IR 05000454/2012002

IR 05000454-12-002, 05000455-12-002; 01/01/2012 - 03/31/2012; Byron Station, Units 1 & 2; Fire Protection and Plant Modifications

ML12132A034
Person / Time
Site:	Byron
Issue date:	05/10/2012
From:	Eric Duncan Region 3 Branch 3
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-12-002
Download: ML12132A034 (45)

Text

UNITED STATES May 10, 2012

SUBJECT:

BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000454/2012002; 05000455/2012002

Dear Mr. Pacilio:

On March 31, 2012, 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 findings which were discussed on April 5, 2012, with Mr. T. Tulon and other members of your staff.

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

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

Three NRC-identified findings of very low safety significance (Green) were identified during this inspection.

These findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy.

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

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 Resident Inspector Office at the Byron Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document 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 and 50-455 License Nos. NPF-37 and NPF-66

Enclosure:

Inspection Report No. 05000454/2012002 and 05000455/2012002 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-454; 50-455 License Nos: NPF-37; NPF-66 Report Nos: 05000454/2012002 and 05000455/2012002 Licensee: Exelon Generation Company, LLC Facility: Byron Station, Units 1 and 2 Location: Byron, IL Dates: January 1, 2012, through March 31, 2012 Inspectors: B. Bartlett, Senior Resident Inspector J. Robbins, Resident Inspector R. Ng, Project Engineer J. Dalzell-Bishop, Reactor Engineer J. Cassidy, Senior Health Physicist A. Garmoe, Braidwood Resident Inspector B. Jose, Senior Reactor Engineer E. Sanchez Santiago, Reactor Inspector C. Thompson, Resident Inspector, Illinois Emergency Management Agency Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000454/2012002, 05000455/2012002; 01/01/2012 - 03/31/2012;

Byron Station, Units 1 & 2; Fire Protection and Plant Modifications.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Three Green findings were identified by the inspectors. The findings were considered Non-Cited Violations (NCVs) of NRC regulations.

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Assigned cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low safety significance (Green) and an associated NCV of Byron Operating License Condition 2.E when fireproofing material on a structural steel beam in the 2A Safety Injection (SI) Pump Room was identified as missing. As part of their immediate corrective actions, the licensee entered this issue into their correction action program (CAP) as Issue Report (IR) 1308297 and implemented compensatory measures that included hourly fire watches until fireproofing of the steel beam was subsequently completed.

The finding was determined to be more than minor in accordance with IMC 0612,

Appendix B, Issue Screening, since it was associated with the Protection Against External Events 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. In accordance with IMC 0609, Appendix F, Attachment 1, Application of Fire Protection SDP Phase 1 Worksheet, the finding screened as having very low safety significance (Green) since although the finding was associated with a degradation of fire confinement due to the incomplete application of fireproofing material to the beam and the degradation rating was determined to be Moderate, the degraded barrier still provided a minimum of 20 minutes of fire endurance protection. This finding had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area because the licensee failed to identify and therefore assess this issue completely, accurately, and in a timely manner commensurate with the safety significance of the issue P.1(a). (Section 1R05)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50.55a(g)4 when licensee personnel failed to perform system leakage testing in a timely manner as required by Section XI of the American Society of Mechanical Engineers (ASME) Code following modification activities that added piping and associated welds between the Unit 1 and Unit 2 Component Cooling

Water (CC) and Essential Service Water (SX) systems. The licensee entered this issue into their CAP as IR 1348236 and performed the required system leakage tests, which were all found to be acceptable.

The finding was determined to be more than minor in accordance with IMC 0612,

Appendix B, Issue Screening, because it was associated with the Mitigating Systems Cornerstone attribute of Procedure Quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609,

Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone.

Specifically, the inspectors answered Yes to Question 1 - Is the finding a design or qualification deficiency confirmed not to result in a loss of operability or functionality?

Based upon this Phase 1 screening, the inspectors concluded that the finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the Resources component of the Human Performance cross-cutting area because the licensee failed to include the necessary ASME testing requirements in the modification package and the work performance package to ensure adequate performance of an activity which affected testing of a safety-related modification to risk-significant systems, and thereby ensure nuclear safety H.2(c). (Section 1R18.1)

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XIV, Inspection, Test, and Operating Status, when licensee personnel failed to control the operating status of eight manual isolation valves that were installed as part of a modification. Specifically, the licensee performed a modification that added piping between the CC and SX systems while the systems were operable and in service, but did not ensure appropriate operational control of system isolation boundaries. As part of their immediate corrective actions, the licensee entered this issue into their CAP as IR 1347396 and placed temporary identification tags on the valves and initiated a Clearance Order to control the position of these valves.

The finding was determined to be more than minor in accordance with IMC 0612,

Appendix B, Issue Screening, because it was associated with the Mitigating Systems Cornerstone attribute of Procedure Quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609,

Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone.

Specifically, the inspectors answered Yes to Question 1 - Is the finding a design or qualification deficiency confirmed not to result in a loss of operability or functionality?

