operability Evaluations (71111.15) .1 Operability Evaluations a. Inspection Scope The inspectors reviewed the following issues:  Unit 1 Division 111 Battery Racks Support Questions;  Capacity of Pressurizer Power Operated Relief Valve (PORV) Air Accumulators During Natural Circulation Cooldown; 
inspection results which were discussed on April 4, 2013, with Mr. B. Youman and other  
9 Enclosure  Operation of SX Pump with Single Cubical Cooler; and  Unit 1 Power Range Channel N43 TS 3.3.1.D Entry. The inspectors selected these potential operability issues based on the risk significance of the associated components and systems.  The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred.  The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensee's 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 Attachment. This inspection constituted four operability inspection samples as defined in IP 71111.15-05. b. Findings No findings were identified. 1R18 Plant Modifications (71111.18) .1 Plant Modifications a. Inspection Scope The inspectors reviewed the following modification:  Reactor Containment Fan Cooler (RCFC) Check Dampers Closure Spring Changes The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system.  The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems.  As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated.  Lastly, the inspectors discussed the plant
members of your staff.  
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 are listed in the Attachment. 
The inspection examined activities conducted under your license as they relate to safety and  
10 Enclosure  This inspection constituted one permanent plant modification sample as defined in IP 71111.18-05. b. Findings No findings were identified. 1R19 Post-Maintenance Testing (71111.19) .1 Post-Maintenance Testing a. Inspection Scope The inspectors reviewed the following post-maintenance testing activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:  Unit 1 Bus 144 Breaker 1442 Following Lockout Relay Replacement;  Unit 1 Train 'A' SX Cubical Coolers Following Repairs;  Unit 2 Instrument Inverter 214 Following Coil Replacement; and  Unit 2 Train 'B' Generator Stator Water Cooling System Pump Following Motor Replacement. These activities were selected based upon the structure, system, and component's (SSC'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
compliance with the Commissions rules and regulations and with the conditions of your license.   
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
The inspectors reviewed selected procedures and records, observed activities, and interviewed  
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 bases 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 into the CAP at the appropriate threshold and that the problems were being corrected commensurate with their importance to safety.  Documents reviewed are listed in the Attachment. This inspection constituted four post-maintenance testing samples as defined in IP 71111.19-05. b. Findings No findings were identified. 
personnel.  
11 Enclosure  1R20 Outage Activities (71111.20) .1 Unit 2 Forced Outage a. Inspection Scope On March 20, 2013, at 7:51 p.m., licensee personnel performed a manual trip of the Unit 2 reactor.  The reactor was manually tripped in accordance with site procedures when the only operating and available electrical generator stator cooling water pump
Two NRC-identified findings of very low safety significance (Green) were identified during this  
tripped unexpectedly.  The inspectors responded to the site and assessed the cause of the trip, performed follow-up inspection of minor equipment failures, and immediately communicated any observations to NRC management.  The inspectors reviewed outage equipment configuration and risk management, verified electrical lineups, monitored decay heat removal, observed reactor startup activities, and reviewed the identification and resolution of problems associated with the forced outage. All safety-related equipment operated as designed.  Some nonsafety-related equipment experienced minor malfunctions.  For example:  The 'B' reactor trip breaker closed indication light extinguished as expected, however the open indication light did not illuminate to indicate that the breaker was open.  An operator was dispatched and verified the breaker was open.  Subsequently, a burned out 'B' reactor trip breaker open indication light bulb was replaced.  The control rod in position M-12 (control bank D) had a general warning light flashing, although its associated rod bottom light was lit.  Following troubleshooting, a logic card was replaced in the control rod drive cabinet to address the issue.  Following the Unit 2 trip, light smoke was reported to be coming from the Unit 2 'A' main feedwater pump motor.  It was later determined that when the 2A main feedater pump was shut down that its associated motor heater automatically energized.  An abnormally large amount of dust had built up on the heater and when it energized the dust "burned off." The licensee addressed these issues and Unit 2 was restarted and synchronized to the electrical grid on March 22, 2013.  Documents reviewed are listed in the Attachment.  This inspection constituted one other outage sample as defined in IP 71111.20-05. b. Findings No findings were identified. .2 Unit 2 Refueling Outage a. Inspection Scope The inspectors reviewed the Outage Safety Plan and contingency plans for the Unit 2 refueling outage (RFO) that began on April 7, 2013, to confirm that the licensee had appropriately considered risk, industry operating experience, and previous site specific 
inspection.  One of these findings was determined to involve a violation of NRC requirements.   
12 Enclosure  problems in developing and implementing a plan that assured maintenance of defense in depth.  A complete list of accomplished inspection activities will be documented following completion of the Unit 2 RFO. This inspection constituted a partial RFO sample as defined in IP 71111.20-05. b. Findings No findings were identified. 1R22 Surveillance Testing (71111.22) .1 Surveillance Testing a. Inspection Scope The inspectors reviewed the test results for the following activities to determine whether
However, because of its very low safety significance, and because the issue was entered into  
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:  Unit 1 Train 'B' Containment Spray Pump Quarterly Surveillance;  Unit 1 Train 'A' Diesel Generator Operability Surveillance;  Unit 1 Train 'A' Solid State Protection System Surveillance;  Unit 2 K636 Engineered Safety Features (ESF) Relay Surveillance; and  Unit 2 K644 ESF Relay 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, demonstrate operational readiness, and consistent with the system design basis;  was plant equipment calibration correct, accurate, and properly documented;  were as left setpoints within required ranges; and was the calibration frequency in accordance with TSs, the UFSAR, plant procedures, and applicable commitments;  was measuring and test equipment calibration current;  was the test equipment used within the required range and accuracy and were applicable prerequisites described in the test procedures satisfied;  did test frequencies meet TS requirements to demonstrate operability and reliability;  were tests performed in accordance with the test procedures and other applicable procedures;  were jumpers and lifted leads controlled and restored where used;  were test data and results accurate, complete, within limits, and valid; 
your corrective action program, the NRC is treating this violation as a non-cited violation (NCV)  
13 Enclosure  was test equipment removed following testing;  where applicable for in-service testing activities, was testing performed in accordance with the applicable version of Section XI of the American Society of Mechanical Engineers (ASME) Code, and were reference values consistent with the system design basis;  was the unavailability of the tested equipment appropriately considered in the performance indicator data;  where applicable, were test results not meeting acceptance criteria addressed with an adequate operability evaluation, or was the system or component declared inoperable;  where applicable for safety-related instrument control surveillance tests, was the reference setting data accurately incorporated into the test procedure;  was equipment returned to a position or status required to support the performance of its safety function following testing;  were all problems identified during the testing appropriately documented and dispositioned in the licensee's CAP;  where applicable, were annunciators and other alarms demonstrated to be functional and were annunicator and alarm setpoints consistent with design documents; and  where applicable, were alarm response procedure entry points and actions consistent with the plant design and licensing documents. Documents reviewed are listed in the Attachment.  This inspection constituted five routine surveillance testing samples as defined in IP 71111.22, Sections -02 and -05.  b. Findings No findings were identified. 1EP6 Drill Evaluation (71114.06) .1 Training Observation a. Inspection Scope  The inspectors observed a simulator training evolution for licensed operators on January 31, 2013, which required Emergency Plan implementation by a licensee operations crew.  This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance.  The inspectors observed event classification and notification activities performed by the crew.  The inspectors also attended the post-evolution critique for the scenario.  The focus of the inspectors' activities was to note any weaknesses and deficiencies in the crew's performance and ensure that the licensee evaluators noted the same issues and entered
in accordance with Section 2.3.2 of the NRC Enforcement Policy.  
them into the CAP.  As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment.  This inspection constituted one training evolution with emergency preparedness drill sample as defined in IP 71114.06-05. 
If you contest this NCV, you should provide a response within 30 days of the date of this  
14 Enclosure  b. Findings No findings were identified. 2. RADIATION SAFETY 2RS4 Occupational Dose Assessment (71124.04) This inspection constituted a partial sample as defined in IP 71124.04-05. .1 External Dosimetry (02.02) a. Inspection Scope The inspectors evaluated whether the licensee's dosimetry vendor is National Voluntary Laboratory Accreditation Program (NVLAP) accredited and if the approved irradiation test categories for each type of personnel dosimeter used were consistent with the types and energies of the radiation present and the way the dosimeter was being used (e.g., to measure deep dose equivalent, shallow dose equivalent, or lens dose equivalent).  b. Findings No findings were identified. 4. OTHER ACTIVITIES 4OA1 Performance Indicator Verification (71151) .1 Unplanned Scrams Per 7000 Critical Hours a. Inspection Scope The inspectors sampled licensee submittals for the Unplanned Scrams Per 7000 Critical Hours Performance Indicator (PI) for both Unit 1 and Unit 2 for the period from the first quarter 2012 through the fourth quarter 2012.  To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, dated October 2009, were used.  The inspectors reviewed the licensee's operator narrative logs, IRs, event reports and NRC Integrated Inspection Reports for the period of January 2012 through December 2012 to validate the accuracy of the submittals.  The inspectors also reviewed the licensee's IR 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. Findings No findings were identified. 
inspection report, with the basis for your denial, to the Nuclear Regulatory Commission,  
15 Enclosure  .2 Unplanned Scrams with Complications a. Inspection Scope The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI for Unit 1 and Unit 2 for the period from the first quarter 2012 through the fourth quarter 2012.  To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, dated October 2009, were used.  The inspectors reviewed the licensee's operator narrative logs, IRs, event reports and NRC Integrated Inspection Reports for the period of January 2012 through December 2012 to validate the accuracy of the submittals.  The inspectors also reviewed the licensee's IR database to determine if any problems had been identified with the PI data collected or
ATTN:  Document Control Desk, Washington, DC 20555-0001; with copies to the Regional  
transmitted for this indicator.  Documents reviewed are listed in the Attachment . This inspection constituted two unplanned scrams with complications samples as defined in IP 71151-05. b. Findings No findings were identified. .3 Unplanned Power Changes Per 7000 Critical Hours a. Inspection Scope The inspectors sampled licensee submittals for the Unplanned Power Changes Per 7000 Critical Hours PI for Unit 1 and Unit 2 for the period from the first quarter 2012 through the fourth quarter 2012.  To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, dated October 2009, were used.  The inspectors reviewed the licensee's operator narrative logs, IRs, maintenance rule records, event reports, and NRC Integrated Inspection Reports for the period of January 2012 through December 2012 to validate the accuracy of the submittals.  The inspectors also reviewed the licensee's IR 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 power changes per 7000 critical hours samples as defined in IP 71151-05. b. Findings No findings were identified. 
Administrator, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,  
16 Enclosure  4OA2 Identification and Resolution of Problems (71152) .1 Routine Review of Items Entered into the Corrective Action Program a. Inspection Scope As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's 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
Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-
included the complete and accurate identification of the problem; that timeliness was commensurate with safety significance; that evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrence reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.  Minor issues entered into the licensee's CAP as a result of the inspectors' observations are listed in the Attachment. These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples.  Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report. b. Findings No findings were identified. .2 Daily Corrective Action Program Reviews a. Inspection Scope To facilitate the identification of repetitive equipment failures and human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's CAP.  This review was accomplished through inspection of the station's daily IR packages. These daily reviews were performed by procedure as part of the inspectors' daily plant status monitoring activities and, as such, did not constitute any separate inspection samples. b. Findings No findings were identified. 
0001; and the NRC Resident Inspector at the Byron Station.   
17 Enclosure  .3 Selected Issue Follow-Up Inspection:  Actions to Address Engineering-Related Issues Identified at Braidwood During NRC Inspections a. Inspection Scope The inspectors reviewed evaluations and calculations as well as related IRs to assess the adequacy of the licensee's extent-of-condition review of issues identified during the Braidwood Station Unit 1 and Unit 2 Evaluation of Changes, Tests, or Experiments and Permanent Plant Modifications inspections performed in 2011.    This review included an analysis that was performed by the licensee to determine the effects of lead shielding on the Unit 1 Safety Injection (SI) system piping subsystem and associated pipe supports.  This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.  b. Findings Embedment Plate Design Deficiencies  Introduction:  The inspectors identified a finding of very low safety significance (Green) and an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," when licensee personnel failed to properly evaluate the structural steel embedment plate which supported SI pipe supports 1SI06025V and 1SI06030S.  Description:  The SI system is part of the emergency core cooling system (ECCS).  Section 6.3.1 of the Byron UFSAR stated, in part, that the primary function of the ECCS is to remove the stored and fission product decay heat from the reactor during accident conditions and provide shutdown capability for design basis accidents by means of boron injection.  Piping Subsystem 1SI06 is part of the SI System and is a safety-related ASME Class II, Seismic Category I subsystem located in the curved wall area of the auxiliary building.  A structural steel embedment plate that supports safety-related pipe supports 1SI06025V and 1SI06030S is located in the auxiliary building, which is a Seismic Category I structure.  Section 3.8.4.5.2 of the UFSAR describes requirements for structural steel design inside the auxiliary building and states, in part, "The stresses and strains of structural steel are limited to those specified in the AISC (American Institute of Steel Construction)-"  Also, this section required that stresses be held within the elastic range and that no plastic deformation was allowed.  The inspectors reviewed Calculation No. 13.2.29BY, "Mechanical Component Support 1SI06025V," Revision 2X that evaluated pipe supports 1SI06025V and 1SI06030S.  These supports were attached to a structural embedment plate in the auxiliary building.  The structural steel embedment plate evaluation was also included in this calculation.  During a review of Calculation No. 13.2.29BY, the inspectors identified a number of concerns, including the following: 
If you disagree with a cross-cutting aspect assignment in this report, you should provide a  
18 Enclosure  The calculated bending stress on the embedment plate was greater than the allowable bending stress by about 67 percent and the licensee relied on engineering judgment to demonstrate compliance with the design and licensing basis requirements;  The calculation used the actual instead of minimum material yield stress of the embedment plate to calculate the allowable bending stress;  The calculation used an acceptance criteria which permitted plastic or permanent deformation through yielding of the structural steel embedment plate and redistribution of stresses in the embedment plate due to applied loads;    The calculation did not include an evaluation for severe environmental load combinations as described in UFSAR Table 3.8-9 and as described in UFSAR Section 3.8.4.3, "Loads and Loading Combinations;" and  The calculation did not consider applied stresses due to self-weight and self-weight seismic excitation of tube steel pipe support members. The inspectors determined that the engineering judgment used to demonstrate compliance with the design and licensing basis was not valid because the AISC required that the allowable bending stress be determined using the minimum yield stress of the material.  In addition, UFSAR Section 3.8.4.5.2 specified no plastic or permanent deformation due to applied stresses.  The inspectors also identified that the structural steel embedment plate was not qualified for the severe environmental load combination as described in UFSAR Table 3.8-9 and as required by UFSAR Section 3.8.4.3.  The licensee entered this issue into their CAP as IR 1478188, "NRC Identified Use of CMTR in a 80's Calculation."  As part of their immediate corrective actions, the licensee performed an operability evaluation and concluded the structural steel embedment plate was operable, but nonconforming. Analysis:  The inspectors determined that the failure to design the structural steel embedment plate which supported pipe supports 1SI06025V and 1SI06030S in accordance with AISC and Seismic Category I linear elastic requirements was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).  Specifically, the licensee did not demonstrate that the structural steel embedment plate which supported pipe supports 1SI06025V and 1SI06030S would maintain structural linear elastic integrity when subjected to design loads. The inspectors reviewed Attachment 0609.04, "Initial Characterization of Findings," Table 3 - SDP Appendix Router.  The inspectors answered 'No' to all of the questions in Sections A through E of Table 3 and therefore the finding was evaluated using the SDP in accordance with IMC 0609, "The Significance Determination Process (SDP) for Findings At-Power," Appendix A, Exhibit 2, "Mitigating Systems Screening 
response within 30 days of the date of this inspection report, with the basis for your  
19 Enclosure  Questions."  The inspectors answered 'Yes' to Question 1 - If the finding is a deficiency affecting the design or qualification of a mitigating SSC [Structure, System, or Component], does the SSC maintain its operability or functionality?  Specifically, the design deficiency was confirmed not to result in a loss of operability of the structural steel embedment plate.  Therefore, the finding was determined to have very low safety significance (Green).  The inspectors performed an independent review of the operability evaluation and had no further concerns.    The inspectors did not identify a cross-cutting aspect associated with this finding because the calculation was from the 1980's and was therefore not representative of current performance.  Enforcement:  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
disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector  
of the design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.  Piping Subsystem 1SI06 is part of the Safety Injection System and is a safety-related ASME Class II, Seismic Category I subsystem located in the curved wall area of the auxiliary building.  A structural steel embedment plate that supports safety-related pipe supports 1SI06025V and 1SI06030S is located in the auxiliary building, which is a Seismic Category I structure.  Section 3.8.4.5.2 of the UFSAR describes requirements for structural steel design inside the auxiliary building and states, in part, "The stresses and strains of structural steel are limited to those specified in the AISC-."  Also, Section 3.8.4.5.2 of the UFSAR required that stresses be within the elastic range and that no plastic deformation was allowed. Contrary to the above, from initial construction to February 21, 2013, the licensee failed to demonstrate the design adequacy of the embedment plate which supported safety-related Safety Injection pipe supports 1SI06025V and 1SI06030S.  Specifically, the design for the structural steel embedment plate which supported safety-related Safety Injection pipe supports 1SI06025V and 1SI06030S was inadequate, in that Calculation No. 13.2.29BY, "Mechanical Component Support 1SI06025V," Revision 2X, which was a quality calculation, did not demonstrate that the embedment plate would meet AISC and Seismic Category I linear elastic requirements. Because this violation was of very low safety significance and it was entered into the
at the Byron Station.
licensee's CAP as IR 1478188, this violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.  As part of their immediate corrective actions, the licensee performed an operability evaluation and concluded the structural steel embedment plate was operable.  (NCV 05000454/2013002-01, "Embedment Plate Design Deficiencies") .4 Selected Issue Follow-Up Inspection: Valves in LCO Due to Abandonment a. Inspection Scope During a review of items entered in the licensee's CAP, the inspectors identified an IR regarding equipment that had been abandoned in place.  Specifically, IR 1306607, "Long Term LCO [Limiting Condition for Operation] Extent of Condition Review Per IR 1298667," characterized a series of valves as abandoned.  The valves were also 
20 Enclosure  characterized as having a containment isolation function.  The inspectors reviewed the licensees' procedures associated with containment leak rate testing and recent test data to ensure that the performance of the abandoned valves remained acceptable.  This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05. b. Findings No findings were identified. 4OA5  Other Activities .1 (Closed) NRC Temporary Instruction (TI) 2515/187 - "Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walkdowns" As discussed in NRC Integrated Inspection Report 05000454/2012005; 05000455/2012005, the inspectors previously verified that licensee walkdown packages Unit 1 13-Line Wall, Unit 1 1A and 1D Main Steam Isolation Valve Room Probable Maximum Precipitation (PMP) Curb, and River Screen House Penetration RH-15C, contained the elements specified in Nuclear Energy Institute (NEI) 12-07, "Guidelines for Performing Walkdowns of Plant Flood Protection Features." During the previous quarter, the inspectors accompanied the licensee on their walkdown of the River Screen House, Penetration RH-15C; and Unit 1 A and D Main Steam Isolation Valve Room PMP Curb and verified that the licensee confirmed the following
flood protection features:  Visual inspection of the flood protection feature was performed if the flood protection feature was relevant.  External visual inspection for indications of degradation that would prevent its credited function from being performed was performed.  Critical SSC dimensions were measured.  Available physical margin, where applicable, was determined.  Flood protection feature functionality was determined using either visual observation or by review of other documents. During this quarter, the inspectors conducted additional independent walkdowns to verify licensee compliance with inspection guidance contained in TI 2515/187.  The area selected was the building that houses the spent fuel pool, the fuel handling building (FHB).  There were several reasons for selecting this area.  For example, the spent fuel pool filtering and heat removal systems are located in the FHB.  In addition, the FHB has access ways that lead to other portions of the auxiliary building, a safety-related structure. The Byron UFSAR identified that the FHB was not subject to flooding.  The inspectors questioned why the FHB would not be subject to flooding since portions of it are at ground level, a roll-up door in this building leads to an adjacent structure which has a 
21 Enclosure  roll-up door that leads outside, and railway channels in the FHB have been observed to contain rain water. The inspectors verified that noncompliances with current licensing requirements, and issues identified in accordance with the 10 CFR 50.54(f) letter, Item 2.g of Enclosure 4, were entered into the licensee's CAP.  In addition, issues identified in response to Item 2.g that could challenge risk significant equipment and the licensee's ability to mitigate the consequences will be subject to additional NRC evaluation. .2 Failure to Properly Scope All the Pertinent External Flood Protection Features into Walkdown Lists in Accordance with Nuclear Energy Institute (NEI) 12-07  Introduction:  The inspectors identified a finding of very low safety significance (Green) when licensee personnel failed to develop inspection lists that included all external flood protection features credited in current licensing bases (CLB) documents as specified in NEI 12-07, "Guidelines for Performing Walkdowns of Plant Flood Protection Features."  Specifically, the inspection lists did not include several passive components in the FHB which were an essential element of the Byron flood mitigation strategy. Description:  The inspectors reviewed the licensee's inspection and walkdown documents associated with flooding reviews performed in accordance with NEI 12-07, "Guidelines for Performing Walkdowns of Plant Flood Protection Features," in response to a letter from the NRC to licensees pursuant to 10 CFR 50.54(f).  During the review, the inspectors identified that the licensee had completed their scoping of components for TI 2515/187, "Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walkdowns," and failed to properly scope all flood protection features credited in the CLB documents for flooding events.  Specifically, while reviewing the Flooding Features Walkdown List used to inspect and test design bases flood mitigating equipment in accordance with the NRC-endorsed guidance of NEI 12-07, the inspectors identified that the flood protection features in the FHB were not included.  The flood protection features in the FHB were designed to protect the auxiliary building, including residual heat removal and containment spray pumps from site external flooding scenarios, and were an essential part of the Byron design basis flood mitigation strategy.  In particular, the concrete steps inside the FHB were designed to prevent flood waters that enter the FHB from reaching a door that would allow water to enter the auxiliary building. Because the licensee did not adequately follow the guidance in NEI 12-07 and identify components in the FHB that served as passive flooding barriers, these components were not scheduled for visual inspections or walkdowns.  As a result, the licensee failed to recognize walkdowns of these passive flooding barriers were required to adequately respond to the March 12, 2012 letter from the NRC to licensees that discussed these reviews.  The licensee acknowledged that they may not have identified these flood barriers during subsequent reviews if the inspectors had not identified the issue. The licensee entered this issue into their CAP as IR 1466355, "Update UFSAR Regarding External Flooding."  Corrective actions included plans to perform an inspection of the NRC-identified passive flooding features that were omitted from the inspection lists and an extent-of-condition review. Analysis:  The inspectors determined that the failure to include concrete flood barriers in the FHB in the flooding inspection lists developed to address NEI 12-07, although these 
22 Enclosure  passive components were a critical element of the Byron flood mitigation strategy, was a performance deficiency.  Using the guidance in IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," the inspectors determined this finding affected the Mitigating Systems Cornerstone.  The inspectors determined that the performance deficiency was more than minor because it was associated with the Protection Against External Factors (Flood Hazard) attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).  Specifically, the concrete flood barriers in the FHB protecting important safety-related equipment in the auxiliary building as well as the flood barriers for the spent fuel pool cooling pumps were not properly scoped into the licensee's walkdown lists. The inspectors reviewed Attachment 0609.04, "Initial Characterization of Findings," Table 3 - SDP Appendix Router.  The inspectors answered 'No' to all of the questions in Sections A through E of Table 3 and therefore the finding was evaluated using the SDP in accordance with IMC 0609, "The Significance Determination Process (SDP) for Findings At-Power," Appendix A, Exhibit 2, "Mitigating Systems Screening Questions."  The inspectors answered 'No' to Question B for the External Event Mitigation Systems - Does the finding involve the loss or degradation of equipment or function specifically designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic snubbers, flooding barriers, tornado doors)?  Therefore, the finding was determined to have very low safety significance (Green).  This finding had a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area because licensee personnel did not properly apply human error prevention techniques such as peer checking and proper documentation of
activities [H.4(a)]. Enforcement:  This finding did not involve enforcement action because no violation of a regulatory requirement was identified.  Because this finding does not involve a violation and is of very low safety significance, it is identified as a finding (FIN).  (FIN 05000454/2013002-02; 05000455/2013002-02, Failure to Properly Scope All Pertinent External Flood Protection Features into Walkdown Lists in Accordance with Industry Guidance NEI 12-07) .3 (Closed) Unresolved Item 05000454/2011005-03; 05000455/2011005-03:  Use of Thermolumiscent Dosimeters May Not Be Consistent With the Methods Used By the National Voluntary Laboratory Accreditation Program Accreditation Process In the fourth quarter of 2011, the inspectors identified that the licensee's use of thermoluminescent dosimeters (TLDs) may not be consistent with the methods used by the NVLAP accreditation process.  Specifically, the licensee used a vendor to supply and process dosimeters that measure radiation exposure for the monitored workers.  This vendor is NVLAP-accredited for beta, gamma, neutron, mixture of beta/gamma, and mixture of neutron/gamma radiations.  However, the licensee used the TLDs when
workers may be exposed to beta, gamma, and neutron radiations within the same monitoring period.  The inspectors determined that this mixture of three radiation types may not be aligned with the accreditation process, and opened Unresolved Item (URI) 
23 Enclosure  05000454/2011005-03; 05000455/2011005-03 to evaluate the issue.  The inspectors requested technical assistance from the Office of Nuclear Reactor Regulation (NRR) through Task Interface Agreement (TIA) 2012-05 (ML 12268A330), the results of which are discussed below. Title 10 CFR 20.1501(c)(2) requires that the dosimeter processor be approved for the type of radiation or radiations included in the NVLAP program that most closely approximates the type of radiation or radiations for which the individual wearing the dosimeter is monitored.  As there is no NVLAP test category for dosimeters exposed to a mixture of beta, gamma, and neutron radiations, the NRC has determined that licensees, which monitor for beta, gamma, and neutron exposure with a single dosimeter, need to use a processor that is NVLAP accredited in categories for beta-photon mixtures and neutron-photon mixtures.  The licensee's dosimetry processor was NVLAP accredited for both beta-photon and neutron-photon mixtures and therefore was in compliance with 10 CFR 20.1501(c)(2). Notwithstanding the paragraph above, licensees are required to provide adequate
monitoring in accordance with 10 CFR 20.1502(a).  For any type of in-field use practice that can introduce error in the monitoring results (dependent upon the type of dosimeter and processing method), it becomes a question of compliance with the monitoring requirements of 10 CRR 20.1502(a) and not of NVLAP accreditation requirements of 10 CFR 20.1501(c)(2).  As described in TIA 2012-05, another licensee had performed a study with the same dosimeters used by Byron (Harshaw 760).  This study demonstrated that exposing a single Harshaw 760 dosimeter to a mixture of beta, gamma, and neutron radiation met industry standards for accuracy and precision.  Therefore, the licensee provided adequate monitoring and was in compliance with 10 CFR 20.1502(a). The inspectors determined that no performance deficiency existed; therefore this URI is closed. 4OA6  Management Meetings .1 Exit Meeting Summary On April 4, 2013, the inspectors presented the inspection results to Mr. B. Youman, Byron Plant Manager, and other members of the licensee's staff.  The licensee acknowledged the issues presented.  The inspectors confirmed that none of the potential report input discussed was considered proprietary. .2 Interim Exit Meetings  The inspection results for the area of occupational dose assessment were
discussed with Mr. B. Burton, Radiation Protection Manager, on March 26, 2013.  The inspection results for the area of lead shielding and pipe supports were discussed with Ms. A. Corrigan, Mechanical Design Manager, and                    Mr. E. Blondin, Design Engineering Manager, on March 26, 2013. The licensee acknowledged the issues presented.  The inspectors confirmed that none of the potential report input discussed was considered proprietary. 
24 Enclosure  ATTACHMENT:  SUPPLEMENTAL INFORMATION 
1 Attachment  SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT Licensee R. Kearney, Site Vice President B. Youman, Plant Manager B. Askren, Security Manager B. Barton, Radiation Protection Manager S. Briggs, Operations Director A. Creamean, Chemistry Manager S. Gackstetter, Training Manager D. Gudger, Regulatory Assurance Manager E. Hernandez, Engineering Director D. Horstmann, Business Operations B. Spahr, Maintenance Director E. Topping, Nuclear Oversight Manager  Nuclear Regulatory Commission E. Duncan, Chief, Branch 3, Division of Reactor Projects B. Bartlett, Byron Senior Resident Inspector J. Robbins, Byron Resident Inspector  Illinois Emergency Management Agency (IEMA)  R. Zuffa, IEMA   
2 Attachment    LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 05000454/2013002-01 NCV Embedment Plate Design Deficiencies (Section 4OA2.3) 05000454/2013002-02; 05000455/2013002-02 FIN Failure to Properly Scope All Pertinent External Flood Protection Features into Walkdown Lists in Accordance with Industry Guidance NEI 12-07 (Section 4OA5.2)  Closed 05000454/2013002-01 NCV Embedment Plate Design Deficiencies (Section 4OA2.3) 05000454/2013002-02; 05000455/2013002-02 FIN Failure to Properly Scope All Pertinent External Flood Protection Features into Walkdown Lists in Accordance with Industry Guidance NEI 12-07 (Section 4OA5.2) TI 2515/187 TI Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walkdown (Section 4OA5.1) 05000454/2011005-03; 05000455/2011005-03 URI Use of TLDs May Not Be Consistent With the Methods Used by the NVLAP Accreditation Process (Section 4OA5.3)     
3 Attachment  LIST OF DOCUMENTS REVIEWED The following is a list of documents reviewed during the inspection.  Inclusion on this list does not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that selected sections of portions of the documents were evaluated as part of the overall inspection effort.  Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report. Section 1R04 - BOP WO-E4; Control Room Chilled Water Electrical Lineup, Revision 2 - BOP WO-M3; Control Room Chilled Water Valve Lineup, Revision 10 Section 1R06 - BAR 0PL02J-3-B2; ESW Sump 2 Level High High, Revision 52 - IR 1413893; Unit 1 SX Alpha Sump Pump Check Valve is Sticking Open, September 16, 2012 - M-48; Diagram of Miscellaneous Sumps and Pumps, Revision AE Section 1R11 - IR 1486687; Unexpected Unit 1 PDMS Alarms Due to Failing CETC, March 12, 2012 Section 1R12 - IR 1487650; Potential Corporate Elevation for Byron Maintenance, March 12, 2013 - IR 1479105; Unit 1 Gain POT R303 for N-43 Not Functioning Properly, February 22, 2013 - Byron Station Maintenance Rule Expert Panel Meeting Notes, November 5, 2009 - Byron Station Maintenance Rule Expert Panel Meeting Notes, December 18, 2009 - Byron Station Maintenance Rule Expert Panel Meeting Notes, June 7, 2011 - Byron Station Maintenance Rule Expert Panel Meeting Notes, November 3, 2011 - IR 1214163; Common Cause Analysis for MCCB for MCC 134Y2-A4, June 2, 2011 - ER-AA-310-1005; (A)(1) Determination Template for IR 1207922, Revision 5 - ER-AA-310-1005; (A)(1) Determination Template for IR 1207931, Revision 5 - Byron Station Maintenance Rule Periodic Assessment #11, January 2011 - June 2012 Section 1R13 - IR 1474028; 2A CV Pump Gear Box Failed to Develop Oil Pressure on Start,
February 12, 2013 - IR 1474042; 2A CV Pump Gear Oil Pressure Guage Stuck at 0 Psig, February 12, 2013 Section 1R15 - IR 1413971; Byron OAD Investigated and Identified an Abnormal Indication of the Over Current Relay, October 11, 2012 - NSWP-S-05; Concrete Expansion Anchors, Revision 7 - Calculation 7.16.10.2-BYR97-229; Structural Evaluation of Battery Racks and the Mounting Details in 111 and 112 Battery Rooms of the Auxiliary Building, Revision 4 - Drawing 6E-0-3391AY; 125V DC Battery Rack Mounting Details - Drawing M-11978; Bus 111 & 211 125V DC "L" Two Step EP3 Racks, Revision 2 
4 Attachment  - Drawing 6E-0-3391AH; Byron Station Unit 1& 2, Electrical Equipment Mounting Details, Revision S - Drawing 64-05906; Floor Rack - Two Step EQ Protected for Plate Size 3 and 4 Batteries, Revision 0 - CC-AA-112; Temporary Configuration Changes, Revision 19 - EC 378402; Single Use Evaluation for 1/2 of SX Cubical Coolers Not Available, January 6, 2010 - EC 392429; Operation of SX Pump with Single Cubical Cooler, February 12, 2013 - IR 1465872; Review of Braidwood IR 1459353 - PZR PORV Accumulator Pressure, January 22 - CN-RRA-00-47; Calculational Table for Byron and Braidwood Natural Circulation Cooldown, Revision 1 Section 1R18 - Performance Verification Testing; RCFC Check Dampers for Byron Units 1 and 2, July 1981 - Sargent & Lundy Fan Check Dampers for Byron Units 1 and 2, March 5, 1985 - Material and Equipment Receiving and Inspection Report CECo Engineering and Construction, June 30, 1981 - Material and Equipment Receiving and Inspection Report CECo Engineering and Construction, June 30, 1981 - Q.F.2910.24; Project No. 4391-05, Tornado/Isolation Dampers, May 11, 1981 - Q.F.2910.24; Project No. 4392-05, Tornado/Isolation Dampers, May 11, 1981 - IR 1419184; RCFC Damper Missing Springs; September 27, 2012 - IR 1419189; RCFC Damper Missing Springs; September 27, 2012 - IR 1419190; RCFC Damper Missing Springs; September 27, 2012 - IR 1419192; RCFC Damper Missing Springs; September 27, 2012 - IR 1474498; NRC Follow-Up - RCFC Discharge Check Damper; February 7, 2013 Section 1R19 - IR 1473967; No SX PP Cubicle Cooler Tubesheet Degradation Margin Exists, February 11, 2013 - WO 1493809; 214 Instrument Inverter EOC Walkdown Due to 211 INV Failure, Revision 1 - WO 1591475; 1SX01PA Comprehensive IST Required for Essential Service Water Pump, February 14, 2013 - BOP IP-1; Instrument Bus Inverter Startup, Revision 14 - IR 1472776; ACB 1442 Drives On-Line Risk Yellow for Both Units, February 8, 2013 - IR 1473015; Lockout Relay 486-1442 for Breaker 1442 is Degraded, February 8, 2013 - WO 1237471; Bus 144 Sat 142-2 Feed (ACB 1442) RES OC Relay Routine, February 8, 2013 - WO 1444425; Replace Lockout Relay on ACB 1442, February 9, 2013 - WO 1591475; 1SX01PA Comprehensive IST Requirement for Essential Service Water Pump,
February 14, 2013 - WO 1418630; Support Eddy Current Testing for 1A SX Pump Cubical Cooler, February14, 2013 - WO 1366902; Operation Run Cooler and Check for Proper Operation, February 14, 2013 - WO 1314236; Preventative Maintenance on Breaker SAT Feed, February 14, 2013 Section 1R20 - OP-AA-101-113-1004; Equipment Prompt: 2A Generator Stator Cooling Water Pump (2A GC) Tripped, Revision 24 
5 Attachment  - IR 1490321; Smoke Noticed Coming from the 2A FW Pump Motor, March 20, 2013 - IR 1490323; DRPI POD M-12 Indicated General Warning Following Reactor Trip, March 20, 2013 - IR 1493026; Smoke was Reported Coming from U2 Voltage Regulator Cabinet, March 20, 2013 - IR 1490315; U-2 Reactor Trip - Loss of GC, March 20, 2013 - IR 1490330; Oil Leaking From Exciter End of Main Generator, March 20, 2013 - IR 1490407; Need Cleanup of Generator Oil Leak in Various TB Elevations, March 21, 2013 - IR 1490453; U2 RCDT Elevated Inputs Investigation, March 21, 2013 - IR 1490635; Following U2 Reactor Trip, 2AR11J went Dark Blue and then White, March 21, 2013 Section 1R22 - 1BOSR 3.1.5-1; Train A Solid State Protection System Surveillance, Revision 32 - WO 1469526 01; ESF Relay Train Reactor Trip - K636/2FW039S, February 25, 2013 - IR 631199; Revise Unit Two Schematic Diagram 6E-2 4030FW56, May 18, 2007 - IR 848809; 12/15 E-3 Schedule Review, November 23, 2008 - IR 1064332; Inadequate Technical Information Provided for New SSPS Cards, May 2, 2010 - IR 1293130; UV Driver Card Vulnerability in OE 34462 Applicable at Byron, November 21, 2011 - IR 1323037; Unexpected FWI While Closing RX Trip Breakers, February 5, 2012 - IR 1328319; Unexpected Ground Reading During SSPS Surveillance, February 17, 2012 - IR 1329012; Unexpected FWI While Closing RX Trip Breakers, February 20, 2012 - IR 1329908; Low Contact Volts Found During SSPS - Not Unusual, February 21, 2012 - IR 1374658; Low Voltage Reading During 2BOSR 3.1.5-2, June 5, 2012 - WO 1588151; 1CS01PB Comprehensive IST Requirements for Containment Spray Pump, January 29, 2013 - BOP CS-5; Containment Spray System Recirculation to the RWST, Revision 11 - WO 1609614; 1A Diesel Generator Operability Surveillance, February 6, 2013 - 1BOSR 8.1.2-1; Unit 1 Train A Diesel Generator Operability Surveillance, Revision 20 - WO 1596040; ESF Relay Train B CS-K644 ESFAS Instrumentation ESF Relay Surveillance, February 28, 2013 - WO 1597146; 2CS01PB Comprehensive IST Requirements for Containment Spray Pump,
February 28, 2013 Section 2RS4 - Final Response to Task Interface Agreement 2012-05; ML12268A330; October 16, 2012 Section 4OA1 - Power History Curves for Unit 1 and Unit 2, January 2012 through December 2012 - Perfomance Indicator Data as Reported for the Period January 2012 through December 2012 - IR 1319908; B2F26 U2 Reactor Trip Due To Electrical Fault and Unusual Event, January 30, 2012 - IR 1323547; B2F27 Manual Reactor Trip and Manual Auxiliary Feedwater Actuation, February 6, 2012 
 