Based upon this Phase 1 screening, the inspectors concluded that the finding was of very low safety significance (Green). This finding had a cross-cutting aspect in the Work Control component of the Human Performance cross-cutting area because licensee personnel failed to properly coordinate work activities between operations and maintenance groups, which potentially impacted the pressure boundary of a safety-related system, thereby affecting nuclear safety H.3(b). (Section 1R18.2)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near full power throughout most of the inspection period. On February 28, 2012, an insulator failed in the switchyard and the Unit lost offsite power. A Notice of Unusual Event (NOUE) was declared, but the Unit remained on line and at full power. Offsite power was restored the following day and the NOUE was terminated. On March 10, 2012, the turbine generator was taken offline and power was reduced to 15 percent for a maintenance work window to replace electrical insulators. Following the identification of a boric acid leak inside of containment during insulator replacement activities, the Unit was shut down and placed in Mode 5, Cold Shutdown, to address the identified leak. The Unit was restarted on March 15, 2012, and operated at or near full power for the remainder of the inspection period.

Unit 2 operated at or near full power throughout most of the inspection period. On January 30, 2012, an insulator failed in the switchyard causing a complete loss of offsite power. A NOUE was declared and the Unit began a controlled natural circulation cooldown. Offsite power was restored and the NOUE was terminated the following day. During the return to service on February 6, 2012, the Unit was manually tripped when steam generator water level exceeded expectations. The Unit was restarted and returned to power the following day. An NRC Special Inspection Team was dispatched to review the circumstances of the January 30, 2012, event and their observations are documented in Inspection Report (IR) 05000455/2012-008. On March 16, 2012, the turbine generator was taken offline and power was reduced to 15 percent for a maintenance work window to replace electrical insulators. The Unit was returned to full power on March 18, 2012 and operated at or near full power for the remainder of the inspection period.

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition - High Winds Forecast During

Station Auxiliary Transformer Outage with Associated Switchyard Work in Progress

a. Inspection Scope

Since high winds were forecast in the vicinity of the facility for March 6, 2012, the inspectors reviewed the licensees overall preparations and protection for the expected weather conditions. Specifically, the inspectors assessed the licensees readiness for adverse weather conditions with high winds in the area during the Unit 2 station auxiliary transformer (SAT) Outage on March 6, 2012.

The inspectors walked down the emergency alternating current (AC) power systems because their safety-related functions could be adversely affected or required as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors determined whether the licensee staffs preparations conformed to site procedures and determined whether the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. The inspectors also reviewed a sample of Corrective Action Program (CAP) items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment.

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

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 2 Train A DC [Direct Current] Bus 211 during Scheduled Maintenance on the Unit 2 Train B Emergency Diesel Generator (DG);

• Unit 1 Train B SI while Unit 1 Train A SI was Out of Service for Maintenance; and

• Unit 2 Train A Auxiliary Feedwater (AF) while Unit 2 Train B AF was Out of Service for Maintenance.

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

.

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

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on the following:

• Unit 2 Train A SI Pump Room (Fire Zone 11.3A-2);

• Unit 2 Main Steam & Auxiliary Feedwater Pipe Tunnel (Fire Zone 18.3-2);

• Main Control Room (Fire Zone 2.1-0); and

• Operator Work Planning Office Outside of the Main Control Room (Fire Zone 2.1-1).

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

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

b. Findings

Structural Steel Beam Missing Fireproofing Materials

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated Non-Cited Violation (NCV) of Byron Operating License Condition 2.E when fireproofing material on a structural steel beam in the 2A SI Pump Room was identified as missing.

Description:

The inspectors performed a fire protection walkdown of the 2A SI Pump Room (Fire Zone 11.3A-2) and identified that a structural steel beam supporting the room ceiling was not fully fireproofed. The ceiling in the 2A SI pump room was also the floor of the Pipe Tunnel at Elevation 375 6. The beam was inside the 2A SI pump room with the uncovered section abutting the wall on Column Line Q. The licensee entered this issue into their CAP as IR 1308297. On January 4, 2012, the licensee completed an assessment of this condition and concluded that the exposed area exceeded the allowed exposed area as identified in Design Input Transmittal (DIT) BYR-ASD-0171. Because the exposed area exceeded the allowable area, the licensee initiated corrective actions to install additional fireproofing on the structural support. The licensee also implemented hourly fire watches from the time of discovery until the issue was corrected.

The inspectors determined that the structural steel beam carried a 2-hour fire rating in accordance with Section 2.3.11.12, Auxiliary Building General Area - Elevation 364 0 (Fire Zone 11.3-0), of the Byron Fire Protection Report. Specifically, Section 2.3.11.12 of the Byron Fire Protection Report stated, in part, The floor slab is supported by steel beams and columns which are protected with a fire-resistant coating and carry a 2-hour fire rating. Based on this arrangement, heat generated by a fire in the 2A SI pump room could weaken the structural steel beam to the point that the supported ceiling might collapse and cause damage to equipment located within the 2A SI pump room. The licensee stated that this condition likely existed since initial plant construction.

Analysis:

The incomplete application of fireproofing material on a structural steel beam that was required to have a 2-hour fire rating was a performance deficiency.

The finding was determined to be more than minor in accordance with Inspection Manual Chapter (IMC) 0612, Appendix B, Issue Screening, because it was associated with the Protection Against External Events 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.

The inspectors determined that the finding could be evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609, Significance Determination Process, Appendix F, Fire Protection Significance Determination Process, because it was associated with or involved impairment or degradation of a fire protection barrier.