6 Attachment  Section 4OA2 - IR 1474066; Issues With SX to CC MOD Installation, February 11, 2013 - IR 1477430; Insufficient  Insertion of Anti-Vibration Bars in Alloy 600, February 19, 2013 - IR 1413971; EACE - 1B RH Pump Trip Due to CO-5 Overcurrent Relay Operation, September 17, 2012 - IR1272187; Issues Applicable to Byron from Bwd Mod/50.59 Inspection; October 4, 2011 - IR 1296141; NER NC-11-045-Y Fleet Wide Actions; September 28, 2011 - Byron Document No. DS-MC-01-BY; Certification of Design Specification for Primary Containment Piping Penetration Assemblies; Revision 3 - Byron/Braidwood Document No. 01-10-52; Bryon/Braidwood Piping Design Specification; Revision 2 - Calculation No. 13.2.29BY; Mechanical Component Support 1SI06025V; Revision 2X - ER-AA-380; Primary Containment Leakrate Testing Program, Revision 9 - BVP 800-39; Primary Containment Leakrate Testing Program, Revision 10 - 1BOSR 6.1.1-19; Unit 1 Primary Containment Type C Leakage Rate Tests and IST Tests of the OffGas System, Revision 8 - 2BVSR 6.1.1-24; Unit 2 Summation of Primary Containment Type B & C Local Leakage Tests for Acceptance Criteria, Revision 12 - 1BVSR 6.1.1-24; Unit 2 Summation of Primary Containment Type B & C Local Leakage Tests for Acceptance Criteria, Revision 15 - IR 1298667; Long Term LCO for VQ Valves Needs Resolution, December 6, 2011 - IR 1306607; Long Term LCO Extent of Condition Review Per IR 1298667, December 26, 2011 - EC 390536; Determine Acceptability of Code Case N-597-2 use on FAC Components 1FW085B/D, Revision 0 - IR 1412470; B1R18 FAC Component 1FW085B Exam Failure, September 13, 2012 - IR 1415327; B1R18 FAC Component 1FW085D Exam Failure, September 13, 2012 Corrective Action Documents As a Result of NRC Inspection  - IR 1487707; NRC ID UFSAR Discrepancy-Appendix A, Page A.1.57-1; March 14, 2013 - IR 1478188; NRC Identified Use of CMTR in a 80's Calculation; February 21, 2013 - IR 1490153; NRC/IEMA 1A DG HELB Modification Walkdown; March 20, 2013 - IR 1493278; NRC ID'ed: PDP 50.59 Enhancement Required, March 27, 2013 Section 4OA5 - IR 1466355; FUK: Update UFSAR Regarding External Flooding, January 24, 2013 - IR 1472808; FUK: Effect of Local Intense Precipitation on FHB and SFP PP, February 8, 2013 - IR 1474686; FUK: Concrete Steps on 401" FHB to Areas 5 & 7, February 13, 2013 - IR 1475877; Blockwall Penetrations in SFP Pump Room, February 15, 2013 - IR 1484749; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013 - IR 1484755; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013 - IR 1484758; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013 - IR 1484765; FUK: MCC 132X3 Fasteners Seismic Walkdown, March 7, 2013 - IR 1484768; FUK: MCC 131X3 Fasteners Seismic Walkdown, March 7, 2013  Corrective Action Documents As a Result of NRC Inspection  -IR 1453636; FUK: Flooding and Seismic Walkdowns, December 18, 2012 
7 Attachment  LIST OF ACRONYMNS USE ADAMS Agencywide Document Access and Management System AISC American Institute of Steel Construction ASME American Society of Mechanical Engineers CAP Corrective Action Program CFR Code of Federal Regulations CLB Current Licensing Basis ECCS Emergency Core Cooling System ESF Engineered Safety Feature FHB Fuel Handling Building FIN Finding FSAR Final Safety Analysis Report IMC Inspection Manual Chapter IP Inspection Procedure IR Inspection Report IR Issue Report LCO Limiting Condition for Operation NCV Non-Cited Violation NEI Nuclear Energy Institute NRC U.S. Nuclear Regulatory Commission NRR Office of Nuclear Reactor Regulation NVLAP National Voluntary Laboratory Accreditation Program PARS Publicly Available Records System PI Performance Indicator PMP Probable Maximum Precipitation PORV Power-Operated Relief Valve RCFC Reactor Containment Fan Cooler ROP Reactor Oversight Process RFO Refueling Outage SDP Significance Determination Process SI Safety Injection SSC Structure, System, or Component SX Essential Service Water TI Temporary Instruction TIA Task Interface Agreement TLD Thermoluminescent Dosimeter TS Technical Specification UFSAR Updated Final Safety Analysis Report URI Unresolved Item WO Work Order 
M. Pacilio    -2-  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 (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS).  ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room). Sincerely,                /RA/  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 No. 05000454/2013002 and 05000455/2013002    w/Attachment:  Supplemental Information cc w/encl: Distribution via ListServ   
            DOCUMENT NAME:  G:\DRPIII\BYRO\Byron 2013 002.docx  Publicly Available  Non-Publicly Available  Sensitive  Non-Sensitive To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy OFFICE RIII        NAME TDaun:dtp EDuncan  DATE 04/26/13 04/29/13  OFFICIAL RECORD COPY 
Letter to M. Pacilio from E. Duncan dated April 29, 2013.  SUBJECT: BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000454/2013002; 05000455/2013002  DISTRIBUTION: Doug Huyck RidsNrrDorlLpl3-2 Resource RidsNrrPMByron Resource
RidsNrrDirsIrib Resource Chuck Casto Cynthia Pederson Steven Orth Allan Barker Christine Lipa Carole Ariano Linda Linn DRPIII DRSIII Tammy Tomczak Patricia Buckley ROPreports.Resource@nrc.gov 