The inspectors performed a Phase 1 evaluation using the Fire Protection SDP. The finding was associated with a degradation of fire confinement due to the incomplete application of fireproofing material to the beam. Based on a walkdown by the inspectors and the licensees evaluation, it was determined that there were no fire ignition source scenarios that would have caused the structural steel beams to weaken to the point that the ceiling might collapse. Therefore, no potentially challenging fire scenarios were identified.

Based on the above discussion, in Step 1.1 of Attachment 1 of IMC 0609, Appendix F, the inspectors identified that the Finding Category was Fire Confinement as the issue was associated with a degraded fire barrier that separated one fire area from another. In Step 1.2 of Attachment 1 of IMC 0609, Appendix F, the inspectors conservatively assigned a Fire Degradation Rating of Moderate since the element impacted by the finding was still expected to provide some substantial defense in depth benefit despite the noted deficiency. The finding was determined to be of very low safety significance (Green) when the inspectors answered Yes to Question 7 of Task 1.3.2, Supplemental Screening for Fire Confinement Findings - Does the degraded barrier provide a minimum of 20 minutes fire endurance protection and are the fixed or in situ fire ignition sources and combustible or flammable materials positioned such that, even considering fire spread to secondary combustibles, the degraded barrier or barrier element will not be subject to direct flame impingement?

The inspectors determined that the fire barrier in question was routinely inspected every 18 months during the performance of 0BVSR 10.g.8-1, Fire Rated Assemblies Visual Inspection. Therefore, the failure to identify the degraded condition reflected current performance. As a result, this finding was determined to have a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area because the licensee failed to identify and therefore assess this issue completely, accurately, and in a timely manner commensurate with the safety significance of the issue P.1(a).

Enforcement:

Byron Station Operating License Condition 2.E stated, in part, that the licensee shall implement and maintain in effect all provisions of the approved Fire Protection Program as described in the licensees Fire Protection Report.

Section 2.3.11.12, Auxiliary Building General Area - Elevation 364 0 (Fire Zone 11.3-0), of the Byron Fire Protection Report stated, in part, that, The floor slab of the tunnel at elevation 375 feet 6 inches is a 27-inch clear cover of structural reinforced concrete over 3-inch fluted steel decking formwork. It is supported by steel beams which are protected with a fire resistant covering and carry a minimum 2-hour fire rating.

Contrary to the above, since initial construction of Byron Unit 2 the structural steel beam in the 2A SI Pump Room abutting the wall on Column Line Q was not fireproofed to a 2-hour fire rating as required by the Byron Station Fire Protection Report and Operating License Condition 2.E. As part of their immediate corrective actions, the licensee implemented compensatory measures that included hourly fire watches until additional fireproofing was installed. Because this violation was of very low safety significance and because this issue was entered into the licensees CAP as IR 1308297, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000455/2012002-01, Structural Steel Beam Missing Fireproofing Materials)

1R06 Flooding

.1 Underground Vaults

a. Inspection Scope

The inspectors reviewed underground manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors verified that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices, such as a sump pump, were used, the inspectors determined whether the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submerged conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground manholes subject to flooding:

• Manhole 0A1;

• Manhole 0A2;

• Manhole 0B1;

• Manhole 0B2; and

• Manhole 1ML.

Documents reviewed are listed in the attachment.

This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review

a. Inspection Scope

On March 13, 2012, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and emergency plan actions and notifications.

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

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.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

On January 31, 2012, the inspectors observed control room operators during removal of the power supplies for Unit 2 from the DGs to the normal offsite power lines during restoration activities following the January 30, 2012, NOUE. This was an activity that required heightened awareness or 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 performance in these areas was compared to pre-established operator action expectations, procedural compliance, and task completion requirements. Documents reviewed are listed in the Attachment.

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

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Control Room Heating, Ventilation, and Air-Conditioning (HVAC) Damper 0VC18Y Following Repair of Damaged Seals; and

• Possible Under-Torque of Valve 1RC8042B Resulting in Unidentified Reactor Coolant System (RCS) Leakage.

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

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the Maintenance Rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

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

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

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

b. Findings

Potential Under-Torque of Valve 1RC8042B

Introduction:

In response to the identification of boric acid leakage from valve 1RC8042B, the inspectors identified an Unresolved Item (URI) associated with the effectiveness of previous maintenance performed on this valve.

Description:

Following the licensees identification of valve 1RC8042B as a source of unidentified leakage in containment in March 2012, the inspectors selected this valve for a maintenance effectiveness review. The inspectors identified that a work package associated with this valve repair was performed during the previous Unit 1 refueling outage in March 2011. The work package for the repair identified an existing boric acid leak and directed the replacement of the valve bonnet. Therefore, the material condition of 1RC8042B was restored and subsequently degraded in less than 1 year. The licensee entered this issue into their CAP as IR 1339922, Perform Rework Evaluation on 1RC8042B. At the end of the inspection period, the licensee was still in the process of evaluating this issue. This URI will remain open pending the licensees completion of the rework evaluation and the inspectors review and follow up of the evaluation.

(URI 05000454/2012002-02, Potential Under-Torque of Valve 1RC8042B)

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Unit 2 Risk During Scheduled Train B DG Outage;

• Unit 1 and Unit 2 Risk During Scheduled Unit 2 SAT Outage; and

• Unit 1 and Unit 2 Risk During Scheduled Unit 1 SAT Outage.

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

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

b. Findings

No findings were identified.

1R15 Operability Evaluations

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Unit 1 Essential Service Water (SX) Due to Removal of Piping Section and Seismic Supports During Maintenance;

• Unit 1 Train B DG Due to Turbo Charger Thrust Bearing Alarm Pressure Sensor Issues;

• Peak Cladding Temperature Concerns;

• Unit 1 Containment Leakage Detection System Due to Boric Acid Accumulation in System Drain; and

• Component Cooling Water (CC) System and SX System Following NRC Identification of Licensee Failure to Meet All ASME Code Requirements.

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

.

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

b. Findings

Boric Acid Accumulation Identified in Leakage Detection Trough

Introduction:

In response to boric acid accumulation in a leakage detection trough in Unit 1 containment, the inspectors identified an URI associated with the past operability of Unit 1 containment leakage detection instrumentation.

Description:

During a Unit 1 containment walkdown the inspectors identified a boric acid leak on sample valve 1PS9365B located on the 426 elevation. The 426 elevation of containment utilized floor grating; therefore the inspectors inspected the lower levels of containment to determine if any other equipment had been impacted by the leak. On the 377 elevation, the inspectors identified a large area of boric acid accumulation. The inspectors subsequently made the licensee staff aware of this additional boric acid accumulation. Photographs were subsequently taken by the licensee and provided to the Outage Control Center. The licensee entered this issue into their CAP as IR 1339957, 1PS9365 Has Leak From Either Packing or Bonnet.

In preparation for a Mode 5 to Mode 4 change, the licensee was required to perform an inspection and assessment of containment in accordance with 1BOSR Z.5.b.1-1, Unit 1 Containment Loose Debris Inspection, to ensure that the material condition of containment was adequate to support at-power operations. The inspectors performed an independent inspection following the licensees inspection and assessment. During this independent inspection, the inspectors identified that boric acid associated with boric acid leakage on the 377 elevation documented in IR 1339957 was still present.

Specifically, boric acid had accumulated in a trough that was located along the wall of the inner containment structure. The accumulated boric acid completely covered the drain located in the trough. The purpose of this trough was to collect any potential leakage and direct that leakage to a drain that led to a sump. The flow of water into the sump as well as the level of this sump was monitored to facilitate the prompt identification of containment leakage. The leakage detection instrumentation for the RCS was required to be operable in Modes 1-4. Unit 1 was in Mode 4 at the time of this discovery. This issue was entered into the licensees CAP as IR 1341380, NRC Identified Boric Acid Covering Floor. The impact of this issue on the leakage detection instrumentation was still being assessed by the licensee at the end of the inspection period. This URI will remain open pending the licensees completion of their assessment of the issue and the inspectors review of that assessment. This issue is also discussed in Section 71111.20 of this report. (URI 05000454/2012002-03, Boric Acid Accumulation Identified in Leakage Detection Trough)

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modifications:

• Unit 1 RC8042B Diaphragm Valve Replaced with Globe Valve; and

• Engineering Change 383216 and EC 383934, Safety-Related Make Up to the CC System.

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 systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and were 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

.

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

b. Findings

(1) Incomplete Component Cooling Water System and Essential Service Water System Code Examinations

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR 50.55a(g)4 when licensee personnel failed to perform a system leakage test in a timely manner as required by ASME Code Section XI for the required weld volume for the Unit 1 and 2 CC system and SX system welds following system modification activities.

Description:

The licensee performed a modification to Unit 1 and Unit 2 which added SX as a source of safety-related makeup water to the CC system. The licensee performed this modification with both the CC and SX systems operable and in service. The modification included the addition of 1.5-inch diameter ASME Code Class 3 piping connections between the two systems for both trains of both Units. To support the operability and continued service of the CC and SX systems during the modification activities, the licensee utilized a contractor to perform hot taps in CC and SX system piping.

To prepare for the hot taps to be installed, the licensee welded a Code Class 3 weldolet to the surface of the CC and SX piping at a total of eight locations for the two trains in both Unit 1 and Unit 2. Prior to welding the weldolets to the CC and SX piping, the weldolets had been previously welded to piping that included a safety-related manual isolation valve for each of the eight weldolets. Once the welds were completed, a volumetric examination was performed in accordance with ASME Code requirements.

Subsequently, the hot tap was performed in which a 1.5-inch hole was drilled in the CC and SX piping through the manual isolation valve.

The hot taps and associated valves for each of the eight connections were installed at different times. The first of the new valves, 2CC200A, was installed on December 21, 2011. The remaining seven valves, 1SX280A, 1SX280B, 2SX280A, 2SX280B, 1CC200A, 1CC200B, and 2CC200B were installed over the following weeks.

The 1989 Edition of ASME Code Section XI, Article IWA-4540, Pressure Testing of Class 1, 2, and 3 Items, required that repair and/or replacement activities performed by welding or brazing on a pressure-retaining boundary shall include a hydrostatic or system leakage test in accordance with IWA-5000, prior to, or as part of, returning to service.

Following the hot tapping activity for each of the eight connections, the newly installed piping became a part of the Code Class 3 pressure boundary of the CC and the SX systems and was required to meet the ASME Code as described above, including testing requirements. As the piping was constructed in accordance with the ASME Code and a volumetric examination had been previously performed, only a final system leakage test was required by the ASME Code for each of the eight new connections.

However, this test was not performed for any of these connections until questioned by the NRC inspectors.

The licensee entered this issue into their CAP as IR 1348236 and immediately performed the required system leakage tests. All tests were successful.