M. Pacilio
-2-
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 (PARS) component of
NRC's Agencywide Document Access and Management System (ADAMS).  ADAMS is
accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public
Electronic Reading Room).
Sincerely,
/RA/
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 05000454/2013002 and 05000455/2013002
  w/Attachment:  Supplemental Information
cc w/encl:
Distribution via ListServ 
Enclosure
U. S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-454; 50-455
License Nos:
NPF-37; NPF-66
Report No:
05000454/2013002; 05000455/2013002
Licensee:
Exelon Generation Company, LLC
Facility:
Byron Station, Units 1 and 2
Location:
Byron, IL
Dates:
January 1 through March 31, 2013
Inspectors:
B. Bartlett, Senior Resident Inspector
J. Robbins, Resident Inspector
J. Bozga, Reactor Inspector
V. Meyers, Health Physicist
V. Meghani, Reactor Inspector
T. Daun, Reactor Engineer
R. Ng, Project Engineer
C. Thompson, Resident Inspector, Illinois Emergency 
Management Agency
Approved by:
E. Duncan, Chief
Branch 3
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS ......................................................................................................... 1
REPORT DETAILS .................................................................................................................... 3
Summary of Plant Status ........................................................................................................ 3
1.
REACTOR SAFETY .................................................................................................... 3
1R01
Adverse Weather Protection (71111.01) ............................................................ 3
1R04
Equipment Alignment (71111.04) ...................................................................... 4
1R05
Fire Protection (71111.05) ................................................................................. 4
1R06
Flooding (71111.06) .......................................................................................... 5
1R11
Licensed Operator Requalification Program (71111.11) .................................... 6
1R12
Maintenance Effectiveness (71111.12) .............................................................. 7
1R13 
Maintenance Risk Assessments and Emergent Work Control (71111.13) ......... 8
1R15
Operability Evaluations (71111.15) .................................................................... 8
1R18
Plant Modifications (71111.18) .......................................................................... 9
1R19
Post-Maintenance Testing (71111.19) ..............................................................10
1R20
Outage Activities (71111.20) ............................................................................11
1R22
Surveillance Testing (71111.22) .......................................................................12
1EP6
Drill Evaluation (71114.06) ...............................................................................13
2.
RADIATION SAFETY .................................................................................................14
2RS4
Occupational Dose Assessment (71124.04) .....................................................14
4.
OTHER ACTIVITIES ...................................................................................................14
4OA1
Performance Indicator Verification (71151).......................................................14
4OA2
Identification and Resolution of Problems (71152)............................................16
4OA5    Other Activities .................................................................................................20
4OA6 
Management Meetings .....................................................................................23
SUPPLEMENTAL INFORMATION ............................................................................................. 1
Key Points of Contact ............................................................................................................. 1
List of Items Opened, Closed, and Discussed ........................................................................ 2
List of Documents Reviewed .................................................................................................. 3
List of Acronymns Use ............................................................................................................ 7
1
Enclosure
SUMMARY OF FINDINGS
Inspection Report (IR) 05000454/2013002 and 05000455/2013002; 01/01/2013 - 03/31/2013;
Byron Station, Units 1 & 2; Identification and Resolution of Problems; Other Activities.
This report covers a 3-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors.  Based on the results of this inspection, two NRC-
identified findings of very low safety significance (Green) were identified.  One of these findings
had an associated Non-Cited Violation (NCV) of NRC regulations.  The significance of
inspection findings is indicated by their color (Greater than Green, or Green, White, Yellow,
Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination
Process (SDP) dated June 2, 2011.  Cross-cutting aspects are determined using IMC 0310,
Components Within the Cross-Cutting Areas, dated October 28, 2011.  All violations of NRC
requirements are dispositioned in accordance with the NRCs Enforcement Policy dated
January 28, 2013.  The NRCs program for overseeing the safe operation of commercial nuclear
power reactors is described in NUREG-1649, Reactor Oversight Process (ROP), Revision 4.
A.
NRC-Identified and Self-Revealed Finding
Cornerstone:  Mitigating Systems
*
Green.  The inspectors identified a finding of very low safety significance (Green) and an
associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when
licensee personnel failed to properly evaluate the structural steel embedment plate
which supported Safety Injection (SI) pipe supports 1SI06025V and 1SI06030S. 
Specifically, the licensee failed to demonstrate compliance with the American Institute of
Steel Construction (AISC) and Seismic Category I linear elastic requirements.  The
licensee entered this issue into their corrective action program (CAP) as Issue Report
(IR) 1478188.  As part of their immediate corrective actions, the licensee performed an
operability evaluation and concluded the structural steel embedment plate was operable,
but nonconforming.
The inspectors determined that the performance deficiency was more than minor
because it was associated with the Design Control attribute of the Mitigating Systems
Cornerstone and adversely affected the cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences (i.e., core damage).  Specifically, the licensee failed
to demonstrate compliance with AISC and Seismic Category I linear elastic requirements
to ensure the structural steel embedment plate would maintain structural integrity when
subjected to a design basis load.  The inspectors determined that because the finding
did not result in a loss of operability or functionality, the finding was of very low safety
significance (Green).  This finding did not have a cross-cutting aspect as it was not
indicative of current performance.  (Section 4OA2.3)
*
Green.  The inspectors identified a finding of very low safety significance (Green) when
licensee personnel failed to develop inspection lists that included all external flood
protection features credited in current licensing bases (CLB) documents as specified in
Nuclear Energy Institute (NEI) 12-07, Guidelines for Performing Walkdowns of Plant
Flood Protection Features.  Specifically, concrete flood barriers in the fuel handling
building (FHB) that protected safety-related equipment in the auxiliary building and flood
barriers for the spent fuel pool cooling pumps were not included in the licensees
2
Enclosure
flooding inspection lists, although these passive components were a critical element of
the licensees flood mitigation strategy.  The licensee entered this issue into their CAP
as IR 1466355.  Corrective actions included plans to perform an inspection of the NRC-
identified features that were omitted from the inspection lists and an extent-of-condition
review.
The inspectors determined that the performance deficiency was more than minor
because it was associated with the Protection Against External Factors (Flood Hazard)
attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone
objective of ensuring the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences (i.e., core damage).  Because the
finding did not involve the loss or degradation of equipment or function specifically
designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic
snubbers, flooding barriers, tornado doors), the finding was of very low safety
significance (Green).  This finding had a cross-cutting aspect in the Work Practices
component of the Human Performance cross-cutting area because licensee personnel
failed to properly apply human error prevention techniques such as peer checking and
proper documentation of activities [H.4(a)].  (Section 4OA5.2)
B.
Licensee-Identified Violations
None.
3
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at or near full power throughout the inspection period. 
Unit 2 operated at or near full power throughout most of the inspection period.  On
March 20, 2013, at approximately 7:51 p.m., the Unit 2 reactor was manually tripped when the
only available generator stator cooling water pump failed.  All equipment operated as expected
with a few minor exceptions.  Unit 2 returned to full power operation on March 25, 2013, after
the pump was repaired and returned to service.
1.
REACTOR SAFETY
Cornerstones:  Initiating Events, Mitigating Systems, Barrier Integrity and
Emergency Preparedness
1R01 Adverse Weather Protection (71111.01)
.1
External Flooding
a.
Inspection Scope 
The inspectors evaluated the design, material condition, and procedures for coping with
the design bases probable maximum flood.  The evaluation included a review to check
for deviations from the descriptions provided in the Updated Final Safety Analysis Report
(UFSAR) for features intended to mitigate the potential for flooding from external factors. 
As part of this evaluation, the inspectors checked for obstructions that could prevent
draining, checked that the roofs did not contain obvious loose items that could clog
drains in the event of heavy precipitation, and determined whether barriers required to
mitigate flooding were in place and operable.  Additionally, the inspectors performed a
walkdown of the protected area to identify any modification to the site which could inhibit
site drainage during a probable maximum precipitation event or allow water ingress past
a flood barrier.  The inspectors also walked down underground bunkers/manholes
subject to flooding that contained multiple trains or multiple function risk-significant
cables.  The inspectors also reviewed the abnormal operating procedure for mitigating
the design bases flood to ensure it could be implemented as written.  Specific areas
inspected included the Unit 1 emergency diesel generators, main steam tunnels, and the
fuel handling building (FHB).
This inspection constituted one external flooding sample as defined in Inspection
Procedure (IP) 71111.01-05.
b.
Findings
Findings identified during this inspection are documented in Section 4OA5, Other
Activities.
4
Enclosure
1R04 Equipment Alignment (71111.04)
.1
Quarterly Partial System Walkdowns
a.
Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
*
Unit Common Train A Control Room Chiller with Train B Control Room Chiller
Out of Service for Maintenance;
*
Unit 2 Instrument Inverter 212 with Instrument Inverter 214 Out of Service for
Maintenance; and
*
Unit 2 Train A Essential Service Water (SX) with Unit 2 Train B SX 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, the UFSAR, Technical Specification (TS) requirements, outstanding
work orders (WOs), issue reports (IRs), 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 function(s).  The inspectors also
walked down accessible portions of the systems to verify system components and
support equipment were aligned correctly and operable.  The inspectors examined the
material condition of the components and observed operating parameters of equipment
to verify that there were no obvious deficiencies.  The inspectors also verified that the
licensee had properly identified and resolved equipment alignment problems that could
cause initiating events or impact the capability of mitigating systems or barriers and
entered them into the corrective action program (CAP) with the appropriate significance
characterization.  Documents reviewed are listed in the Attachment.
This inspection constituted three partial system walkdown samples as defined in
IP 71111.04-05.
b.
Findings
No findings were identified.
1R05 Fire Protection (71111.05)
.1
Routine Resident Inspector Tours (71111.05Q)
a.
Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on the
availability, accessibility, and the condition of firefighting equipment in the following
risk-significant plant areas:
5
Enclosure
*
Division 11 Miscellaneous Electrical Equipment and Battery Room Fire
Area 5.6-1;
*
Division 21 Miscellaneous Electrical Equipment and Battery Room Fire
Area 5.6-2;
*
Division 12 Miscellaneous Electrical Equipment and Battery Room Fire
Area 5.4-1; and 
*
Division 22 Miscellaneous Electrical Equipment and Battery Room Fire         
Area 5.4-2.
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. 
This inspection constituted four quarterly fire protection inspection samples as defined in
IP 71111.05-05.
b.
Findings
No findings were identified
1R06 Flooding (71111.06)
.1
Internal Flooding
a.
Inspection Scope
The inspectors reviewed selected risk important plant design features and licensee
procedures intended to protect the plant and its safety-related equipment from internal
flooding events.  The inspectors reviewed flood analyses and design documents,
including the UFSAR, engineering calculations, and abnormal operating procedures to
identify licensee commitments.  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 CAP 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
6
Enclosure
sumps were clear of debris and were operable, and that the licensee complied with
existing commitments:
*
Unit 1 and Unit 2 SX Pump Rooms
Documents reviewed are listed in the Attachment.  This inspection constituted one
internal flooding sample as defined in IP 71111.06-05.
b.
Findings
No findings were identified. 
1R11 Licensed Operator Requalification Program (71111.11)
.1
Resident Inspector Quarterly Review (71111.11Q)
a.
Inspection Scope
On January 31, 2013, the inspectors observed a crew of licensed operators in the plant
simulator during licensed operator requalification examinations to verify that operator
performance was adequate, evaluators were identifying and documenting crew
performance problems, and training was being conducted in accordance with licensee
procedures.  The inspectors evaluated the following areas:
*
licensed operator performance;
*
crews clarity and formality of communications;
*
ability to take timely actions in the conservative direction;
*
prioritization, interpretation, and verification of annunciator alarms;
*
correct use and implementation of abnormal and emergency procedures;
*
control board manipulations;
*
oversight and direction from supervisors; and
*
ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications.
The crews performance in these areas was compared to pre-established operator action
expectations, procedural compliance, and successful critical task completion
requirements.  Documents reviewed are listed in the Attachment.
In addition, the inspectors observed licensed operator performance in the actual plant
and the main control room during this calendar quarter.
This inspection constituted one quarterly licensed operator requalification program
sample as defined in IP 71111.11-05.
b.
Findings
No findings were identified.
7
Enclosure
.2
Resident Inspector Quarterly Observation of Heightened Activity or Risk (71111.11Q)
On March 12, 2013, the inspectors observed control room operators during the
emergent failure of Unit 1 core exit thermocouple 50, and on March 22, 2013, the
inspectors observed plant startup following the Unit 2 forced outage.  These were
activities that required heightened awareness and was related to increased risk. 
The inspectors evaluated the following areas:
*
licensed operator performance;
*
crews clarity and formality of communications;
*
ability to take timely actions in the conservative direction;
*
prioritization, interpretation, and verification of annunciator alarms;
*
correct use and implementation of procedures;
*
control board manipulations;
*
oversight and direction from supervisors; and
*
ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications.
The crews performance in these areas was compared to pre-established operator action
expectations, procedural compliance, and successful critical task completion
requirements.  Documents reviewed are listed in the Attachment.
This inspection constituted one quarterly licensed operator heightened activity/risk
sample as defined in IP 71111.11-05.
b.
Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12)
.1
Routine Quarterly Evaluations (71111.12Q)
a.
Inspection Scope
The inspectors evaluated degraded performance issues involving the following
risk-significant systems:
*
Failure of Unit 1 Power Range Channel N43; and
*
Review of Maintenance Rule Assessment for the Period of January 2011 to
June 2012.
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.
8
Enclosure
b.
Findings
No findings were identified.
1R13  Maintenance Risk Assessments and Emergent Work Control (71111.13)
.1
Maintenance Risk Assessments and Emergent Work Control
a.
Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the
maintenance and emergent work activities affecting risk-significant and safety-related
equipment listed below to verify that the appropriate risk assessments were performed
prior to removing equipment for work:
*
Unit 2 Train A Charging Pump Emergent Failure with the Unit 1 Train A SX
Pump Out of Service for Planned Maintenance;
*
Unit 1 Power Range Channel N43 Emergent Failure with Unit 2 Train B SX
Inoperable for Planned Maintenance; and
*
Unit 1 Train B Auxiliary Feedwater Pump Work Window.
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 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.
This inspection constituted three maintenance risk assessments and emergent work
control samples as defined in IP 71111.13-05.
b.
Findings
No findings were identified.
1R15 Operability Evaluations (71111.15)
.1
Operability Evaluations
a.
Inspection Scope
The inspectors reviewed the following issues:
*
Unit 1 Division 111 Battery Racks Support Questions;
*
Capacity of Pressurizer Power Operated Relief Valve (PORV) Air Accumulators
During Natural Circulation Cooldown;
9
Enclosure
*
Operation of SX Pump with Single Cubical Cooler; and
*
Unit 1 Power Range Channel N43 TS 3.3.1.D Entry.
The inspectors selected these potential operability issues based on the risk significance
of the associated components and systems.  The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred.  The inspectors compared the operability and design criteria in the
appropriate sections of the TS and UFSAR to the licensees evaluations to determine
whether the components or systems were operable.  Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled.  The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations.  Additionally, the inspectors reviewed a 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
Attachment.
This inspection constituted four operability inspection samples as defined in
IP 71111.15-05.
b.
Findings
No findings were identified.
1R18 Plant Modifications (71111.18)
.1
Plant Modifications
a.
Inspection Scope
The inspectors reviewed the following modification:
*
Reactor Containment Fan Cooler (RCFC) Check Dampers Closure Spring
Changes
The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety
evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to
verify that the modification did not affect the operability or availability of the affected
system.  The inspectors, as applicable, observed ongoing and completed work activities
to ensure that the modifications were installed as directed and consistent with the design
control documents; the modifications operated as expected; post-modification testing
adequately demonstrated continued system operability, availability, and reliability; and
that operation of the modifications did not impact the operability of any interfacing
systems.  As applicable, the inspectors verified that relevant procedure, design, and
licensing documents were properly updated.  Lastly, the inspectors discussed the plant
modification with operations, engineering, and training personnel to ensure that the
individuals were aware of how the operation with the plant modification in place could
impact overall plant performance.  Documents reviewed are listed in the Attachment.
10
Enclosure
This inspection constituted one permanent plant modification sample as defined in
IP 71111.18-05.
b.
Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19)
.1
Post-Maintenance Testing
a.
Inspection Scope
The inspectors reviewed the following post-maintenance testing activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
*
Unit 1 Bus 144 Breaker 1442 Following Lockout Relay Replacement;
*
Unit 1 Train A SX Cubical Coolers Following Repairs;
*
Unit 2 Instrument Inverter 214 Following Coil Replacement; and
*
Unit 2 Train B Generator Stator Water Cooling System Pump Following Motor
Replacement.
These activities were selected based upon the structure, system, and components
(SSCs) 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 bases 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 into the CAP at the appropriate threshold and
that the problems were being corrected commensurate with their importance to safety. 
Documents reviewed are listed in the Attachment.
This inspection constituted four post-maintenance testing samples as defined in
IP 71111.19-05.
b. Findings
No findings were identified.
11
Enclosure
1R20 Outage Activities (71111.20)
.1
Unit 2 Forced Outage
a.
Inspection Scope
On March 20, 2013, at 7:51 p.m., licensee personnel performed a manual trip of the
Unit 2 reactor.  The reactor was manually tripped in accordance with site procedures
when the only operating and available electrical generator stator cooling water pump
tripped unexpectedly.  The inspectors responded to the site and assessed the cause of
the trip, performed follow-up inspection of minor equipment failures, and immediately
communicated any observations to NRC management.  The inspectors reviewed outage
equipment configuration and risk management, verified electrical lineups, monitored
decay heat removal, observed reactor startup activities, and reviewed the identification
and resolution of problems associated with the forced outage.
All safety-related equipment operated as designed.  Some nonsafety-related equipment
experienced minor malfunctions.  For example:
*
The B reactor trip breaker closed indication light extinguished as expected, however
the open indication light did not illuminate to indicate that the breaker was open.  An
operator was dispatched and verified the breaker was open.  Subsequently, a burned
out B reactor trip breaker open indication light bulb was replaced.
*
The control rod in position M-12 (control bank D) had a general warning light
flashing, although its associated rod bottom light was lit.  Following troubleshooting,
a logic card was replaced in the control rod drive cabinet to address the issue.
*
Following the Unit 2 trip, light smoke was reported to be coming from the Unit 2 A
main feedwater pump motor.  It was later determined that when the 2A main feedater
pump was shut down that its associated motor heater automatically energized.  An
abnormally large amount of dust had built up on the heater and when it energized the
dust burned off.
The licensee addressed these issues and Unit 2 was restarted and synchronized to the
electrical grid on March 22, 2013. 
Documents reviewed are listed in the Attachment.  This inspection constituted one other
outage sample as defined in IP 71111.20-05.
b.
Findings
No findings were identified.
.2
Unit 2 Refueling Outage
a.
Inspection Scope
The inspectors reviewed the Outage Safety Plan and contingency plans for the Unit 2
refueling outage (RFO) that began on April 7, 2013, to confirm that the licensee had
appropriately considered risk, industry operating experience, and previous site specific
12
Enclosure
problems in developing and implementing a plan that assured maintenance of defense in
depth. 
A complete list of accomplished inspection activities will be documented following
completion of the Unit 2 RFO.
This inspection constituted a partial RFO sample as defined in IP 71111.20-05.
b.
Findings
No findings were identified.
1R22 Surveillance Testing (71111.22)
.1
Surveillance Testing
a.
Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether
risk-significant systems and equipment were capable of performing their intended safety
function and to verify testing was conducted in accordance with applicable procedural
and TS requirements:
*
Unit 1 Train B Containment Spray Pump Quarterly Surveillance;
*
Unit 1 Train A Diesel Generator Operability Surveillance;
*
Unit 1 Train A Solid State Protection System Surveillance;
*
Unit 2 K636 Engineered Safety Features (ESF) Relay Surveillance; and
*
Unit 2 K644 ESF Relay 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, demonstrate operational readiness, and
consistent with the system design basis;
*
was plant equipment calibration correct, accurate, and properly documented;
*
were as left setpoints within required ranges; and was the calibration frequency
in accordance with TSs, the UFSAR, plant procedures, and applicable
commitments;
*
was measuring and test equipment calibration current;
*
was the test equipment used within the required range and accuracy and were
applicable prerequisites described in the test procedures satisfied;
*
did test frequencies meet TS requirements to demonstrate operability and
reliability; 
*
were tests performed in accordance with the test procedures and other
applicable procedures; 
*
were jumpers and lifted leads controlled and restored where used;
*
were test data and results accurate, complete, within limits, and valid;
13
Enclosure
*
was test equipment removed following testing;
*
where applicable for in-service testing activities, was testing performed in
accordance with the applicable version of Section XI of the American Society of
Mechanical Engineers (ASME) Code, and were reference values consistent with
the system design basis;
*
was the unavailability of the tested equipment appropriately considered in the
performance indicator data;
*
where applicable, were test results not meeting acceptance criteria addressed
with an adequate operability evaluation, or was the system or component
declared inoperable;
*
where applicable for safety-related instrument control surveillance tests, was the
reference setting data accurately incorporated into the test procedure;
*
was equipment returned to a position or status required to support the
performance of its safety function following testing;
*
were all problems identified during the testing appropriately documented and
dispositioned in the licensees CAP;
*
where applicable, were annunciators and other alarms demonstrated to be
functional and were annunicator and alarm setpoints consistent with design
documents; and 
*
where applicable, were alarm response procedure entry points and actions
consistent with the plant design and licensing documents.
Documents reviewed are listed in the Attachment.
This inspection constituted five routine surveillance testing samples as defined in
IP 71111.22, Sections -02 and -05.
b.
Findings
No findings were identified.
1EP6 Drill Evaluation (71114.06)
.1
Training Observation
a.
Inspection Scope 
The inspectors observed a simulator training evolution for licensed operators on
January 31, 2013, which required Emergency Plan implementation by a licensee
operations crew.  This evolution was planned to be evaluated and included in
performance indicator data regarding drill and exercise performance.  The inspectors
observed event classification and notification activities performed by the crew.  The
inspectors also attended the post-evolution critique for the scenario.  The focus of the
inspectors activities was to note any weaknesses and deficiencies in the crews
performance and ensure that the licensee evaluators noted the same issues and entered
them into the CAP.  As part of the inspection, the inspectors reviewed the scenario
package and other documents listed in the Attachment. 
This inspection constituted one training evolution with emergency preparedness drill
sample as defined in IP 71114.06-05.
14
Enclosure
b.
Findings
No findings were identified.
2.
RADIATION SAFETY
2RS4 Occupational Dose Assessment (71124.04)
This inspection constituted a partial sample as defined in IP 71124.04-05.
.1
External Dosimetry (02.02)
a.
Inspection Scope
The inspectors evaluated whether the licensees dosimetry vendor is National Voluntary
Laboratory Accreditation Program (NVLAP) accredited and if the approved irradiation
test categories for each type of personnel dosimeter used were consistent with the types
and energies of the radiation present and the way the dosimeter was being used (e.g., to
measure deep dose equivalent, shallow dose equivalent, or lens dose equivalent). 
b.
Findings
No findings were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1
Unplanned Scrams Per 7000 Critical Hours
a.
Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams Per 7000 Critical
Hours Performance Indicator (PI) for both Unit 1 and Unit 2 for the period from the first
quarter 2012 through the fourth quarter 2012.  To determine the accuracy of the PI data
reported during those periods, PI definitions and guidance contained in Nuclear Energy
Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 6, dated October 2009, were used.  The inspectors reviewed the licensees
operator narrative logs, IRs, event reports and NRC Integrated Inspection Reports for
the period of January 2012 through December 2012 to validate the accuracy of the
submittals.  The inspectors also reviewed the licensees IR database to determine if any
problems had been identified with the PI data collected or transmitted for this indicator. 
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.
Findings
No findings were identified.
15
Enclosure
.2
Unplanned Scrams with Complications
a.
Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams with
Complications PI for Unit 1 and Unit 2 for the period from the first quarter 2012 through
the fourth quarter 2012.  To determine the accuracy of the PI data reported during those
periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 6, dated October 2009, were used.  The
inspectors reviewed the licensees operator narrative logs, IRs, event reports and NRC
Integrated Inspection Reports for the period of January 2012 through December 2012 to
validate the accuracy of the submittals.  The inspectors also reviewed the licensees IR
database to determine if any problems had been identified with the PI data collected or
transmitted for this indicator.  Documents reviewed are listed in the Attachment .
This inspection constituted two unplanned scrams with complications samples as
defined in IP 71151-05.
b.
Findings
No findings were identified.
.3
Unplanned Power Changes Per 7000 Critical Hours
a.
Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Power Changes Per
7000 Critical Hours PI for Unit 1 and Unit 2 for the period from the first quarter 2012
through the fourth quarter 2012.  To determine the accuracy of the PI data reported
during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were
used.  The inspectors reviewed the licensees operator narrative logs, IRs, maintenance
rule records, event reports, and NRC Integrated Inspection Reports for the period of
January 2012 through December 2012 to validate the accuracy of the submittals.  The
inspectors also reviewed the licensees IR database to determine if any problems had
been identified with the PI data collected or transmitted for this indicator.  Documents
reviewed are listed in the Attachment.
This inspection constituted two unplanned power changes per 7000 critical hours
samples as defined in IP 71151-05.
b.
Findings
No findings were identified.
16
Enclosure
4OA2 Identification and Resolution of Problems (71152)
.1
Routine Review of Items Entered into the Corrective Action Program
a.
Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensees CAP at
an appropriate threshold, that adequate attention was being given to timely corrective
actions, and that adverse trends were identified and addressed.  Attributes reviewed
included the complete and accurate identification of the problem; that timeliness was
commensurate with safety significance; that evaluation and disposition of performance
issues, generic implications, common causes, contributing factors, root causes, extent-
of-condition reviews, and previous occurrence reviews were proper and adequate; and
that the classification, prioritization, focus, and timeliness of corrective actions were
commensurate with safety and sufficient to prevent recurrence of the issue.  Minor
issues entered into the licensees CAP as a result of the inspectors observations are
listed in the Attachment.
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples.  Instead, by procedure they were considered an
integral part of the inspections performed during the quarter and documented in
Section 1 of this report.
b.
Findings
No findings were identified.
.2
Daily Corrective Action Program Reviews
a.
Inspection Scope
To facilitate the identification of repetitive equipment failures and human performance
issues for follow-up, the inspectors performed a daily screening of items entered into the
licensees CAP.  This review was accomplished through inspection of the stations daily
IR packages.
These daily reviews were performed by procedure as part of the inspectors daily plant
status monitoring activities and, as such, did not constitute any separate inspection
samples.
b.
Findings
No findings were identified.
17
Enclosure
.3
Selected Issue Follow-Up Inspection:  Actions to Address Engineering-Related Issues
Identified at Braidwood During NRC Inspections
a.
Inspection Scope
The inspectors reviewed evaluations and calculations as well as related IRs to assess
the adequacy of the licensees extent-of-condition review of issues identified during the
Braidwood Station Unit 1 and Unit 2 Evaluation of Changes, Tests, or Experiments and
Permanent Plant Modifications inspections performed in 2011. 
This review included an analysis that was performed by the licensee to determine the
effects of lead shielding on the Unit 1 Safety Injection (SI) system piping subsystem and
associated pipe supports. 
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b.
Findings
Embedment Plate Design Deficiencies 
Introduction:  The inspectors identified a finding of very low safety significance (Green)
and an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B,
Criterion III, Design Control, when licensee personnel failed to properly evaluate the
structural steel embedment plate which supported SI pipe supports 1SI06025V and
1SI06030S. 
Description:  The SI system is part of the emergency core cooling system (ECCS). 
Section 6.3.1 of the Byron UFSAR stated, in part, that the primary function of the ECCS
is to remove the stored and fission product decay heat from the reactor during accident
conditions and provide shutdown capability for design basis accidents by means of
boron injection. 
Piping Subsystem 1SI06 is part of the SI System and is a safety-related ASME Class II,
Seismic Category I subsystem located in the curved wall area of the auxiliary building.  A
structural steel embedment plate that supports safety-related pipe supports 1SI06025V
and 1SI06030S is located in the auxiliary building, which is a Seismic Category I
structure.  Section 3.8.4.5.2 of the UFSAR describes requirements for structural steel
design inside the auxiliary building and states, in part, The stresses and strains of
structural steel are limited to those specified in the AISC (American Institute of Steel
Construction)  Also, this section required that stresses be held within the elastic range
and that no plastic deformation was allowed.
The inspectors reviewed Calculation No. 13.2.29BY, Mechanical Component Support
1SI06025V, Revision 2X that evaluated pipe supports 1SI06025V and 1SI06030S. 
These supports were attached to a structural embedment plate in the auxiliary building. 
The structural steel embedment plate evaluation was also included in this calculation. 
During a review of Calculation No. 13.2.29BY, the inspectors identified a number of
concerns, including the following:
18
Enclosure
*
The calculated bending stress on the embedment plate was greater than the
allowable bending stress by about 67 percent and the licensee relied on engineering
judgment to demonstrate compliance with the design and licensing basis
requirements; 
*
The calculation used the actual instead of minimum material yield stress of the
embedment plate to calculate the allowable bending stress;
*
The calculation used an acceptance criteria which permitted plastic or permanent
deformation through yielding of the structural steel embedment plate and
redistribution of stresses in the embedment plate due to applied loads; 
*
The calculation did not include an evaluation for severe environmental load
combinations as described in UFSAR Table 3.8-9 and as described in UFSAR
Section 3.8.4.3, Loads and Loading Combinations; and
*
The calculation did not consider applied stresses due to self-weight and self-weight
seismic excitation of tube steel pipe support members.
The inspectors determined that the engineering judgment used to demonstrate
compliance with the design and licensing basis was not valid because the AISC required
that the allowable bending stress be determined using the minimum yield stress of the
material.  In addition, UFSAR Section 3.8.4.5.2 specified no plastic or permanent
deformation due to applied stresses.  The inspectors also identified that the structural
steel embedment plate was not qualified for the severe environmental load combination
as described in UFSAR Table 3.8-9 and as required by UFSAR Section 3.8.4.3. 
The licensee entered this issue into their CAP as IR 1478188, NRC Identified Use of
CMTR in a 80's Calculation.  As part of their immediate corrective actions, the licensee
performed an operability evaluation and concluded the structural steel embedment plate
was operable, but nonconforming.
Analysis:  The inspectors determined that the failure to design the structural steel
embedment plate which supported pipe supports 1SI06025V and 1SI06030S in
accordance with AISC and Seismic Category I linear elastic requirements was a
performance deficiency.
The inspectors determined that the performance deficiency was more than minor
because it was associated with the Design Control attribute of the Mitigating Systems
Cornerstone and adversely affected the cornerstone objective of ensuring the
availability, reliability, and capability of systems that respond to initiating events to
prevent undesirable consequences (i.e., core damage).  Specifically, the licensee did not
demonstrate that the structural steel embedment plate which supported pipe supports
1SI06025V and 1SI06030S would maintain structural linear elastic integrity when
subjected to design loads.
The inspectors reviewed Attachment 0609.04, Initial Characterization of Findings,
Table 3 - SDP Appendix Router.  The inspectors answered No to all of the questions in
Sections A through E of Table 3 and therefore the finding was evaluated using the SDP
in accordance with IMC 0609, The Significance Determination Process (SDP) for
Findings At-Power, Appendix A, Exhibit 2, Mitigating Systems Screening
19
Enclosure
Questions.  The inspectors answered Yes to Question 1 - If the finding is a deficiency
affecting the design or qualification of a mitigating SSC [Structure, System, or
Component], does the SSC maintain its operability or functionality?  Specifically, the
design deficiency was confirmed not to result in a loss of operability of the structural
steel embedment plate.  Therefore, the finding was determined to have very low safety
significance (Green).  The inspectors performed an independent review of the operability
evaluation and had no further concerns. 
The inspectors did not identify a cross-cutting aspect associated with this finding
because the calculation was from the 1980s and was therefore not representative of
current performance. 
Enforcement:  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 the design, such as by the performance of design reviews, by the use of alternate or
simplified calculational methods, or by the performance of a suitable testing program. 
Piping Subsystem 1SI06 is part of the Safety Injection System and is a safety-related
ASME Class II, Seismic Category I subsystem located in the curved wall area of the
auxiliary building.  A structural steel embedment plate that supports safety-related pipe
supports 1SI06025V and 1SI06030S is located in the auxiliary building, which is a
Seismic Category I structure.  Section 3.8.4.5.2 of the UFSAR describes requirements
for structural steel design inside the auxiliary building and states, in part, The stresses
and strains of structural steel are limited to those specified in the AISC.  Also,
Section 3.8.4.5.2 of the UFSAR required that stresses be within the elastic range and
that no plastic deformation was allowed.
Contrary to the above, from initial construction to February 21, 2013, the licensee failed
to demonstrate the design adequacy of the embedment plate which supported safety-
related Safety Injection pipe supports 1SI06025V and 1SI06030S.  Specifically, the
design for the structural steel embedment plate which supported safety-related Safety
Injection pipe supports 1SI06025V and 1SI06030S was inadequate, in that Calculation
No. 13.2.29BY, Mechanical Component Support 1SI06025V, Revision 2X, which was a
quality calculation, did not demonstrate that the embedment plate would meet AISC and
Seismic Category I linear elastic requirements.
Because this violation was of very low safety significance and it was entered into the
licensees CAP as IR 1478188, this violation is being treated as a NCV, consistent with
Section 2.3.2 of the NRC Enforcement Policy.  As part of their immediate corrective
actions, the licensee performed an operability evaluation and concluded the structural
steel embedment plate was operable.  (NCV 05000454/2013002-01, Embedment
Plate Design Deficiencies)
.4
Selected Issue Follow-Up Inspection: Valves in LCO Due to Abandonment
a.
Inspection Scope
During a review of items entered in the licensees CAP, the inspectors identified an
IR regarding equipment that had been abandoned in place.  Specifically, IR 1306607,
Long Term LCO [Limiting Condition for Operation] Extent of Condition Review Per
IR 1298667, characterized a series of valves as abandoned.  The valves were also
20
Enclosure
characterized as having a containment isolation function.  The inspectors reviewed the
licensees procedures associated with containment leak rate testing and recent test data
to ensure that the performance of the abandoned valves remained acceptable. 
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b.
Findings
No findings were identified.
4OA5  Other Activities
.1
(Closed) NRC Temporary Instruction (TI) 2515/187 - Inspection of Near-Term Task
Force Recommendation 2.3 Flooding Walkdowns
As discussed in NRC Integrated Inspection Report 05000454/2012005;
05000455/2012005, the inspectors previously verified that licensee walkdown packages
Unit 1 13-Line Wall, Unit 1 1A and 1D Main Steam Isolation Valve Room Probable
Maximum Precipitation (PMP) Curb, and River Screen House Penetration RH-15C,
contained the elements specified in Nuclear Energy Institute (NEI) 12-07, Guidelines for
Performing Walkdowns of Plant Flood Protection Features.
During the previous quarter, the inspectors accompanied the licensee on their walkdown
of the River Screen House, Penetration RH-15C; and Unit 1 A and D Main Steam
Isolation Valve Room PMP Curb and verified that the licensee confirmed the following
flood protection features: 
*
Visual inspection of the flood protection feature was performed if the flood
protection feature was relevant.  External visual inspection for indications of
degradation that would prevent its credited function from being performed was
performed.
*
Critical SSC dimensions were measured.
*
Available physical margin, where applicable, was determined.
*
Flood protection feature functionality was determined using either visual
observation or by review of other documents.
During this quarter, the inspectors conducted additional independent walkdowns to verify
licensee compliance with inspection guidance contained in TI 2515/187.  The area
selected was the building that houses the spent fuel pool, the fuel handling building
(FHB).  There were several reasons for selecting this area.  For example, the spent fuel
pool filtering and heat removal systems are located in the FHB.  In addition, the FHB has
access ways that lead to other portions of the auxiliary building, a safety-related
structure.
The Byron UFSAR identified that the FHB was not subject to flooding.  The inspectors
questioned why the FHB would not be subject to flooding since portions of it are at
ground level, a roll-up door in this building leads to an adjacent structure which has a
21
Enclosure
roll-up door that leads outside, and railway channels in the FHB have been observed to
contain rain water.
The inspectors verified that noncompliances with current licensing requirements, and
issues identified in accordance with the 10 CFR 50.54(f) letter, Item 2.g of Enclosure 4,
were entered into the licensee's CAP.  In addition, issues identified in response to Item
2.g that could challenge risk significant equipment and the licensees ability to mitigate
the consequences will be subject to additional NRC evaluation.
.2
Failure to Properly Scope All the Pertinent External Flood Protection Features into
Walkdown Lists in Accordance with Nuclear Energy Institute (NEI) 12-07 