Analysis:

The inspectors determined that the failure to complete required system leakage tests in a timely manner following CC and SX piping modifications was a performance deficiency.

The finding was more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Procedure Quality 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. Specifically, this issue increased the risk of failure for the CC and SX systems, which affected the Mitigating Systems Cornerstone objective of equipment performance and reliability.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone. Specifically, the inspectors answered Yes to Question 1 - Is the finding a design or qualification deficiency confirmed not to result in a loss of operability or functionality? In this case, the licensee had performed and passed a volumetric examination prior to the inspectors observation and subsequent to the inspectors questions the licensee successfully passed the system leakage test. Based upon this Phase 1 screening, the inspectors concluded that the finding was of very low safety significance (Green).

This finding had a cross-cutting aspect in the Resources component of the Human Performance cross-cutting area because the licensee failed to include the necessary ASME testing requirements in the modification package and the work performance package to ensure adequate performance of an activity, which affected testing of a safety-related modification to risk-significant systems and thereby ensure nuclear safety

H.2(c).

Enforcement:

Title 10 CFR 50.55a(g)4 required in part, that throughout the service life of a pressurized water reactor facility, components classified as ASME Code Class 1, 2, and 3 must meet the requirements of Section XI.

The 1989 Edition of ASME Code Section XI, Article IWA-4540, Pressure Testing of Class 1, 2, and 3 Items, required that repair and/or replacement activities performed by welding or brazing on a pressure-retaining boundary shall include a hydrostatic or system leakage test in accordance with IWA-5000, prior to, or as part of, returning to service.

Contrary to the above, on March 26, 2012, the NRC inspectors identified that Code Class 3 piping welds on the safety-related portion of the CC and SX systems had not received a required system leakage test beginning on December 21, 2011, when piping associated with valve 2CC200A was installed in the SX system and over the following weeks when similar piping associated with valves 1SX280A, 1SX280B, 2SX280A, 2SX280B, 1CC200A, 1CC200B, and 2CC200B was added to the SX and the CC systems. The affected portions of the SX and CC systems remained in service during the piping installation activities and therefore should have been leak tested immediately following the installation activities. Immediate corrective actions included performing the system leakage tests, which were all found to be acceptable. Because this violation was of very low safety significance and because this issue was entered into the licensees CAP as IR 1348236, this violation is being treated as a NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000454/2012002-04; 05000455/2012002-04, Incomplete CC System and Essential Service Water System Code Examinations)

(2) Failure to Control the Operating Status of Eight New Valves Affecting Two Safety-Related Systems

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XIV, Inspection, Test, and Operating Status, when licensee personnel failed to control the operating status of manual isolation valves that were installed as part of a modification that added piping between the CC and SX systems.

Description:

The licensee performed a modification to Unit 1 and Unit 2 which added SX as a source of safety-related makeup water to the CC system. The licensee performed this modification with both the CC and SX systems operable and in service. The modification included the addition of 1.5-inch diameter ASME Code Class 3 piping connections between the two systems with associated isolation valves. To support the operability and continued service of the CC and SX systems during the modification, the licensee utilized a contractor to perform hot taps in CC and SX system piping. As each of the two trains of each of the two Units had a connection between the CC and the SX systems, there were a total of eight hot taps and associated isolation valves installed.

The hot taps and associated valves for each of the eight connections were installed at different times. The first of the new valves, 2CC200A, was installed on December 21, 2011. The remaining seven valves, 1SX280A, 1SX280B, 2SX280A, 2SX280B, 1CC200A, 1CC200B, and 2CC200B, were installed over the following weeks. To maintain system integrity, the manual isolation valves were left closed following the hot tap and the valves were verified closed by a non-licensed equipment operator in accordance with the work order instructions. However, the valves had no formal labeling and were not otherwise controlled by the licensees operating department.

Quality Assurance Topical Report NO-AA-10, Revision 86, Section 14, Step 2.2.4, required, in part, that When equipment is ready to be returned to service, operating personnel place the equipment in operation and verify and document its functional acceptability. The Company assures return to normal conditions using approved procedures, includingreturning valves to proper start-up or operating positions. In the case of the modification being discussed, a single manual valve separating the CC or SX systems ensured system integrity was maintained. This valve had no formal labeling, was not included in any operating procedure, was located in an area where the CC/SX cross-tie work was still being performed, and was not secured closed by any formal or informal mechanism. In addition, no communication had been made to the operating department that these valves should remain closed. The inspectors were concerned that one or more of the valves could be inadvertently opened resulting in leakage out of either the CC or the SX systems. The licensee entered this issue into their CAP as IR 1347396. Immediate corrective actions included placing temporary identification tags on the eight valves and initiating a Clearance Order to control the position of the valves.

Analysis:

The inspectors determined that the failure of the licensee to control the operating status of eight new valves in the CC and SX systems was a performance deficiency.

The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Procedure Quality 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. Specifically, this issue increased the risk of failure for the CC and SX systems, which affected the Mitigating Systems Cornerstone objective of equipment performance and reliability.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone. Specifically, the inspectors answered Yes to Question 1 - Is the finding a design or qualification deficiency confirmed not to result in a loss of operability or functionality? Therefore, the finding was determined to be of very low safety significance (Green). In this case, the licensee had informal labeling on the valves, had closed the valves in accordance with their work instructions, had an equipment operator verify the valves closed as required by their work instructions, and the contract workers in the area had received training not to operate valves without permission.