Introduction:  The inspectors identified a finding of very low safety significance (Green)
when licensee personnel failed to develop inspection lists that included all external flood
protection features credited in current licensing bases (CLB) documents as specified in
NEI 12-07, Guidelines for Performing Walkdowns of Plant Flood Protection Features. 
Specifically, the inspection lists did not include several passive components in the FHB
which were an essential element of the Byron flood mitigation strategy.
Description:  The inspectors reviewed the licensees inspection and walkdown
documents associated with flooding reviews performed in accordance with NEI 12-07,
Guidelines for Performing Walkdowns of Plant Flood Protection Features, in response
to a letter from the NRC to licensees pursuant to 10 CFR 50.54(f).  During the review,
the inspectors identified that the licensee had completed their scoping of components for
TI 2515/187, Inspection of Near-Term Task Force Recommendation 2.3 Flooding
Walkdowns, and failed to properly scope all flood protection features credited in the
CLB documents for flooding events.  Specifically, while reviewing the Flooding Features
Walkdown List used to inspect and test design bases flood mitigating equipment in
accordance with the NRC-endorsed guidance of NEI 12-07, the inspectors identified that
the flood protection features in the FHB were not included.  The flood protection features
in the FHB were designed to protect the auxiliary building, including residual heat
removal and containment spray pumps from site external flooding scenarios, and were
an essential part of the Byron design basis flood mitigation strategy.  In particular, the
concrete steps inside the FHB were designed to prevent flood waters that enter the FHB
from reaching a door that would allow water to enter the auxiliary building.
Because the licensee did not adequately follow the guidance in NEI 12-07 and identify
components in the FHB that served as passive flooding barriers, these components
were not scheduled for visual inspections or walkdowns.  As a result, the licensee failed
to recognize walkdowns of these passive flooding barriers were required to adequately
respond to the March 12, 2012 letter from the NRC to licensees that discussed these
reviews.  The licensee acknowledged that they may not have identified these flood
barriers during subsequent reviews if the inspectors had not identified the issue.
The licensee entered this issue into their CAP as IR 1466355, Update UFSAR
Regarding External Flooding.  Corrective actions included plans to perform an
inspection of the NRC-identified passive flooding features that were omitted from the
inspection lists and an extent-of-condition review.
Analysis:  The inspectors determined that the failure to include concrete flood barriers in
the FHB in the flooding inspection lists developed to address NEI 12-07, although these
22
Enclosure
passive components were a critical element of the Byron flood mitigation strategy, was a
performance deficiency. 
Using the guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B,
Issue Screening, the inspectors determined this finding affected the Mitigating Systems
Cornerstone.  The inspectors determined that the performance deficiency was more than
minor because it was associated with the Protection Against External Factors (Flood
Hazard) attribute of the Mitigating Systems Cornerstone and adversely affected the
cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences (i.e., core
damage).  Specifically, the concrete flood barriers in the FHB protecting important
safety-related equipment in the auxiliary building as well as the flood barriers for the
spent fuel pool cooling pumps were not properly scoped into the licensees walkdown
lists.
The inspectors reviewed Attachment 0609.04, Initial Characterization of Findings,
Table 3 - SDP Appendix Router.  The inspectors answered No to all of the questions in
Sections A through E of Table 3 and therefore the finding was evaluated using the SDP
in accordance with IMC 0609, The Significance Determination Process (SDP) for
Findings At-Power, Appendix A, Exhibit 2, Mitigating Systems Screening
Questions.  The inspectors answered No to Question B for the External Event
Mitigation Systems - Does the finding involve the loss or degradation of equipment or
function specifically designed to mitigate a seismic, flooding, or severe weather initiating
event (e.g., seismic snubbers, flooding barriers, tornado doors)?  Therefore, the finding
was determined to have very low safety significance (Green). 
This finding had a cross-cutting aspect in the Work Practices component of the Human
Performance cross-cutting area because licensee personnel did not properly apply
human error prevention techniques such as peer checking and proper documentation of
activities [H.4(a)].
Enforcement:  This finding did not involve enforcement action because no violation of a
regulatory requirement was identified.  Because this finding does not involve a violation
and is of very low safety significance, it is identified as a finding (FIN).  (FIN
05000454/2013002-02; 05000455/2013002-02, Failure to Properly Scope All
Pertinent External Flood Protection Features into Walkdown Lists in Accordance
with Industry Guidance NEI 12-07)
.3
(Closed) Unresolved Item 05000454/2011005-03; 05000455/2011005-03:  Use of
Thermolumiscent Dosimeters May Not Be Consistent With the Methods Used By the
National Voluntary Laboratory Accreditation Program Accreditation Process
In the fourth quarter of 2011, the inspectors identified that the licensees use of
thermoluminescent dosimeters (TLDs) may not be consistent with the methods used by
the NVLAP accreditation process.  Specifically, the licensee used a vendor to supply and
process dosimeters that measure radiation exposure for the monitored workers.  This
vendor is NVLAP-accredited for beta, gamma, neutron, mixture of beta/gamma, and
mixture of neutron/gamma radiations.  However, the licensee used the TLDs when
workers may be exposed to beta, gamma, and neutron radiations within the same
monitoring period.  The inspectors determined that this mixture of three radiation types
may not be aligned with the accreditation process, and opened Unresolved Item (URI)
23
Enclosure
05000454/2011005-03; 05000455/2011005-03 to evaluate the issue.  The inspectors
requested technical assistance from the Office of Nuclear Reactor Regulation (NRR)
through Task Interface Agreement (TIA) 2012-05 (ML 12268A330), the results of which
are discussed below.
Title 10 CFR 20.1501(c)(2) requires that the dosimeter processor be approved for the
type of radiation or radiations included in the NVLAP program that most closely
approximates the type of radiation or radiations for which the individual wearing the
dosimeter is monitored.  As there is no NVLAP test category for dosimeters exposed to a
mixture of beta, gamma, and neutron radiations, the NRC has determined that licensees,
which monitor for beta, gamma, and neutron exposure with a single dosimeter, need to
use a processor that is NVLAP accredited in categories for beta-photon mixtures and
neutron-photon mixtures.  The licensees dosimetry processor was NVLAP accredited
for both beta-photon and neutron-photon mixtures and therefore was in compliance with
10 CFR 20.1501(c)(2).
Notwithstanding the paragraph above, licensees are required to provide adequate
monitoring in accordance with 10 CFR 20.1502(a).  For any type of in-field use
practice that can introduce error in the monitoring results (dependent upon the type of
dosimeter and processing method), it becomes a question of compliance with the
monitoring requirements of 10 CRR 20.1502(a) and not of NVLAP accreditation
requirements of 10 CFR 20.1501(c)(2).  As described in TIA 2012-05, another licensee
had performed a study with the same dosimeters used by Byron (Harshaw 760).  This
study demonstrated that exposing a single Harshaw 760 dosimeter to a mixture of beta,
gamma, and neutron radiation met industry standards for accuracy and precision. 
Therefore, the licensee provided adequate monitoring and was in compliance with
10 CFR 20.1502(a).
The inspectors determined that no performance deficiency existed; therefore this URI is
closed.
4OA6  Management Meetings
.1
Exit Meeting Summary
On April 4, 2013, the inspectors presented the inspection results to Mr. B. Youman,
Byron Plant Manager, and other members of the licensees staff. 
The licensee acknowledged the issues presented.  The inspectors confirmed that none
of the potential report input discussed was considered proprietary.
.2
Interim Exit Meetings
*
The inspection results for the area of occupational dose assessment were
discussed with Mr. B. Burton, Radiation Protection Manager, on March 26, 2013.
*
The inspection results for the area of lead shielding and pipe supports were
discussed with Ms. A. Corrigan, Mechanical Design Manager, and                   
Mr. E. Blondin, Design Engineering Manager, on March 26, 2013.
The licensee acknowledged the issues presented.  The inspectors confirmed that none
of the potential report input discussed was considered proprietary.
24
Enclosure
ATTACHMENT:  SUPPLEMENTAL INFORMATION
1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
R. Kearney, Site Vice President
B. Youman, Plant Manager
B. Askren, Security Manager
B. Barton, Radiation Protection Manager
S. Briggs, Operations Director
A. Creamean, Chemistry Manager
S. Gackstetter, Training Manager
D. Gudger, Regulatory Assurance Manager
E. Hernandez, Engineering Director
D. Horstmann, Business Operations
B. Spahr, Maintenance Director
E. Topping, Nuclear Oversight Manager
Nuclear Regulatory Commission
E. Duncan, Chief, Branch 3, Division of Reactor Projects
B. Bartlett, Byron Senior Resident Inspector
J. Robbins, Byron Resident Inspector
Illinois Emergency Management Agency (IEMA)
R. Zuffa, IEMA
2
Attachment
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000454/2013002-01
NCV
Embedment Plate Design Deficiencies (Section 4OA2.3)
05000454/2013002-02;
05000455/2013002-02
FIN
Failure to Properly Scope All Pertinent External Flood
Protection Features into Walkdown Lists in Accordance with
Industry Guidance NEI 12-07 (Section 4OA5.2)
Closed
05000454/2013002-01
NCV
Embedment Plate Design Deficiencies (Section 4OA2.3)
05000454/2013002-02;
05000455/2013002-02
FIN
Failure to Properly Scope All Pertinent External Flood
Protection Features into Walkdown Lists in Accordance with
Industry Guidance NEI 12-07 (Section 4OA5.2)
TI 2515/187
TI
Inspection of Near-Term Task Force Recommendation 2.3
Flooding Walkdown (Section 4OA5.1)
05000454/2011005-03;
05000455/2011005-03
URI
Use of TLDs May Not Be Consistent With the Methods Used
by the NVLAP Accreditation Process (Section 4OA5.3)
3
Attachment
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection.  Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort.  Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
Section 1R04
- BOP WO-E4; Control Room Chilled Water Electrical Lineup, Revision 2
- BOP WO-M3; Control Room Chilled Water Valve Lineup, Revision 10
Section 1R06
- BAR 0PL02J-3-B2; ESW Sump 2 Level High High, Revision 52
- IR 1413893; Unit 1 SX Alpha Sump Pump Check Valve is Sticking Open, September 16, 2012
- M-48; Diagram of Miscellaneous Sumps and Pumps, Revision AE
Section 1R11
- IR 1486687; Unexpected Unit 1 PDMS Alarms Due to Failing CETC, March 12, 2012
Section 1R12
- IR 1487650; Potential Corporate Elevation for Byron Maintenance, March 12, 2013
- IR 1479105; Unit 1 Gain POT R303 for N-43 Not Functioning Properly, February 22, 2013
- Byron Station Maintenance Rule Expert Panel Meeting Notes, November 5, 2009
- Byron Station Maintenance Rule Expert Panel Meeting Notes, December 18, 2009
- Byron Station Maintenance Rule Expert Panel Meeting Notes, June 7, 2011
- Byron Station Maintenance Rule Expert Panel Meeting Notes, November 3, 2011
- IR 1214163; Common Cause Analysis for MCCB for MCC 134Y2-A4, June 2, 2011
- ER-AA-310-1005; (A)(1) Determination Template for IR 1207922, Revision 5
- ER-AA-310-1005; (A)(1) Determination Template for IR 1207931, Revision 5
- Byron Station Maintenance Rule Periodic Assessment #11, January 2011 - June 2012
Section 1R13
- IR 1474028; 2A CV Pump Gear Box Failed to Develop Oil Pressure on Start,
February 12, 2013
- IR 1474042; 2A CV Pump Gear Oil Pressure Guage Stuck at 0 Psig, February 12, 2013
Section 1R15
- IR 1413971; Byron OAD Investigated and Identified an Abnormal Indication of the Over
Current Relay, October 11, 2012
- NSWP-S-05; Concrete Expansion Anchors, Revision 7
- Calculation 7.16.10.2-BYR97-229; Structural Evaluation of Battery Racks and the Mounting
Details in 111 and 112 Battery Rooms of the Auxiliary Building, Revision 4
- Drawing 6E-0-3391AY; 125V DC Battery Rack Mounting Details
- Drawing M-11978; Bus 111 & 211 125V DC L Two Step EP3 Racks, Revision 2
4
Attachment
- Drawing 6E-0-3391AH; Byron Station Unit 1& 2, Electrical Equipment Mounting Details,
Revision S
- Drawing 64-05906; Floor Rack - Two Step EQ Protected for Plate Size 3 and 4 Batteries,
Revision 0
- CC-AA-112; Temporary Configuration Changes, Revision 19
- EC 378402; Single Use Evaluation for 1/2 of SX Cubical Coolers Not Available, January 6, 2010
- EC 392429; Operation of SX Pump with Single Cubical Cooler, February 12, 2013
- IR 1465872; Review of Braidwood IR 1459353 - PZR PORV Accumulator Pressure,
January 22
- CN-RRA-00-47; Calculational Table for Byron and Braidwood Natural Circulation Cooldown,
Revision 1
Section 1R18
- Performance Verification Testing; RCFC Check Dampers for Byron Units 1 and 2, July 1981
- Sargent & Lundy Fan Check Dampers for Byron Units 1 and 2, March 5, 1985
- Material and Equipment Receiving and Inspection Report CECo Engineering and
Construction, June 30, 1981
- Material and Equipment Receiving and Inspection Report CECo Engineering and
Construction, June 30, 1981
- Q.F.2910.24; Project No. 4391-05, Tornado/Isolation Dampers, May 11, 1981
- Q.F.2910.24; Project No. 4392-05, Tornado/Isolation Dampers, May 11, 1981
- IR 1419184; RCFC Damper Missing Springs; September 27, 2012
- IR 1419189; RCFC Damper Missing Springs; September 27, 2012
- IR 1419190; RCFC Damper Missing Springs; September 27, 2012
- IR 1419192; RCFC Damper Missing Springs; September 27, 2012
- IR 1474498; NRC Follow-Up - RCFC Discharge Check Damper; February 7, 2013
Section 1R19
- IR 1473967; No SX PP Cubicle Cooler Tubesheet Degradation Margin Exists,
February 11, 2013
- WO 1493809; 214 Instrument Inverter EOC Walkdown Due to 211 INV Failure, Revision 1
- WO 1591475; 1SX01PA Comprehensive IST Required for Essential Service Water Pump,
February 14, 2013
- BOP IP-1; Instrument Bus Inverter Startup, Revision 14
- IR 1472776; ACB 1442 Drives On-Line Risk Yellow for Both Units, February 8, 2013
- IR 1473015; Lockout Relay 486-1442 for Breaker 1442 is Degraded, February 8, 2013
- WO 1237471; Bus 144 Sat 142-2 Feed (ACB 1442) RES OC Relay Routine, February 8, 2013
- WO 1444425; Replace Lockout Relay on ACB 1442, February 9, 2013
- WO 1591475; 1SX01PA Comprehensive IST Requirement for Essential Service Water Pump,
February 14, 2013
- WO 1418630; Support Eddy Current Testing for 1A SX Pump Cubical Cooler,
February14, 2013
- WO 1366902; Operation Run Cooler and Check for Proper Operation, February 14, 2013
- WO 1314236; Preventative Maintenance on Breaker SAT Feed, February 14, 2013
Section 1R20
- OP-AA-101-113-1004; Equipment Prompt: 2A Generator Stator Cooling Water Pump (2A GC)
Tripped, Revision 24
5
Attachment
- IR 1490321; Smoke Noticed Coming from the 2A FW Pump Motor, March 20, 2013
- IR 1490323; DRPI POD M-12 Indicated General Warning Following Reactor Trip, March 20,
2013
- IR 1493026; Smoke was Reported Coming from U2 Voltage Regulator Cabinet,
March 20, 2013
- IR 1490315; U-2 Reactor Trip - Loss of GC, March 20, 2013
- IR 1490330; Oil Leaking From Exciter End of Main Generator, March 20, 2013
- IR 1490407; Need Cleanup of Generator Oil Leak in Various TB Elevations, March 21, 2013
- IR 1490453; U2 RCDT Elevated Inputs Investigation, March 21, 2013
- IR 1490635; Following U2 Reactor Trip, 2AR11J went Dark Blue and then White,
March 21, 2013
Section 1R22
- 1BOSR 3.1.5-1; Train A Solid State Protection System Surveillance, Revision 32
- WO 1469526 01; ESF Relay Train Reactor Trip - K636/2FW039S, February 25, 2013
- IR 631199; Revise Unit Two Schematic Diagram 6E-2 4030FW56, May 18, 2007
- IR 848809; 12/15 E-3 Schedule Review, November 23, 2008
- IR 1064332; Inadequate Technical Information Provided for New SSPS Cards, May 2, 2010
- IR 1293130; UV Driver Card Vulnerability in OE 34462 Applicable at Byron,
November 21, 2011
- IR 1323037; Unexpected FWI While Closing RX Trip Breakers, February 5, 2012
- IR 1328319; Unexpected Ground Reading During SSPS Surveillance, February 17, 2012
- IR 1329012; Unexpected FWI While Closing RX Trip Breakers, February 20, 2012
- IR 1329908; Low Contact Volts Found During SSPS - Not Unusual, February 21, 2012
- IR 1374658; Low Voltage Reading During 2BOSR 3.1.5-2, June 5, 2012
- WO 1588151; 1CS01PB Comprehensive IST Requirements for Containment Spray Pump,
January 29, 2013
- BOP CS-5; Containment Spray System Recirculation to the RWST, Revision 11
- WO 1609614; 1A Diesel Generator Operability Surveillance, February 6, 2013
- 1BOSR 8.1.2-1; Unit 1 Train A Diesel Generator Operability Surveillance, Revision 20
- WO 1596040; ESF Relay Train B CS-K644 ESFAS Instrumentation ESF Relay Surveillance,
February 28, 2013
- WO 1597146; 2CS01PB Comprehensive IST Requirements for Containment Spray Pump,
February 28, 2013
Section 2RS4
- Final Response to Task Interface Agreement 2012-05; ML12268A330; October 16, 2012
Section 4OA1
- Power History Curves for Unit 1 and Unit 2, January 2012 through December 2012
- Perfomance Indicator Data as Reported for the Period January 2012 through December 2012
- IR 1319908; B2F26 U2 Reactor Trip Due To Electrical Fault and Unusual Event,
January 30, 2012
- IR 1323547; B2F27 Manual Reactor Trip and Manual Auxiliary Feedwater Actuation,
February 6, 2012
6
Attachment
Section 4OA2
- IR 1474066; Issues With SX to CC MOD Installation, February 11, 2013
- IR 1477430; Insufficient  Insertion of Anti-Vibration Bars in Alloy 600, February 19, 2013
- IR 1413971; EACE - 1B RH Pump Trip Due to CO-5 Overcurrent Relay Operation,
September 17, 2012
- IR1272187; Issues Applicable to Byron from Bwd Mod/50.59 Inspection; October 4, 2011
- IR 1296141; NER NC-11-045-Y Fleet Wide Actions; September 28, 2011
- Byron Document No. DS-MC-01-BY; Certification of Design Specification for Primary
Containment Piping Penetration Assemblies; Revision 3
- Byron/Braidwood Document No. 01-10-52; Bryon/Braidwood Piping Design Specification;
Revision 2
- Calculation No. 13.2.29BY; Mechanical Component Support 1SI06025V; Revision 2X
- ER-AA-380; Primary Containment Leakrate Testing Program, Revision 9
- BVP 800-39; Primary Containment Leakrate Testing Program, Revision 10
- 1BOSR 6.1.1-19; Unit 1 Primary Containment Type C Leakage Rate Tests and IST Tests of
the OffGas System, Revision 8
- 2BVSR 6.1.1-24; Unit 2 Summation of Primary Containment Type B & C Local Leakage Tests
for Acceptance Criteria, Revision 12
- 1BVSR 6.1.1-24; Unit 2 Summation of Primary Containment Type B & C Local Leakage Tests
for Acceptance Criteria, Revision 15
- IR 1298667; Long Term LCO for VQ Valves Needs Resolution, December 6, 2011
- IR 1306607; Long Term LCO Extent of Condition Review Per IR 1298667, December 26, 2011
- EC 390536; Determine Acceptability of Code Case N-597-2 use on FAC Components
1FW085B/D, Revision 0
- IR 1412470; B1R18 FAC Component 1FW085B Exam Failure, September 13, 2012
- IR 1415327; B1R18 FAC Component 1FW085D Exam Failure, September 13, 2012
Corrective Action Documents As a Result of NRC Inspection
- IR 1487707; NRC ID UFSAR Discrepancy-Appendix A, Page A.1.57-1; March 14, 2013
- IR 1478188; NRC Identified Use of CMTR in a 80's Calculation; February 21, 2013
- IR 1490153; NRC/IEMA 1A DG HELB Modification Walkdown; March 20, 2013
- IR 1493278; NRC IDed: PDP 50.59 Enhancement Required, March 27, 2013
Section 4OA5
- IR 1466355; FUK: Update UFSAR Regarding External Flooding, January 24, 2013
- IR 1472808; FUK: Effect of Local Intense Precipitation on FHB and SFP PP, February 8, 2013
- IR 1474686; FUK: Concrete Steps on 401 FHB to Areas 5 & 7, February 13, 2013
- IR 1475877; Blockwall Penetrations in SFP Pump Room, February 15, 2013
- IR 1484749; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013
- IR 1484755; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013
- IR 1484758; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013
- IR 1484765; FUK: MCC 132X3 Fasteners Seismic Walkdown, March 7, 2013
- IR 1484768; FUK: MCC 131X3 Fasteners Seismic Walkdown, March 7, 2013
Corrective Action Documents As a Result of NRC Inspection
-IR 1453636; FUK: Flooding and Seismic Walkdowns, December 18, 2012
7
Attachment
LIST OF ACRONYMNS USE
ADAMS
Agencywide Document Access and Management System
AISC
American Institute of Steel Construction
ASME
American Society of Mechanical Engineers
CAP
Corrective Action Program
CFR
Code of Federal Regulations
CLB
Current Licensing Basis
ECCS
Emergency Core Cooling System
ESF
Engineered Safety Feature
FHB
Fuel Handling Building
FIN
Finding
FSAR
Final Safety Analysis Report
IMC
Inspection Manual Chapter
IP
Inspection Procedure
IR
Inspection Report
IR
Issue Report
LCO
Limiting Condition for Operation
NCV
Non-Cited Violation
NEI
Nuclear Energy Institute
NRC
U.S. Nuclear Regulatory Commission
NRR
Office of Nuclear Reactor Regulation
NVLAP
National Voluntary Laboratory Accreditation Program
PARS
Publicly Available Records System
PI
Performance Indicator
PMP
Probable Maximum Precipitation
PORV
Power-Operated Relief Valve
RCFC
Reactor Containment Fan Cooler
ROP
Reactor Oversight Process
RFO
Refueling Outage
SDP
Significance Determination Process
SI
Safety Injection
SSC
Structure, System, or Component
SX
Essential Service Water
TI
Temporary Instruction
TIA
Task Interface Agreement
TLD
Thermoluminescent Dosimeter
TS
Technical Specification
UFSAR
Updated Final Safety Analysis Report
URI
Unresolved Item
WO
Work Order
M. Pacilio
-2-
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 (PARS) component of
NRC's Agencywide Document Access and Management System (ADAMS).  ADAMS is
accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public
Electronic Reading Room).
Sincerely,
/RA/
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 No. 05000454/2013002 and 05000455/2013002
  w/Attachment:  Supplemental Information
cc w/encl:
Distribution via ListServ
DOCUMENT NAME:  G:\\DRPIII\\BYRO\\Byron 2013 002.docx
Publicly Available
Non-Publicly Available
Sensitive
Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy
OFFICE
RIII
NAME
TDaun:dtp
EDuncan
DATE
04/26/13
04/29/13
OFFICIAL RECORD COPY
Letter to M. Pacilio from E. Duncan dated April 29, 2013.
SUBJECT:
BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION
REPORT 05000454/2013002; 05000455/2013002
DISTRIBUTION:
Doug Huyck
RidsNrrDorlLpl3-2 Resource
RidsNrrPMByron Resource
RidsNrrDirsIrib Resource
Chuck Casto
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Steven Orth
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Linda Linn
DRPIII
DRSIII
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ROPreports.Resource@nrc.gov
}}
}}