This finding had a cross-cutting aspect in the Work Control component of the Human Performance cross-cutting area because licensee personnel failed to properly coordinate work activities between operations and maintenance groups, which potentially impacted the pressure boundary of a safety-related system, thereby affecting nuclear safety

H.3(b).

Enforcement:

10 CFR Part 50, Appendix B, Criterion XIV, Inspection, Test, and Operating Status, required, in part, that Measures shall also be established for indicating the operating status of structures, systems, and components of the nuclear power plant, such as by tagging valves and switches, to prevent inadvertent operation.

Contrary to the above, on March 26, 2012, the NRC inspectors identified that safety-related valves 1SX280A, 1SX280B, 2SX280A, 2SX280B, 1CC200A, 1CC200B, 2CC200A, and 2CC200B that had been added to the CC and the SX system starting on December 21, 2011, had not been tagged or controlled to prevent inadvertent operation.

Immediate corrective actions included placing temporary identification tags on the valves and initiating a Clearance Order to control the position of these eight valves. Because this violation was of very low safety significance and because this issue was entered into the licensees CAP as IR 1347396, this violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000454/2012002-05; 05000455/2012002-05, Failure to Control the Operating Status of Eight New Valves Affecting Two Safety-Related Systems)

1R19 Post Maintenance Testing

.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 2 Train B DG Following Governor Replacement;

• Unit 2 Train B AF Pump Monthly Surveillance Performed Following Maintenance;

• Unit 2 Train B AF Pump Diesel Engine Starting Sequence and Overspeed Trip Test;

• Unit 1 Train B Auxiliary Oil Pump for SX Pump Following Motor Replacement;

• Unit 1 Train B AF to Steam Generator Isolation Valve Stem & Thermal Overload Work; and

• Work Order 1517879-04, Test Following Replacement of Pressure Switch for Unit 1 Train B DG Turbocharger Thrust Bearing Failure Alarm.

These activities were selected based upon the 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 basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety.

Documents reviewed are listed in the Attachment.

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

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for an unscheduled Unit 2 outage that was caused by the failure of a switchyard insulator on January 30, 2012. The inspectors also observed the licensees return to power and subsequent unplanned manual reactor trip during power ascension on February 6, 2012. The inspectors then observed the licensees restart of Unit 2 on February 7, 2012. On March 6, 2012, the licensee shutdown Unit 1 for planned maintenance outage B1M03 and restarted the Unit on March 16, 2012, following a cool down to Mode 5 to repair a RCS valve. On March 16, 2012, the licensee shut down Unit 2 for planned maintenance outage B2M06 and restarted the Unit on March 18, 2012. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The inspectors observed or reviewed the reactor shutdown and cooldown, outage equipment configuration and risk management, electrical lineups, control and monitoring of decay heat removal, control of containment activities, startup and heatup activities, and identification and resolution of problems associated with the outage.

This inspection constituted four outage samples of other activities as defined in IP 71111.20-05.

b. Findings

The inspectors performed several containment walkdowns following the Unit 1 down power. The Unit had been on line for about 1 year following the last refueling outage and during that time the containment airborne tritium levels had been increasing, indicative of a possible RCS unidentified leak. The inspectors and some members of the licensees staff had concluded that a small leak was present. The leak size had been estimated at between 0.001 gallons per minute (gpm) and 0.01 gpm. The licensee had considered sending in a remote controlled robot inside of the primary containment radiation shield wall, but had not done so. Initially B1M03 had been planned for only a downpower to 15 percent with a plan to send in a robot. Personnel operating the robot identified an RCS leak and the licensee determined that entry into Mode 5, Cold Shutdown, was required in order to perform the repair. The inspectors performed an initial walk down of containment at 15 percent power and observed the robotic surveillance activities. Subsequently, when the licensee completed their Mode 5 entry, the inspectors performed another containment walk down inside of the radiation shield wall.

The inspectors identified a boric acid leak on sample valve 1PS9365B, located on the 426 elevation of containment. The 426 elevation of containment had a grated floor; therefore, the inspectors proceeded to the lower levels of containment to determine if any other equipment had been impacted by the leak. On the 377 elevation, the inspectors identified a large area of boric acid accumulation. The licensee entered this issue into their CAP as IR 1339957.

Additional information and an associated Unresolved Item is discussed further in Section 1R15 of this report.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• Unit 2 Response Time Testing of Installed Resistance Temperature Detectors;

• Generic Letter 89-13 Heat Exchanger Inspection for the Unit 2 Train B Jacket Water Upper and Lower Heat Exchangers;

• Unit 1 Train A Solid State Protection System Bi-Monthly Surveillance;

• Unit 2 Train B AF Pump 2AF01PB Inservice Testing (IST);

• Unit 1 Train B AF to Steam Generator Isolation Valves Stroke Time Test (IST/Containment Isolation Valves); and

• Unit 2 Train B Containment Spray Pump Comprehensive IST Requirements.

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

• did preconditioning occur;

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

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

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

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

• measuring and test equipment calibration was current;

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

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

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

• test equipment was removed after testing;

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

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

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

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

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

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

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

Documents reviewed are listed in the Attachment.

This inspection constituted three routine surveillance testing samples and three IST samples as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

This inspection constituted a partial sample as defined in IP 71124.01-05.