Latest revision as of 09:12, 11 January 2025

IR 05000454-13-002 and 05000455-13-002; Exelon Generation Company, LLC; 01/01/2013 - 03/31/2013; Byron Station, Units 1 & 2, Identification and Resolution of Problems Other Activities
ML13120A181
Person / Time
Site: Byron  Constellation icon.png
Issue date: 04/29/2013
From: Eric Duncan
Region 3 Branch 3
To: Pacilio M
Exelon Generation Co, Exelon Nuclear
References
IR-13-002
Download: ML13120A181 (37)
v • d • e


See also: IR 05000454/2013002

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION III

2443 WARRENVILLE ROAD, SUITE 210

LISLE, IL 60532-4352

April 29, 2013

Mr. Michael J. Pacilio

Senior Vice President, Exelon Generation Company, LLC

President and Chief Nuclear Officer (CNO), Exelon Nuclear

4300 Warrenville Road

Warrenville, IL 60555

SUBJECT:

BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION

REPORT 05000454/2013002; 05000455/2013002

Dear Mr. Pacilio:

On March 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated

inspection at your Byron Station, Units 1 and 2. The enclosed inspection report documents the

inspection results which were discussed on April 4, 2013, with Mr. B. Youman 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.

Two NRC-identified findings of very low safety significance (Green) were identified during this

inspection. One of these findings was determined to involve 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.

If you contest 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 Nuclear Regulatory Commission,

ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional

Administrator, Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director,

Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-

0001; and the NRC Resident Inspector at the Byron Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a

response within 30 days of the date of this inspection report, with the basis for your

disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector

at the Byron Station.

M. Pacilio

-2-

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 (PARS) component of

NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public

Electronic Reading Room).

Sincerely,

/RA/

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 05000454/2013002 and 05000455/2013002

w/Attachment: Supplemental Information

cc w/encl:

Distribution via ListServ

Enclosure

U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos:

50-454; 50-455

License Nos:

NPF-37; NPF-66

Report No:

05000454/2013002; 05000455/2013002

Licensee:

Exelon Generation Company, LLC

Facility:

Byron Station, Units 1 and 2

Location:

Byron, IL

Dates:

January 1 through March 31, 2013

Inspectors:

B. Bartlett, Senior Resident Inspector

J. Robbins, Resident Inspector

J. Bozga, Reactor Inspector

V. Meyers, Health Physicist

V. Meghani, Reactor Inspector

T. Daun, Reactor Engineer

R. Ng, Project Engineer

C. Thompson, Resident Inspector, Illinois Emergency

Management Agency

Approved by:

E. Duncan, Chief

Branch 3

Division of Reactor Projects

Enclosure

TABLE OF CONTENTS

SUMMARY OF FINDINGS ......................................................................................................... 1

REPORT DETAILS .................................................................................................................... 3

Summary of Plant Status ........................................................................................................ 3

1.

REACTOR SAFETY .................................................................................................... 3

1R01

Adverse Weather Protection (71111.01) ............................................................ 3

1R04

Equipment Alignment (71111.04) ...................................................................... 4

1R05

Fire Protection (71111.05) ................................................................................. 4

1R06

Flooding (71111.06) .......................................................................................... 5

1R11

Licensed Operator Requalification Program (71111.11) .................................... 6

1R12

Maintenance Effectiveness (71111.12) .............................................................. 7

1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13) ......... 8

1R15

Operability Evaluations (71111.15) .................................................................... 8

1R18

Plant Modifications (71111.18) .......................................................................... 9

1R19

Post-Maintenance Testing (71111.19) ..............................................................10

1R20

Outage Activities (71111.20) ............................................................................11

1R22

Surveillance Testing (71111.22) .......................................................................12

1EP6

Drill Evaluation (71114.06) ...............................................................................13

2.

RADIATION SAFETY .................................................................................................14

2RS4

Occupational Dose Assessment (71124.04) .....................................................14

4.

OTHER ACTIVITIES ...................................................................................................14

4OA1

Performance Indicator Verification (71151).......................................................14

4OA2

Identification and Resolution of Problems (71152)............................................16

4OA5 Other Activities .................................................................................................20

4OA6

Management Meetings .....................................................................................23

SUPPLEMENTAL INFORMATION ............................................................................................. 1

Key Points of Contact ............................................................................................................. 1

List of Items Opened, Closed, and Discussed ........................................................................ 2

List of Documents Reviewed .................................................................................................. 3

List of Acronymns Use ............................................................................................................ 7

1

Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000454/2013002 and 05000455/2013002; 01/01/2013 - 03/31/2013;

Byron Station, Units 1 & 2; Identification and Resolution of Problems; Other Activities.

This report covers a 3-month period of inspection by resident inspectors and announced

baseline inspections by regional inspectors. Based on the results of this inspection, two NRC-

identified findings of very low safety significance (Green) were identified. One of these findings

had an associated Non-Cited Violation (NCV) of NRC regulations. The significance of

inspection findings is indicated by their color (Greater than Green, or Green, White, Yellow,

Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination

Process (SDP) dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310,

Components Within the Cross-Cutting Areas, dated October 28, 2011. All violations of NRC

requirements are dispositioned in accordance with the NRCs Enforcement Policy dated

January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear

power reactors is described in NUREG-1649, Reactor Oversight Process (ROP), Revision 4.

A.

NRC-Identified and Self-Revealed Finding

Cornerstone: Mitigating Systems

Green. The inspectors identified a finding of very low safety significance (Green) and an

associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when

licensee personnel failed to properly evaluate the structural steel embedment plate

which supported Safety Injection (SI) pipe supports 1SI06025V and 1SI06030S.

Specifically, the licensee failed to demonstrate compliance with the American Institute of

Steel Construction (AISC) and Seismic Category I linear elastic requirements. The

licensee entered this issue into their corrective action program (CAP) as Issue Report

(IR) 1478188. As part of their immediate corrective actions, the licensee performed an

operability evaluation and concluded the structural steel embedment plate was operable,

but nonconforming.

The inspectors determined that the performance deficiency was more than minor

because it was associated with the Design Control attribute of the Mitigating Systems

Cornerstone and adversely affected the cornerstone objective of ensuring the

availability, reliability, and capability of systems that respond to initiating events to

prevent undesirable consequences (i.e., core damage). Specifically, the licensee failed

to demonstrate compliance with AISC and Seismic Category I linear elastic requirements

to ensure the structural steel embedment plate would maintain structural integrity when

subjected to a design basis load. The inspectors determined that because the finding

did not result in a loss of operability or functionality, the finding was of very low safety

significance (Green). This finding did not have a cross-cutting aspect as it was not

indicative of current performance. (Section 4OA2.3)

Green. The inspectors identified a finding of very low safety significance (Green) when

licensee personnel failed to develop inspection lists that included all external flood

protection features credited in current licensing bases (CLB) documents as specified in

Nuclear Energy Institute (NEI) 12-07, Guidelines for Performing Walkdowns of Plant

Flood Protection Features. Specifically, concrete flood barriers in the fuel handling

building (FHB) that protected safety-related equipment in the auxiliary building and flood

barriers for the spent fuel pool cooling pumps were not included in the licensees

2

Enclosure

flooding inspection lists, although these passive components were a critical element of

the licensees flood mitigation strategy. The licensee entered this issue into their CAP

as IR 1466355. Corrective actions included plans to perform an inspection of the NRC-

identified features that were omitted from the inspection lists and an extent-of-condition

review.

The inspectors determined that the performance deficiency was more than minor

because it was associated with the Protection Against External Factors (Flood Hazard)

attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone

objective of ensuring the availability, reliability, and capability of systems that respond to

initiating events to prevent undesirable consequences (i.e., core damage). Because the

finding did not involve the loss or degradation of equipment or function specifically

designed to mitigate a seismic, flooding, or severe weather initiating event (e.g., seismic

snubbers, flooding barriers, tornado doors), the finding was of very low safety

significance (Green). This finding had a cross-cutting aspect in the Work Practices

component of the Human Performance cross-cutting area because licensee personnel

failed to properly apply human error prevention techniques such as peer checking and

proper documentation of activities H.4(a). (Section 4OA5.2)

B.

Licensee-Identified Violations

None.

3

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power throughout the inspection period.

Unit 2 operated at or near full power throughout most of the inspection period. On

March 20, 2013, at approximately 7:51 p.m., the Unit 2 reactor was manually tripped when the

only available generator stator cooling water pump failed. All equipment operated as expected

with a few minor exceptions. Unit 2 returned to full power operation on March 25, 2013, after

the pump was repaired and returned to service.

1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity and

Emergency Preparedness

1R01 Adverse Weather Protection (71111.01)

.1

External Flooding

a.

Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with

the design bases probable maximum flood. The evaluation included a review to check

for deviations from the descriptions provided in the Updated Final Safety Analysis Report

(UFSAR) for features intended to mitigate the potential for flooding from external factors.

As part of this evaluation, the inspectors checked for obstructions that could prevent

draining, checked that the roofs did not contain obvious loose items that could clog

drains in the event of heavy precipitation, and determined whether barriers required to

mitigate flooding were in place and operable. Additionally, the inspectors performed a

walkdown of the protected area to identify any modification to the site which could inhibit

site drainage during a probable maximum precipitation event or allow water ingress past

a flood barrier. The inspectors also walked down underground bunkers/manholes

subject to flooding that contained multiple trains or multiple function risk-significant

cables. The inspectors also reviewed the abnormal operating procedure for mitigating

the design bases flood to ensure it could be implemented as written. Specific areas

inspected included the Unit 1 emergency diesel generators, main steam tunnels, and the

fuel handling building (FHB).

This inspection constituted one external flooding sample as defined in Inspection

Procedure (IP) 71111.01-05.

b.

Findings

Findings identified during this inspection are documented in Section 4OA5, Other

Activities.

4

Enclosure

1R04 Equipment Alignment (71111.04)

.1

Quarterly Partial System Walkdowns

a.

Inspection Scope

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

systems:

Unit Common Train A Control Room Chiller with Train B Control Room Chiller

Out of Service for Maintenance;

Unit 2 Instrument Inverter 212 with Instrument Inverter 214 Out of Service for

Maintenance; and

Unit 2 Train A Essential Service Water (SX) with Unit 2 Train B SX 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, the UFSAR, Technical Specification (TS) requirements, outstanding

work orders (WOs), issue reports (IRs), 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 function(s). The inspectors also

walked down accessible portions of the systems to verify system components and

support equipment were aligned correctly and operable. The inspectors examined the

material condition of the components and observed operating parameters of equipment

to verify that there were no obvious deficiencies. The inspectors also verified that the

licensee had properly identified and resolved equipment alignment problems that could

cause initiating events or impact the capability of mitigating systems or barriers and

entered them into the corrective action program (CAP) with the appropriate significance

characterization. Documents reviewed are listed in the Attachment.

This inspection constituted three partial system walkdown samples as defined in

IP 71111.04-05.

b.

Findings

No findings were identified.

1R05 Fire Protection (71111.05)

.1

Routine Resident Inspector Tours (71111.05Q)

a.

Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on the

availability, accessibility, and the condition of firefighting equipment in the following

risk-significant plant areas:

5

Enclosure

Division 11 Miscellaneous Electrical Equipment and Battery Room Fire

Area 5.6-1;

Division 21 Miscellaneous Electrical Equipment and Battery Room Fire

Area 5.6-2;

Division 12 Miscellaneous Electrical Equipment and Battery Room Fire

Area 5.4-1; and

Division 22 Miscellaneous Electrical Equipment and Battery Room Fire

Area 5.4-2.

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.

This inspection constituted four quarterly fire protection inspection samples as defined in

IP 71111.05-05.

b.

Findings

No findings were identified

1R06 Flooding (71111.06)

.1

Internal Flooding

a.

Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee

procedures intended to protect the plant and its safety-related equipment from internal

flooding events. The inspectors reviewed flood analyses and design documents,

including the UFSAR, engineering calculations, and abnormal operating procedures to

identify licensee commitments. 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 CAP 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

6

Enclosure

sumps were clear of debris and were operable, and that the licensee complied with

existing commitments:

Unit 1 and Unit 2 SX Pump Rooms

Documents reviewed are listed in the Attachment. This inspection constituted one

internal flooding sample as defined in IP 71111.06-05.

b.

Findings

No findings were identified.

1R11 Licensed Operator Requalification Program (71111.11)

.1

Resident Inspector Quarterly Review (71111.11Q)

a.

Inspection Scope

On January 31, 2013, the inspectors observed a crew of licensed operators in the plant

simulator during licensed operator requalification examinations to verify that operator

performance was adequate, evaluators were identifying and documenting crew

performance problems, and training was being conducted in accordance with licensee

procedures. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

The crews performance in these areas was compared to pre-established operator action

expectations, procedural compliance, and successful critical task completion

requirements. Documents reviewed are listed in the Attachment.

In addition, the inspectors observed licensed operator performance in the actual plant

and the main control room during this calendar quarter.

This inspection constituted one quarterly licensed operator requalification program

sample as defined in IP 71111.11-05.

b.

Findings

No findings were identified.

7

Enclosure

.2

Resident Inspector Quarterly Observation of Heightened Activity or Risk (71111.11Q)

On March 12, 2013, the inspectors observed control room operators during the

emergent failure of Unit 1 core exit thermocouple 50, and on March 22, 2013, the

inspectors observed plant startup following the Unit 2 forced outage. These were

activities that required heightened awareness and was related to increased risk.

The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

The crews performance in these areas was compared to pre-established operator action

expectations, procedural compliance, and successful critical task completion

requirements. Documents reviewed are listed in the Attachment.

This inspection constituted one quarterly licensed operator heightened activity/risk

sample as defined in IP 71111.11-05.

b.

Findings

No findings were identified.

1R12 Maintenance Effectiveness (71111.12)

.1

Routine Quarterly Evaluations (71111.12Q)

a.

Inspection Scope

The inspectors evaluated degraded performance issues involving the following

risk-significant systems:

Failure of Unit 1 Power Range Channel N43; and

Review of Maintenance Rule Assessment for the Period of January 2011 to

June 2012.

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.

8

Enclosure

b.

Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

.1

Maintenance Risk Assessments and Emergent Work Control

a.

Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the

maintenance and emergent work activities affecting risk-significant and safety-related

equipment listed below to verify that the appropriate risk assessments were performed

prior to removing equipment for work:

Unit 2 Train A Charging Pump Emergent Failure with the Unit 1 Train A SX

Pump Out of Service for Planned Maintenance;

Unit 1 Power Range Channel N43 Emergent Failure with Unit 2 Train B SX

Inoperable for Planned Maintenance; and

Unit 1 Train B Auxiliary Feedwater Pump Work Window.

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 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.

This inspection constituted three maintenance risk assessments and emergent work

control samples as defined in IP 71111.13-05.

b.

Findings

No findings were identified.

1R15 Operability Evaluations (71111.15)

.1

Operability Evaluations

a.

Inspection Scope

The inspectors reviewed the following issues:

Unit 1 Division 111 Battery Racks Support Questions;

Capacity of Pressurizer Power Operated Relief Valve (PORV) Air Accumulators

During Natural Circulation Cooldown;

9

Enclosure

Operation of SX Pump with Single Cubical Cooler; and

Unit 1 Power Range Channel N43 TS 3.3.1.D Entry.

The inspectors selected these potential operability issues based on the risk significance

of the associated components and systems. The inspectors evaluated the technical

adequacy of the evaluations to ensure that TS operability was properly justified and the

subject component or system remained available such that no unrecognized increase in

risk occurred. The inspectors compared the operability and design criteria in the

appropriate sections of the TS and UFSAR to the licensees evaluations to determine

whether the components or systems were operable. Where compensatory measures

were required to maintain operability, the inspectors determined whether the measures

in place would function as intended and were properly controlled. The inspectors

determined, where appropriate, compliance with bounding limitations associated with the

evaluations. Additionally, the inspectors reviewed a 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

Attachment.

This inspection constituted four operability inspection samples as defined in

IP 71111.15-05.

b.

Findings

No findings were identified.

1R18 Plant Modifications (71111.18)

.1

Plant Modifications

a.

Inspection Scope

The inspectors reviewed the following modification:

Reactor Containment Fan Cooler (RCFC) Check Dampers Closure Spring

Changes

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety

evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to

verify that the modification did not affect the operability or availability of the affected

system. The inspectors, as applicable, observed ongoing and completed work activities

to ensure that the modifications were installed as directed and consistent with the design

control documents; the modifications operated as expected; post-modification testing

adequately demonstrated continued system operability, availability, and reliability; and

that operation of the modifications did not impact the operability of any interfacing

systems. As applicable, the inspectors verified that relevant procedure, design, and

licensing documents were properly updated. Lastly, the inspectors discussed the plant

modification with operations, engineering, and training personnel to ensure that the

individuals were aware of how the operation with the plant modification in place could

impact overall plant performance. Documents reviewed are listed in the Attachment.

10

Enclosure

This inspection constituted one permanent plant modification sample as defined in

IP 71111.18-05.

b.

Findings

No findings were identified.

1R19 Post-Maintenance Testing (71111.19)

.1

Post-Maintenance Testing

a.

Inspection Scope

The inspectors reviewed the following post-maintenance testing activities to verify that

procedures and test activities were adequate to ensure system operability and functional

capability:

Unit 1 Bus 144 Breaker 1442 Following Lockout Relay Replacement;

Unit 1 Train A SX Cubical Coolers Following Repairs;

Unit 2 Instrument Inverter 214 Following Coil Replacement; and

Unit 2 Train B Generator Stator Water Cooling System Pump Following Motor

Replacement.

These activities were selected based upon the structure, system, and components

(SSCs) 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 bases 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 into the CAP at the appropriate threshold and

that the problems were being corrected commensurate with their importance to safety.

Documents reviewed are listed in the Attachment.

This inspection constituted four post-maintenance testing samples as defined in

IP 71111.19-05.

b. Findings

No findings were identified.

11

Enclosure

1R20 Outage Activities (71111.20)

.1

Unit 2 Forced Outage

a.

Inspection Scope

On March 20, 2013, at 7:51 p.m., licensee personnel performed a manual trip of the

Unit 2 reactor. The reactor was manually tripped in accordance with site procedures

when the only operating and available electrical generator stator cooling water pump

tripped unexpectedly. The inspectors responded to the site and assessed the cause of

the trip, performed follow-up inspection of minor equipment failures, and immediately

communicated any observations to NRC management. The inspectors reviewed outage

equipment configuration and risk management, verified electrical lineups, monitored

decay heat removal, observed reactor startup activities, and reviewed the identification

and resolution of problems associated with the forced outage.

All safety-related equipment operated as designed. Some nonsafety-related equipment

experienced minor malfunctions. For example:

The B reactor trip breaker closed indication light extinguished as expected, however

the open indication light did not illuminate to indicate that the breaker was open. An

operator was dispatched and verified the breaker was open. Subsequently, a burned

out B reactor trip breaker open indication light bulb was replaced.

The control rod in position M-12 (control bank D) had a general warning light

flashing, although its associated rod bottom light was lit. Following troubleshooting,

a logic card was replaced in the control rod drive cabinet to address the issue.

Following the Unit 2 trip, light smoke was reported to be coming from the Unit 2 A

main feedwater pump motor. It was later determined that when the 2A main feedater

pump was shut down that its associated motor heater automatically energized. An

abnormally large amount of dust had built up on the heater and when it energized the

dust burned off.

The licensee addressed these issues and Unit 2 was restarted and synchronized to the

electrical grid on March 22, 2013.

Documents reviewed are listed in the Attachment. This inspection constituted one other

outage sample as defined in IP 71111.20-05.

b.

Findings

No findings were identified.

.2

Unit 2 Refueling Outage

a.

Inspection Scope

The inspectors reviewed the Outage Safety Plan and contingency plans for the Unit 2

refueling outage (RFO) that began on April 7, 2013, to confirm that the licensee had

appropriately considered risk, industry operating experience, and previous site specific

12

Enclosure

problems in developing and implementing a plan that assured maintenance of defense in

depth.

A complete list of accomplished inspection activities will be documented following

completion of the Unit 2 RFO.

This inspection constituted a partial RFO sample as defined in IP 71111.20-05.

b.

Findings

No findings were identified.

1R22 Surveillance Testing (71111.22)

.1

Surveillance Testing

a.

Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether

risk-significant systems and equipment were capable of performing their intended safety

function and to verify testing was conducted in accordance with applicable procedural

and TS requirements:

Unit 1 Train B Containment Spray Pump Quarterly Surveillance;

Unit 1 Train A Diesel Generator Operability Surveillance;

Unit 1 Train A Solid State Protection System Surveillance;

Unit 2 K636 Engineered Safety Features (ESF) Relay Surveillance; and

Unit 2 K644 ESF Relay 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, demonstrate operational readiness, and

consistent with the system design basis;

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

were as left setpoints within required ranges; and was the calibration frequency

in accordance with TSs, the UFSAR, plant procedures, and applicable

commitments;

was measuring and test equipment calibration current;

was the test equipment used within the required range and accuracy and were

applicable prerequisites described in the test procedures satisfied;

did test frequencies meet TS requirements to demonstrate operability and

reliability;

were tests performed in accordance with the test procedures and other

applicable procedures;

were jumpers and lifted leads controlled and restored where used;

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

13

Enclosure

was test equipment removed following testing;

where applicable for in-service testing activities, was testing performed in

accordance with the applicable version of Section XI of the American Society of

Mechanical Engineers (ASME) Code, and were reference values consistent with

the system design basis;

was the unavailability of the tested equipment appropriately considered in the

performance indicator data;

where applicable, were test results not meeting acceptance criteria addressed

with an adequate operability evaluation, or was the system or component

declared inoperable;

where applicable for safety-related instrument control surveillance tests, was the

reference setting data accurately incorporated into the test procedure;

was equipment returned to a position or status required to support the

performance of its safety function following testing;

were all problems identified during the testing appropriately documented and

dispositioned in the licensees CAP;

where applicable, were annunciators and other alarms demonstrated to be

functional and were annunicator and alarm setpoints consistent with design

documents; and

where applicable, were alarm response procedure entry points and actions

consistent with the plant design and licensing documents.

Documents reviewed are listed in the Attachment.

This inspection constituted five routine surveillance testing samples as defined in

IP 71111.22, Sections -02 and -05.

b.

Findings

No findings were identified.

1EP6 Drill Evaluation (71114.06)

.1

Training Observation

a.

Inspection Scope

The inspectors observed a simulator training evolution for licensed operators on

January 31, 2013, which required Emergency Plan implementation by a licensee

operations crew. This evolution was planned to be evaluated and included in

performance indicator data regarding drill and exercise performance. The inspectors

observed event classification and notification activities performed by the crew. The

inspectors also attended the post-evolution critique for the scenario. The focus of the

inspectors activities was to note any weaknesses and deficiencies in the crews

performance and ensure that the licensee evaluators noted the same issues and entered

them into the CAP. As part of the inspection, the inspectors reviewed the scenario

package and other documents listed in the Attachment.

This inspection constituted one training evolution with emergency preparedness drill

sample as defined in IP 71114.06-05.

14

Enclosure

b.

Findings

No findings were identified.

2.

RADIATION SAFETY

2RS4 Occupational Dose Assessment (71124.04)

This inspection constituted a partial sample as defined in IP 71124.04-05.

.1

External Dosimetry (02.02)

a.

Inspection Scope

The inspectors evaluated whether the licensees dosimetry vendor is National Voluntary

Laboratory Accreditation Program (NVLAP) accredited and if the approved irradiation

test categories for each type of personnel dosimeter used were consistent with the types

and energies of the radiation present and the way the dosimeter was being used (e.g., to

measure deep dose equivalent, shallow dose equivalent, or lens dose equivalent).

b.

Findings

No findings were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

.1

Unplanned Scrams Per 7000 Critical Hours

a.

Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams Per 7000 Critical

Hours Performance Indicator (PI) for both Unit 1 and Unit 2 for the period from the first

quarter 2012 through the fourth quarter 2012. To determine the accuracy of the PI data

reported during those periods, PI definitions and guidance contained in Nuclear Energy

Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline,

Revision 6, dated October 2009, were used. The inspectors reviewed the licensees

operator narrative logs, IRs, event reports and NRC Integrated Inspection Reports for

the period of January 2012 through December 2012 to validate the accuracy of the

submittals. The inspectors also reviewed the licensees IR database to determine if any

problems had been identified with the PI data collected or transmitted for this indicator.

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.

Findings

No findings were identified.

15

Enclosure

.2

Unplanned Scrams with Complications

a.

Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with

Complications PI for Unit 1 and Unit 2 for the period from the first quarter 2012 through

the fourth quarter 2012. To determine the accuracy of the PI data reported during those

periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 6, dated October 2009, were used. The

inspectors reviewed the licensees operator narrative logs, IRs, event reports and NRC

Integrated Inspection Reports for the period of January 2012 through December 2012 to

validate the accuracy of the submittals. The inspectors also reviewed the licensees IR

database to determine if any problems had been identified with the PI data collected or

transmitted for this indicator. Documents reviewed are listed in the Attachment .

This inspection constituted two unplanned scrams with complications samples as

defined in IP 71151-05.

b.

Findings

No findings were identified.

.3

Unplanned Power Changes Per 7000 Critical Hours

a.

Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Power Changes Per

7000 Critical Hours PI for Unit 1 and Unit 2 for the period from the first quarter 2012

through the fourth quarter 2012. To determine the accuracy of the PI data reported

during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory

Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were

used. The inspectors reviewed the licensees operator narrative logs, IRs, maintenance

rule records, event reports, and NRC Integrated Inspection Reports for the period of

January 2012 through December 2012 to validate the accuracy of the submittals. The

inspectors also reviewed the licensees IR database to determine if any problems had

been identified with the PI data collected or transmitted for this indicator. Documents

reviewed are listed in the Attachment.

This inspection constituted two unplanned power changes per 7000 critical hours

samples as defined in IP 71151-05.

b.

Findings

No findings were identified.

16

Enclosure

4OA2 Identification and Resolution of Problems (71152)

.1

Routine Review of Items Entered into the Corrective Action Program

a.

Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of

this report, the inspectors routinely reviewed issues during baseline inspection activities

and plant status reviews to verify that they were being entered into the licensees CAP at

an appropriate threshold, that adequate attention was being given to timely corrective

actions, and that adverse trends were identified and addressed. Attributes reviewed

included the complete and accurate identification of the problem; that timeliness was

commensurate with safety significance; that evaluation and disposition of performance

issues, generic implications, common causes, contributing factors, root causes, extent-

of-condition reviews, and previous occurrence reviews were proper and adequate; and

that the classification, prioritization, focus, and timeliness of corrective actions were

commensurate with safety and sufficient to prevent recurrence of the issue. Minor

issues entered into the licensees CAP as a result of the inspectors observations are

listed in the Attachment.

These routine reviews for the identification and resolution of problems did not constitute

any additional inspection samples. Instead, by procedure they were considered an

integral part of the inspections performed during the quarter and documented in

Section 1 of this report.

b.

Findings

No findings were identified.

.2

Daily Corrective Action Program Reviews

a.

Inspection Scope

To facilitate the identification of repetitive equipment failures and human performance

issues for follow-up, the inspectors performed a daily screening of items entered into the

licensees CAP. This review was accomplished through inspection of the stations daily

IR packages.

These daily reviews were performed by procedure as part of the inspectors daily plant

status monitoring activities and, as such, did not constitute any separate inspection

samples.

b.

Findings

No findings were identified.

17

Enclosure

.3

Selected Issue Follow-Up Inspection: Actions to Address Engineering-Related Issues

Identified at Braidwood During NRC Inspections

a.

Inspection Scope

The inspectors reviewed evaluations and calculations as well as related IRs to assess

the adequacy of the licensees extent-of-condition review of issues identified during the

Braidwood Station Unit 1 and Unit 2 Evaluation of Changes, Tests, or Experiments and

Permanent Plant Modifications inspections performed in 2011.

This review included an analysis that was performed by the licensee to determine the

effects of lead shielding on the Unit 1 Safety Injection (SI) system piping subsystem and

associated pipe supports.

This review constituted one in-depth problem identification and resolution sample as

defined in IP 71152-05.

b.

Findings

Embedment Plate Design Deficiencies

Introduction: The inspectors identified a finding of very low safety significance (Green)

and an associated Non-Cited Violation (NCV) of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, when licensee personnel failed to properly evaluate the

structural steel embedment plate which supported SI pipe supports 1SI06025V and

1SI06030S.

Description: The SI system is part of the emergency core cooling system (ECCS).

Section 6.3.1 of the Byron UFSAR stated, in part, that the primary function of the ECCS

is to remove the stored and fission product decay heat from the reactor during accident

conditions and provide shutdown capability for design basis accidents by means of

boron injection.

Piping Subsystem 1SI06 is part of the SI System and is a safety-related ASME Class II,

Seismic Category I subsystem located in the curved wall area of the auxiliary building. A

structural steel embedment plate that supports safety-related pipe supports 1SI06025V

and 1SI06030S is located in the auxiliary building, which is a Seismic Category I

structure. Section 3.8.4.5.2 of the UFSAR describes requirements for structural steel

design inside the auxiliary building and states, in part, The stresses and strains of

structural steel are limited to those specified in the AISC (American Institute of Steel

Construction) Also, this section required that stresses be held within the elastic range

and that no plastic deformation was allowed.

The inspectors reviewed Calculation No. 13.2.29BY, Mechanical Component Support

1SI06025V, Revision 2X that evaluated pipe supports 1SI06025V and 1SI06030S.

These supports were attached to a structural embedment plate in the auxiliary building.

The structural steel embedment plate evaluation was also included in this calculation.

During a review of Calculation No. 13.2.29BY, the inspectors identified a number of

concerns, including the following:

18

Enclosure

The calculated bending stress on the embedment plate was greater than the

allowable bending stress by about 67 percent and the licensee relied on engineering

judgment to demonstrate compliance with the design and licensing basis

requirements;

The calculation used the actual instead of minimum material yield stress of the

embedment plate to calculate the allowable bending stress;

The calculation used an acceptance criteria which permitted plastic or permanent

deformation through yielding of the structural steel embedment plate and

redistribution of stresses in the embedment plate due to applied loads;

The calculation did not include an evaluation for severe environmental load

combinations as described in UFSAR Table 3.8-9 and as described in UFSAR

Section 3.8.4.3, Loads and Loading Combinations; and

The calculation did not consider applied stresses due to self-weight and self-weight

seismic excitation of tube steel pipe support members.

The inspectors determined that the engineering judgment used to demonstrate

compliance with the design and licensing basis was not valid because the AISC required

that the allowable bending stress be determined using the minimum yield stress of the

material. In addition, UFSAR Section 3.8.4.5.2 specified no plastic or permanent

deformation due to applied stresses. The inspectors also identified that the structural

steel embedment plate was not qualified for the severe environmental load combination

as described in UFSAR Table 3.8-9 and as required by UFSAR Section 3.8.4.3.

The licensee entered this issue into their CAP as IR 1478188, NRC Identified Use of

CMTR in a 80's Calculation. As part of their immediate corrective actions, the licensee

performed an operability evaluation and concluded the structural steel embedment plate

was operable, but nonconforming.

Analysis: The inspectors determined that the failure to design the structural steel

embedment plate which supported pipe supports 1SI06025V and 1SI06030S in

accordance with AISC and Seismic Category I linear elastic requirements was a

performance deficiency.

The inspectors determined that the performance deficiency was more than minor

because it was associated with the Design Control attribute of the Mitigating Systems

Cornerstone and adversely affected the cornerstone objective of ensuring the

availability, reliability, and capability of systems that respond to initiating events to

prevent undesirable consequences (i.e., core damage). Specifically, the licensee did not

demonstrate that the structural steel embedment plate which supported pipe supports

1SI06025V and 1SI06030S would maintain structural linear elastic integrity when

subjected to design loads.

The inspectors reviewed Attachment 0609.04, Initial Characterization of Findings,

Table 3 - SDP Appendix Router. The inspectors answered No to all of the questions in

Sections A through E of Table 3 and therefore the finding was evaluated using the SDP

in accordance with IMC 0609, The Significance Determination Process (SDP) for

Findings At-Power, Appendix A, Exhibit 2, Mitigating Systems Screening

19

Enclosure

Questions. The inspectors answered Yes to Question 1 - If the finding is a deficiency

affecting the design or qualification of a mitigating SSC [Structure, System, or

Component], does the SSC maintain its operability or functionality? Specifically, the

design deficiency was confirmed not to result in a loss of operability of the structural

steel embedment plate. Therefore, the finding was determined to have very low safety

significance (Green). The inspectors performed an independent review of the operability

evaluation and had no further concerns.

The inspectors did not identify a cross-cutting aspect associated with this finding

because the calculation was from the 1980s and was therefore not representative of

current performance.

Enforcement: 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 the design, such as by the performance of design reviews, by the use of alternate or

simplified calculational methods, or by the performance of a suitable testing program.

Piping Subsystem 1SI06 is part of the Safety Injection System and is a safety-related

ASME Class II, Seismic Category I subsystem located in the curved wall area of the

auxiliary building. A structural steel embedment plate that supports safety-related pipe

supports 1SI06025V and 1SI06030S is located in the auxiliary building, which is a

Seismic Category I structure. Section 3.8.4.5.2 of the UFSAR describes requirements

for structural steel design inside the auxiliary building and states, in part, The stresses

and strains of structural steel are limited to those specified in the AISC. Also,

Section 3.8.4.5.2 of the UFSAR required that stresses be within the elastic range and

that no plastic deformation was allowed.

Contrary to the above, from initial construction to February 21, 2013, the licensee failed

to demonstrate the design adequacy of the embedment plate which supported safety-

related Safety Injection pipe supports 1SI06025V and 1SI06030S. Specifically, the

design for the structural steel embedment plate which supported safety-related Safety

Injection pipe supports 1SI06025V and 1SI06030S was inadequate, in that Calculation

No. 13.2.29BY, Mechanical Component Support 1SI06025V, Revision 2X, which was a

quality calculation, did not demonstrate that the embedment plate would meet AISC and

Seismic Category I linear elastic requirements.

Because this violation was of very low safety significance and it was entered into the

licensees CAP as IR 1478188, this violation is being treated as a NCV, consistent with

Section 2.3.2 of the NRC Enforcement Policy. As part of their immediate corrective

actions, the licensee performed an operability evaluation and concluded the structural

steel embedment plate was operable. (NCV 05000454/2013002-01, Embedment

Plate Design Deficiencies)

.4

Selected Issue Follow-Up Inspection: Valves in LCO Due to Abandonment

a.

Inspection Scope

During a review of items entered in the licensees CAP, the inspectors identified an

IR regarding equipment that had been abandoned in place. Specifically, IR 1306607,

Long Term LCO [Limiting Condition for Operation] Extent of Condition Review Per

IR 1298667, characterized a series of valves as abandoned. The valves were also

20

Enclosure

characterized as having a containment isolation function. The inspectors reviewed the

licensees procedures associated with containment leak rate testing and recent test data

to ensure that the performance of the abandoned valves remained acceptable.

This review constituted one in-depth problem identification and resolution sample as

defined in IP 71152-05.

b.

Findings

No findings were identified.

4OA5 Other Activities

.1

(Closed) NRC Temporary Instruction (TI) 2515/187 - Inspection of Near-Term Task

Force Recommendation 2.3 Flooding Walkdowns

As discussed in NRC Integrated Inspection Report 05000454/2012005;

05000455/2012005, the inspectors previously verified that licensee walkdown packages

Unit 1 13-Line Wall, Unit 1 1A and 1D Main Steam Isolation Valve Room Probable

Maximum Precipitation (PMP) Curb, and River Screen House Penetration RH-15C,

contained the elements specified in Nuclear Energy Institute (NEI) 12-07, Guidelines for

Performing Walkdowns of Plant Flood Protection Features.

During the previous quarter, the inspectors accompanied the licensee on their walkdown

of the River Screen House, Penetration RH-15C; and Unit 1 A and D Main Steam

Isolation Valve Room PMP Curb and verified that the licensee confirmed the following

flood protection features:

Visual inspection of the flood protection feature was performed if the flood

protection feature was relevant. External visual inspection for indications of

degradation that would prevent its credited function from being performed was

performed.

Critical SSC dimensions were measured.

Available physical margin, where applicable, was determined.

Flood protection feature functionality was determined using either visual

observation or by review of other documents.

During this quarter, the inspectors conducted additional independent walkdowns to verify

licensee compliance with inspection guidance contained in TI 2515/187. The area

selected was the building that houses the spent fuel pool, the fuel handling building

(FHB). There were several reasons for selecting this area. For example, the spent fuel

pool filtering and heat removal systems are located in the FHB. In addition, the FHB has

access ways that lead to other portions of the auxiliary building, a safety-related

structure.

The Byron UFSAR identified that the FHB was not subject to flooding. The inspectors

questioned why the FHB would not be subject to flooding since portions of it are at

ground level, a roll-up door in this building leads to an adjacent structure which has a

21

Enclosure

roll-up door that leads outside, and railway channels in the FHB have been observed to

contain rain water.

The inspectors verified that noncompliances with current licensing requirements, and

issues identified in accordance with the 10 CFR 50.54(f) letter, Item 2.g of Enclosure 4,

were entered into the licensee's CAP. In addition, issues identified in response to Item

2.g that could challenge risk significant equipment and the licensees ability to mitigate

the consequences will be subject to additional NRC evaluation.

.2

Failure to Properly Scope All the Pertinent External Flood Protection Features into

Walkdown Lists in Accordance with Nuclear Energy Institute (NEI) 12-07

Introduction: The inspectors identified a finding of very low safety significance (Green)

when licensee personnel failed to develop inspection lists that included all external flood

protection features credited in current licensing bases (CLB) documents as specified in

NEI 12-07, Guidelines for Performing Walkdowns of Plant Flood Protection Features.

Specifically, the inspection lists did not include several passive components in the FHB

which were an essential element of the Byron flood mitigation strategy.

Description: The inspectors reviewed the licensees inspection and walkdown

documents associated with flooding reviews performed in accordance with NEI 12-07,

Guidelines for Performing Walkdowns of Plant Flood Protection Features, in response

to a letter from the NRC to licensees pursuant to 10 CFR 50.54(f). During the review,

the inspectors identified that the licensee had completed their scoping of components for

TI 2515/187, Inspection of Near-Term Task Force Recommendation 2.3 Flooding

Walkdowns, and failed to properly scope all flood protection features credited in the

CLB documents for flooding events. Specifically, while reviewing the Flooding Features

Walkdown List used to inspect and test design bases flood mitigating equipment in

accordance with the NRC-endorsed guidance of NEI 12-07, the inspectors identified that

the flood protection features in the FHB were not included. The flood protection features

in the FHB were designed to protect the auxiliary building, including residual heat

removal and containment spray pumps from site external flooding scenarios, and were

an essential part of the Byron design basis flood mitigation strategy. In particular, the

concrete steps inside the FHB were designed to prevent flood waters that enter the FHB

from reaching a door that would allow water to enter the auxiliary building.

Because the licensee did not adequately follow the guidance in NEI 12-07 and identify

components in the FHB that served as passive flooding barriers, these components

were not scheduled for visual inspections or walkdowns. As a result, the licensee failed

to recognize walkdowns of these passive flooding barriers were required to adequately

respond to the March 12, 2012 letter from the NRC to licensees that discussed these

reviews. The licensee acknowledged that they may not have identified these flood

barriers during subsequent reviews if the inspectors had not identified the issue.

The licensee entered this issue into their CAP as IR 1466355, Update UFSAR

Regarding External Flooding. Corrective actions included plans to perform an

inspection of the NRC-identified passive flooding features that were omitted from the

inspection lists and an extent-of-condition review.

Analysis: The inspectors determined that the failure to include concrete flood barriers in

the FHB in the flooding inspection lists developed to address NEI 12-07, although these

22

Enclosure

passive components were a critical element of the Byron flood mitigation strategy, was a

performance deficiency.

Using the guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B,

Issue Screening, the inspectors determined this finding affected the Mitigating Systems

Cornerstone. The inspectors determined that the performance deficiency was more than

minor because it was associated with the Protection Against External Factors (Flood

Hazard) attribute of the Mitigating Systems Cornerstone and adversely affected the

cornerstone objective of ensuring the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences (i.e., core

damage). Specifically, the concrete flood barriers in the FHB protecting important

safety-related equipment in the auxiliary building as well as the flood barriers for the

spent fuel pool cooling pumps were not properly scoped into the licensees walkdown

lists.

The inspectors reviewed Attachment 0609.04, Initial Characterization of Findings,

Table 3 - SDP Appendix Router. The inspectors answered No to all of the questions in

Sections A through E of Table 3 and therefore the finding was evaluated using the SDP

in accordance with IMC 0609, The Significance Determination Process (SDP) for

Findings At-Power, Appendix A, Exhibit 2, Mitigating Systems Screening

Questions. The inspectors answered No to Question B for the External Event

Mitigation Systems - Does the finding involve the loss or degradation of equipment or

function specifically designed to mitigate a seismic, flooding, or severe weather initiating

event (e.g., seismic snubbers, flooding barriers, tornado doors)? Therefore, the finding

was determined to have very low safety significance (Green).