.1 Radiological Hazard Assessment (02.02)

a. Inspection Scope

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

• Replacement of 1RC8042B For these work activities, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if hazards were properly identified, including the following:

• identification of hot particles;

• the presence of alpha emitters;

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

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

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

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

b. Findings

No findings were identified.

.2 Instructions to Workers (02.03)

a. Inspection Scope

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

b. Findings

No findings were identified.

.3 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors selected several sealed sources from the licensees inventory records and assessed whether the sources were accounted for and verified to be intact.

The inspectors evaluated whether any transactions, since the last inspection, involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.

b. Findings

No findings were identified.

.4 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

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

b. Findings

No findings were identified.

.5 Risk-Significant High Radiation Area and Very High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors discussed with the radiation protection manager the controls and procedures for high-risk high radiation areas and very high radiation areas. The inspectors discussed methods employed by the licensee to provide stricter control of very high radiation area access as specified in 10 CFR 20.1602, Control of Access to Very-High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and Very-High Radiation Areas of Nuclear Plants. The inspectors assessed whether any changes to licensee procedures substantially reduce the effectiveness and level of worker protection.

The inspectors discussed the controls in place for special areas that have the potential to become very high radiation areas during certain plant operations with first line health physics supervisors (or equivalent positions having backshift health physics oversight authority). The inspectors assessed whether these plant operations required communication beforehand with the health physics group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including re-access authorization.

b. Findings

No findings were identified.

.6 Radiation Worker Performance (02.07)

a. Inspection Scope

The inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors assessed whether workers were aware of the radiological conditions in their workplace and the radiation work permit controls/limits in place, and whether their performance reflected the level of radiological hazards present.

b. Findings

No findings were identified.

.7 Radiation Protection Technician Proficiency (02.08)

a. Inspection Scope

The inspectors observed the performance of the radiation protection technicians with respect to all radiation protection work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace and the radiation work permit controls/limits, and whether their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

b. Findings

No findings were identified.

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

This inspection constituted a partial sample as defined in IP 71124.02-05.

.8 Radiological Work Planning (02.02)

a. Inspection Scope

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

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

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

b. Findings

No findings were identified.

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

a. Inspection Scope

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

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

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

The inspectors evaluated the licensees method of adjusting exposure estimates, or re-planning work, when unexpected changes in scope or emergent work were encountered. The inspectors assessed whether adjustments to exposure estimates (intended dose) were based on sound radiation protection and ALARA principles or if they were just adjusted to account for failures to control the work. The inspectors evaluated whether the frequency of these adjustments called into question the adequacy of the original ALARA planning process.

b. Findings

No findings were identified.

.10 Source Term Reduction and Control (02.04)

a. Inspection Scope

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

b. Findings

No findings were identified.

.11 Radiation Worker Performance (02.05)

a. Inspection Scope

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

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA2 Identification and Resolution of Problems

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

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included the complete and accurate identification of the problem; that timeliness was commensurate with the 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 included in the attached List of Documents Reviewed.

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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

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

b. Findings

No findings were identified.

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

.1 (Open) Licensee Event Report 05000454/2012-001, Revision 0, Unit 2 Loss of Normal

Offsite Power and Reactor Trip and Unit 1 Loss of Normal Offsite Power Due to Failure of System Auxiliary Transformer Inverted Insulators The licensee reported two events that had similar causes, each involving the loss of normal offsite power. The first occurred on January 30, 2012 on Unit 2 and the second occurred on February 28, 2012, on Unit 1. In both cases an electrical insulator failed in the switchyard resulting in a loss of offsite power to the associated Unit. The Unit 1 failure did not result in a trip of the Unit, but the Unit 2 failure did result in a plant trip.

Each failure resulted in the declaration of a NOUE.

An NRC Special Inspection Team was dispatched following the Unit 2 event and the results of the inspection were documented in Inspection Report 05000455/2012-008. An Unresolved Item was open pending the results of an internal Task Interface Agreement (TIA) with the Office of Nuclear Reactor Regulation.

Pending the results of the licensees root cause analysis and the inspectors review, this Licensee Event Report (LER) will remain open.

This event follow-up review constituted two samples as defined in IP 71153-05.

.2 (Open) Licensee Event Report 05000455/2012-001, Revision 0, Manual Reactor Trip

During Power Ascension Due to Steam Generator Level Approaching Turbine Trip Setpoint Caused by an Overly Complex Startup Procedure During the restart of Unit 2 on February 6, 2012, following the trip and NOUE on January 30, 2012, there was a level increase in the C loop steam generator and the supervisor directed a manual trip be performed.

At the end of the inspection period the licensee had not completed all the root cause assessments. Pending the review of these assessments, this LER will remain open.

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

4OA5 Other Activities

.1 Temporary Instruction 2515/182 - Review of the Industry Initiative to Control Degradation

of Underground Piping and Tanks

a. Inspection Scope

Leakage from buried and underground pipes has resulted in ground water contamination incidents with associated heightened NRC and public interest. The industry issued a guidance document, Nuclear Energy Institute (NEI) 09-14, Guideline for the Management of Buried Piping Integrity (ADAMS Accession No. ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued Revision 1 to NEI 09-14, Guidance for the Management of Underground Piping and Tank Integrity, (ADAMS Accession No. ML110700122) with an expanded scope of components, which included underground piping that was not in direct contact with the soil and underground tanks. On November 17, 2011, the NRC issued Temporary Instruction (TI)-2515/182 Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.