This finding had a cross-cutting aspect in the Work Practices component of the Human

Performance cross-cutting area because licensee personnel did not properly apply

human error prevention techniques such as peer checking and proper documentation of

activities H.4(a).

Enforcement: This finding did not involve enforcement action because no violation of a

regulatory requirement was identified. Because this finding does not involve a violation

and is of very low safety significance, it is identified as a finding (FIN). (FIN 05000454/2013002-02; 05000455/2013002-02, Failure to Properly Scope All

Pertinent External Flood Protection Features into Walkdown Lists in Accordance

with Industry Guidance NEI 12-07)

.3

(Closed) Unresolved Item 05000454/2011005-03; 05000455/2011005-03: Use of

Thermolumiscent Dosimeters May Not Be Consistent With the Methods Used By the

National Voluntary Laboratory Accreditation Program Accreditation Process

In the fourth quarter of 2011, the inspectors identified that the licensees use of

thermoluminescent dosimeters (TLDs) may not be consistent with the methods used by

the NVLAP accreditation process. Specifically, the licensee used a vendor to supply and

process dosimeters that measure radiation exposure for the monitored workers. This

vendor is NVLAP-accredited for beta, gamma, neutron, mixture of beta/gamma, and

mixture of neutron/gamma radiations. However, the licensee used the TLDs when

workers may be exposed to beta, gamma, and neutron radiations within the same

monitoring period. The inspectors determined that this mixture of three radiation types

may not be aligned with the accreditation process, and opened Unresolved Item (URI)

23

Enclosure 05000454/2011005-03; 05000455/2011005-03 to evaluate the issue. The inspectors

requested technical assistance from the Office of Nuclear Reactor Regulation (NRR)

through Task Interface Agreement (TIA) 2012-05 (ML 12268A330), the results of which

are discussed below.

Title 10 CFR 20.1501(c)(2) requires that the dosimeter processor be approved for the

type of radiation or radiations included in the NVLAP program that most closely

approximates the type of radiation or radiations for which the individual wearing the

dosimeter is monitored. As there is no NVLAP test category for dosimeters exposed to a

mixture of beta, gamma, and neutron radiations, the NRC has determined that licensees,

which monitor for beta, gamma, and neutron exposure with a single dosimeter, need to

use a processor that is NVLAP accredited in categories for beta-photon mixtures and

neutron-photon mixtures. The licensees dosimetry processor was NVLAP accredited

for both beta-photon and neutron-photon mixtures and therefore was in compliance with

10 CFR 20.1501(c)(2).

Notwithstanding the paragraph above, licensees are required to provide adequate

monitoring in accordance with 10 CFR 20.1502(a). For any type of in-field use

practice that can introduce error in the monitoring results (dependent upon the type of

dosimeter and processing method), it becomes a question of compliance with the

monitoring requirements of 10 CRR 20.1502(a) and not of NVLAP accreditation

requirements of 10 CFR 20.1501(c)(2). As described in TIA 2012-05, another licensee

had performed a study with the same dosimeters used by Byron (Harshaw 760). This

study demonstrated that exposing a single Harshaw 760 dosimeter to a mixture of beta,

gamma, and neutron radiation met industry standards for accuracy and precision.

Therefore, the licensee provided adequate monitoring and was in compliance with

10 CFR 20.1502(a).

The inspectors determined that no performance deficiency existed; therefore this URI is

closed.

4OA6 Management Meetings

.1

Exit Meeting Summary

On April 4, 2013, the inspectors presented the inspection results to Mr. B. Youman,

Byron Plant Manager, and other members of the licensees staff.

The licensee acknowledged the issues presented. The inspectors confirmed that none

of the potential report input discussed was considered proprietary.

.2

Interim Exit Meetings

The inspection results for the area of occupational dose assessment were

discussed with Mr. B. Burton, Radiation Protection Manager, on March 26, 2013.

The inspection results for the area of lead shielding and pipe supports were

discussed with Ms. A. Corrigan, Mechanical Design Manager, and

Mr. E. Blondin, Design Engineering Manager, on March 26, 2013.

The licensee acknowledged the issues presented. The inspectors confirmed that none

of the potential report input discussed was considered proprietary.

24

Enclosure

ATTACHMENT: SUPPLEMENTAL INFORMATION

1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

R. Kearney, Site Vice President

B. Youman, Plant Manager

B. Askren, Security Manager

B. Barton, Radiation Protection Manager

S. Briggs, Operations Director

A. Creamean, Chemistry Manager

S. Gackstetter, Training Manager

D. Gudger, Regulatory Assurance Manager

E. Hernandez, Engineering Director

D. Horstmann, Business Operations

B. Spahr, Maintenance Director

E. Topping, Nuclear Oversight Manager

Nuclear Regulatory Commission

E. Duncan, Chief, Branch 3, Division of Reactor Projects

B. Bartlett, Byron Senior Resident Inspector

J. Robbins, Byron Resident Inspector

Illinois Emergency Management Agency (IEMA)

R. Zuffa, IEMA

2

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened 05000454/2013002-01

NCV

Embedment Plate Design Deficiencies (Section 4OA2.3)05000454/2013002-02; 05000455/2013002-02

FIN

Failure to Properly Scope All Pertinent External Flood

Protection Features into Walkdown Lists in Accordance with

Industry Guidance NEI 12-07 (Section 4OA5.2)

Closed 05000454/2013002-01

NCV

Embedment Plate Design Deficiencies (Section 4OA2.3)05000454/2013002-02; 05000455/2013002-02

FIN

Failure to Properly Scope All Pertinent External Flood

Protection Features into Walkdown Lists in Accordance with

Industry Guidance NEI 12-07 (Section 4OA5.2)

TI 2515/187

TI

Inspection of Near-Term Task Force Recommendation 2.3

Flooding Walkdown (Section 4OA5.1)05000454/2011005-03; 05000455/2011005-03

URI

Use of TLDs May Not Be Consistent With the Methods Used

by the NVLAP Accreditation Process (Section 4OA5.3)

3

Attachment

LIST OF DOCUMENTS REVIEWED

The following is a list of documents reviewed during the inspection. Inclusion on this list does

not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that

selected sections of portions of the documents were evaluated as part of the overall inspection

effort. Inclusion of a document on this list does not imply NRC acceptance of the document or

any part of it, unless this is stated in the body of the inspection report.

Section 1R04

- BOP WO-E4; Control Room Chilled Water Electrical Lineup, Revision 2

- BOP WO-M3; Control Room Chilled Water Valve Lineup, Revision 10

Section 1R06

- BAR 0PL02J-3-B2; ESW Sump 2 Level High High, Revision 52

- IR 1413893; Unit 1 SX Alpha Sump Pump Check Valve is Sticking Open, September 16, 2012

- M-48; Diagram of Miscellaneous Sumps and Pumps, Revision AE

Section 1R11

- IR 1486687; Unexpected Unit 1 PDMS Alarms Due to Failing CETC, March 12, 2012

Section 1R12

- IR 1487650; Potential Corporate Elevation for Byron Maintenance, March 12, 2013

- IR 1479105; Unit 1 Gain POT R303 for N-43 Not Functioning Properly, February 22, 2013

- Byron Station Maintenance Rule Expert Panel Meeting Notes, November 5, 2009

- Byron Station Maintenance Rule Expert Panel Meeting Notes, December 18, 2009

- Byron Station Maintenance Rule Expert Panel Meeting Notes, June 7, 2011

- Byron Station Maintenance Rule Expert Panel Meeting Notes, November 3, 2011

- IR 1214163; Common Cause Analysis for MCCB for MCC 134Y2-A4, June 2, 2011

- ER-AA-310-1005; (A)(1) Determination Template for IR 1207922, Revision 5

- ER-AA-310-1005; (A)(1) Determination Template for IR 1207931, Revision 5

- Byron Station Maintenance Rule Periodic Assessment #11, January 2011 - June 2012

Section 1R13

- IR 1474028; 2A CV Pump Gear Box Failed to Develop Oil Pressure on Start,

February 12, 2013

- IR 1474042; 2A CV Pump Gear Oil Pressure Guage Stuck at 0 Psig, February 12, 2013

Section 1R15

- IR 1413971; Byron OAD Investigated and Identified an Abnormal Indication of the Over

Current Relay, October 11, 2012

- NSWP-S-05; Concrete Expansion Anchors, Revision 7

- Calculation 7.16.10.2-BYR97-229; Structural Evaluation of Battery Racks and the Mounting

Details in 111 and 112 Battery Rooms of the Auxiliary Building, Revision 4

- Drawing 6E-0-3391AY; 125V DC Battery Rack Mounting Details

- Drawing M-11978; Bus 111 & 211 125V DC L Two Step EP3 Racks, Revision 2

4

Attachment

- Drawing 6E-0-3391AH; Byron Station Unit 1& 2, Electrical Equipment Mounting Details,

Revision S

- Drawing 64-05906; Floor Rack - Two Step EQ Protected for Plate Size 3 and 4 Batteries,

Revision 0

- CC-AA-112; Temporary Configuration Changes, Revision 19

- EC 378402; Single Use Evaluation for 1/2 of SX Cubical Coolers Not Available, January 6, 2010

- EC 392429; Operation of SX Pump with Single Cubical Cooler, February 12, 2013

- IR 1465872; Review of Braidwood IR 1459353 - PZR PORV Accumulator Pressure,

January 22

- CN-RRA-00-47; Calculational Table for Byron and Braidwood Natural Circulation Cooldown,

Revision 1

Section 1R18

- Performance Verification Testing; RCFC Check Dampers for Byron Units 1 and 2, July 1981

- Sargent & Lundy Fan Check Dampers for Byron Units 1 and 2, March 5, 1985

- Material and Equipment Receiving and Inspection Report CECo Engineering and

Construction, June 30, 1981

- Material and Equipment Receiving and Inspection Report CECo Engineering and

Construction, June 30, 1981

- Q.F.2910.24; Project No. 4391-05, Tornado/Isolation Dampers, May 11, 1981

- Q.F.2910.24; Project No. 4392-05, Tornado/Isolation Dampers, May 11, 1981

- IR 1419184; RCFC Damper Missing Springs; September 27, 2012

- IR 1419189; RCFC Damper Missing Springs; September 27, 2012

- IR 1419190; RCFC Damper Missing Springs; September 27, 2012

- IR 1419192; RCFC Damper Missing Springs; September 27, 2012

- IR 1474498; NRC Follow-Up - RCFC Discharge Check Damper; February 7, 2013

Section 1R19

- IR 1473967; No SX PP Cubicle Cooler Tubesheet Degradation Margin Exists,

February 11, 2013

- WO 1493809; 214 Instrument Inverter EOC Walkdown Due to 211 INV Failure, Revision 1

- WO 1591475; 1SX01PA Comprehensive IST Required for Essential Service Water Pump,

February 14, 2013

- BOP IP-1; Instrument Bus Inverter Startup, Revision 14

- IR 1472776; ACB 1442 Drives On-Line Risk Yellow for Both Units, February 8, 2013

- IR 1473015; Lockout Relay 486-1442 for Breaker 1442 is Degraded, February 8, 2013

- WO 1237471; Bus 144 Sat 142-2 Feed (ACB 1442) RES OC Relay Routine, February 8, 2013

- WO 1444425; Replace Lockout Relay on ACB 1442, February 9, 2013

- WO 1591475; 1SX01PA Comprehensive IST Requirement for Essential Service Water Pump,

February 14, 2013

- WO 1418630; Support Eddy Current Testing for 1A SX Pump Cubical Cooler,

February14, 2013

- WO 1366902; Operation Run Cooler and Check for Proper Operation, February 14, 2013

- WO 1314236; Preventative Maintenance on Breaker SAT Feed, February 14, 2013

Section 1R20

- OP-AA-101-113-1004; Equipment Prompt: 2A Generator Stator Cooling Water Pump (2A GC)

Tripped, Revision 24

5

Attachment

- IR 1490321; Smoke Noticed Coming from the 2A FW Pump Motor, March 20, 2013

- IR 1490323; DRPI POD M-12 Indicated General Warning Following Reactor Trip, March 20,

2013

- IR 1493026; Smoke was Reported Coming from U2 Voltage Regulator Cabinet,

March 20, 2013

- IR 1490315; U-2 Reactor Trip - Loss of GC, March 20, 2013

- IR 1490330; Oil Leaking From Exciter End of Main Generator, March 20, 2013

- IR 1490407; Need Cleanup of Generator Oil Leak in Various TB Elevations, March 21, 2013

- IR 1490453; U2 RCDT Elevated Inputs Investigation, March 21, 2013

- IR 1490635; Following U2 Reactor Trip, 2AR11J went Dark Blue and then White,

March 21, 2013

Section 1R22

- 1BOSR 3.1.5-1; Train A Solid State Protection System Surveillance, Revision 32

- WO 1469526 01; ESF Relay Train Reactor Trip - K636/2FW039S, February 25, 2013

- IR 631199; Revise Unit Two Schematic Diagram 6E-2 4030FW56, May 18, 2007

- IR 848809; 12/15 E-3 Schedule Review, November 23, 2008

- IR 1064332; Inadequate Technical Information Provided for New SSPS Cards, May 2, 2010

- IR 1293130; UV Driver Card Vulnerability in OE 34462 Applicable at Byron,

November 21, 2011

- IR 1323037; Unexpected FWI While Closing RX Trip Breakers, February 5, 2012

- IR 1328319; Unexpected Ground Reading During SSPS Surveillance, February 17, 2012

- IR 1329012; Unexpected FWI While Closing RX Trip Breakers, February 20, 2012

- IR 1329908; Low Contact Volts Found During SSPS - Not Unusual, February 21, 2012

- IR 1374658; Low Voltage Reading During 2BOSR 3.1.5-2, June 5, 2012

- WO 1588151; 1CS01PB Comprehensive IST Requirements for Containment Spray Pump,

January 29, 2013

- BOP CS-5; Containment Spray System Recirculation to the RWST, Revision 11

- WO 1609614; 1A Diesel Generator Operability Surveillance, February 6, 2013

- 1BOSR 8.1.2-1; Unit 1 Train A Diesel Generator Operability Surveillance, Revision 20

- WO 1596040; ESF Relay Train B CS-K644 ESFAS Instrumentation ESF Relay Surveillance,

February 28, 2013

- WO 1597146; 2CS01PB Comprehensive IST Requirements for Containment Spray Pump,

February 28, 2013

Section 2RS4

- Final Response to Task Interface Agreement 2012-05; ML12268A330; October 16, 2012

Section 4OA1

- Power History Curves for Unit 1 and Unit 2, January 2012 through December 2012

- Perfomance Indicator Data as Reported for the Period January 2012 through December 2012

- IR 1319908; B2F26 U2 Reactor Trip Due To Electrical Fault and Unusual Event,

January 30, 2012

- IR 1323547; B2F27 Manual Reactor Trip and Manual Auxiliary Feedwater Actuation,

February 6, 2012

6

Attachment

Section 4OA2

- IR 1474066; Issues With SX to CC MOD Installation, February 11, 2013

- IR 1477430; Insufficient Insertion of Anti-Vibration Bars in Alloy 600, February 19, 2013

- IR 1413971; EACE - 1B RH Pump Trip Due to CO-5 Overcurrent Relay Operation,

September 17, 2012

- IR1272187; Issues Applicable to Byron from Bwd Mod/50.59 Inspection; October 4, 2011

- IR 1296141; NER NC-11-045-Y Fleet Wide Actions; September 28, 2011

- Byron Document No. DS-MC-01-BY; Certification of Design Specification for Primary

Containment Piping Penetration Assemblies; Revision 3

- Byron/Braidwood Document No. 01-10-52; Bryon/Braidwood Piping Design Specification;

Revision 2

- Calculation No. 13.2.29BY; Mechanical Component Support 1SI06025V; Revision 2X

- ER-AA-380; Primary Containment Leakrate Testing Program, Revision 9

- BVP 800-39; Primary Containment Leakrate Testing Program, Revision 10

- 1BOSR 6.1.1-19; Unit 1 Primary Containment Type C Leakage Rate Tests and IST Tests of

the OffGas System, Revision 8

- 2BVSR 6.1.1-24; Unit 2 Summation of Primary Containment Type B & C Local Leakage Tests

for Acceptance Criteria, Revision 12

- 1BVSR 6.1.1-24; Unit 2 Summation of Primary Containment Type B & C Local Leakage Tests

for Acceptance Criteria, Revision 15

- IR 1298667; Long Term LCO for VQ Valves Needs Resolution, December 6, 2011

- IR 1306607; Long Term LCO Extent of Condition Review Per IR 1298667, December 26, 2011

- EC 390536; Determine Acceptability of Code Case N-597-2 use on FAC Components

1FW085B/D, Revision 0

- IR 1412470; B1R18 FAC Component 1FW085B Exam Failure, September 13, 2012

- IR 1415327; B1R18 FAC Component 1FW085D Exam Failure, September 13, 2012

Corrective Action Documents As a Result of NRC Inspection

- IR 1487707; NRC ID UFSAR Discrepancy-Appendix A, Page A.1.57-1; March 14, 2013

- IR 1478188; NRC Identified Use of CMTR in a 80's Calculation; February 21, 2013

- IR 1490153; NRC/IEMA 1A DG HELB Modification Walkdown; March 20, 2013

- IR 1493278; NRC IDed: PDP 50.59 Enhancement Required, March 27, 2013

Section 4OA5

- IR 1466355; FUK: Update UFSAR Regarding External Flooding, January 24, 2013

- IR 1472808; FUK: Effect of Local Intense Precipitation on FHB and SFP PP, February 8, 2013

- IR 1474686; FUK: Concrete Steps on 401 FHB to Areas 5 & 7, February 13, 2013

- IR 1475877; Blockwall Penetrations in SFP Pump Room, February 15, 2013

- IR 1484749; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013

- IR 1484755; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013

- IR 1484758; FUK: MCC 133X1 Fasteners Seismic Walkdown, March 7, 2013

- IR 1484765; FUK: MCC 132X3 Fasteners Seismic Walkdown, March 7, 2013

- IR 1484768; FUK: MCC 131X3 Fasteners Seismic Walkdown, March 7, 2013

Corrective Action Documents As a Result of NRC Inspection

-IR 1453636; FUK: Flooding and Seismic Walkdowns, December 18, 2012

7

Attachment

LIST OF ACRONYMNS USE

ADAMS

Agencywide Document Access and Management System

AISC

American Institute of Steel Construction

ASME

American Society of Mechanical Engineers

CAP

Corrective Action Program

CFR

Code of Federal Regulations

CLB

Current Licensing Basis

ECCS

Emergency Core Cooling System

ESF

Engineered Safety Feature

FHB

Fuel Handling Building

FIN

Finding

FSAR

Final Safety Analysis Report

IMC

Inspection Manual Chapter

IP

Inspection Procedure

IR

Inspection Report

IR

Issue Report

LCO

Limiting Condition for Operation

NCV

Non-Cited Violation

NEI

Nuclear Energy Institute

NRC

U.S. Nuclear Regulatory Commission

NRR

Office of Nuclear Reactor Regulation

NVLAP

National Voluntary Laboratory Accreditation Program

PARS

Publicly Available Records System

PI

Performance Indicator

PMP

Probable Maximum Precipitation

PORV

Power-Operated Relief Valve

RCFC

Reactor Containment Fan Cooler

ROP

Reactor Oversight Process

RFO

Refueling Outage

SDP

Significance Determination Process

SI

Safety Injection

SSC

Structure, System, or Component

SX

Essential Service Water

TI

Temporary Instruction

TIA

Task Interface Agreement

TLD

Thermoluminescent Dosimeter

TS

Technical Specification

UFSAR

Updated Final Safety Analysis Report

URI

Unresolved Item

WO

Work Order

M. Pacilio

-2-

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 (PARS) component of

NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public

Electronic Reading Room).

Sincerely,

/RA/

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 No. 05000454/2013002 and 05000455/2013002

w/Attachment: Supplemental Information

cc w/encl:

Distribution via ListServ

DOCUMENT NAME: G:\\DRPIII\\BYRO\\Byron 2013 002.docx

Publicly Available

Non-Publicly Available

Sensitive

Non-Sensitive

To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy

OFFICE

RIII

NAME

TDaun:dtp

EDuncan

DATE

04/26/13

04/29/13

OFFICIAL RECORD COPY

Letter to M. Pacilio from E. Duncan dated April 29, 2013.

SUBJECT:

BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION

REPORT 05000454/2013002; 05000455/2013002

DISTRIBUTION:

Doug Huyck

RidsNrrDorlLpl3-2 Resource

RidsNrrPMByron Resource

RidsNrrDirsIrib Resource

Chuck Casto

Cynthia Pederson

Steven Orth

Allan Barker

Christine Lipa

Carole Ariano

Linda Linn

DRPIII

DRSIII

Tammy Tomczak

Patricia Buckley

ROPreports.Resource@nrc.gov

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