The inspectors reviewed the licensees programs for buried pipe, underground piping, and tanks in accordance with TI-2515/182 to determine if the program attributes and completion dates identified in Sections 3.3 A and 3.3 B of NEI 09-14, Revision 1, were contained in the licensees program and implementing procedures. For the buried pipe and underground piping program attributes with completion dates that had passed, the inspectors reviewed records to determine if the attribute was, in fact, complete and to determine if the attribute was accomplished in a manner which reflected appropriate practices in program management.

b. Observations Based upon the scope of the review described above, Phase I of TI-2515/182 was completed. The licensees buried piping and underground piping and tanks program was inspected in accordance with Paragraphs 03.01.a through 03.01.c of TI-2515/182 and was found to meet all applicable aspects of NEI 09-14, Revision 1, as set forth in Table 1 of the TI.

c. Findings

No findings were identified.

.2 Review of Institute of Nuclear Power Operations Report

The inspectors reviewed the Institute of Nuclear Power Operations Byron Station Training Accreditation Exit Report, dated August 2011. The report was presented to the National Nuclear Accrediting Board on November 16, 2011.

.3 (Update) Verification of Margin-to-Overfill Backfit Corrective Actions and Extent of

Condition Review: (VIO 05000454/2011013-01; 05000455/2011013-01, Restoring Compliance with Respect to Single Failures)

On January 19, 2011, the NRC issued Inspection Report 05000454/2011010; 05000455/2011010, and notified the licensee of the NRCs decision to issue a compliance backfit in order to address the Steam Generator Tube Rupture (SGTR)

Margin-to-Overfill (MTO) issue documented in URI 05000454/2009007-03; 05000455/2009007-03 and TIA 2010-002 (ML103230177). The report listed the licensees initial corrective actions and requested the licensee to provide a written response within 30 days of their assessment of the issue and a description of their intended actions to address the non-compliance, including a proposed schedule to complete those actions and an assessment of the extent of condition of this issue.

As documented in IR 05000454/2011013; 05000455/2011013, the licensee responded by letter dated February 18, 2011, and committed to the following:

The power supplies to the Steam Generators Power-Operated Relief Valves (PORVs) will be modified with a safety-related battery backup.

The licensee will issue a supplement to their February 18, 2011, response letter, in order to communicate any revisions to the modification installation schedule based on the online/outage determination.

An extent of condition review will be conducted of other transients and accidents outlined in Chapter 15 of the Byron Station UFSAR to identify similar discrepancies with respect to the inappropriate reliance or assumption of single active failure.

The identified discrepancies, if any, would be resolved within the CAP and communicated to the NRC Region III Regional Administrator.

The technical issue was considered open pending completion of the corrective actions (VIO 05000454/2011013-01; 05000455/2011013-01, Restoring Compliance with Respect to Single Failures).

During this inspection, the inspectors reviewed the licensees extent of condition review, UFSAR Chapter 15 accident analysis and Reactor Protection System (RPS) description, logic diagrams, schematic and wiring drawings. The inspectors determined the extent of condition was adequately scoped and involved a multi-discipline review. Concerns identified during the effort were entered into the CAP. No additional single failure vulnerabilities were identified. The inspectors had no concerns with the extent of condition review. The inspectors also performed an independent review of the RPS system because the term single active failure was used several times in the UFSAR and other licensing documents. The inspectors did not identify any concerns with single failure vulnerabilities during this review.

Based on the above review, the inspectors concluded the licensees extent of condition review appeared to be adequate.

The issue will remain open pending NRC verification that the proposed PORV power supply modifications are complete (VIO 05000454/2011013-01; 05000455/2011013-01, Restoring Compliance with Respect to Single Failures).

Documents reviewed are listed in the Attachment.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 5, 2012, the inspectors presented the inspection results to Mr. B. Youman, and other members of the licensee staff.

The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

• The inspection results for TI-2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, with Mr. Tim Tulon, Site Vice President, and other members of the licensee staff on February 1, 2012.

• The inspection results for the areas of Radiological Hazard Assessment and Exposure Controls; and Occupational ALARA Planning and Controls with Mr. Tim Tulon, Site Vice President, and other members of the licensee staff on March 16, 2012.

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

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Youman, Plant Manager

D. Gudger, Regulatory Assurance Manager

J. Langan, Regulatory Assurance Licensing Engineer

B. Spahr, Maintenance Director

B. Barton, Radiation Protection Manager

J. Bottomley, Outage Work Control Superintendent

K. Donovan, Corporate Manager Dry Cast Storage

T. Hulbert, Regulatory Assurance Assistant

S. Briggs, Operations Director

M. Wolfe, Site Reactor Services Manager

F. Hiort, Equipment Operator

M. Amer, Dry Cast Storage Engineer

T. Eliakis, Dry Cast Storage Project Manager

G. Voss, Dry Cast Storage Engineer

Nuclear Regulatory Commission

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

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000455/2012002-01 NCV Structural Steel Beam Missing Fireproofing Materials (Section 1R05)

05000454/2012002-02 URI Potential Under-Torque of Valve 1RC8042B (Section 1R12)

05000454/2012002-03 URI Boric Acid Accumulation Identified in Leakage Detection Trough (Section 1R15)

05000454/2012002-04 NCV Incomplete CC System and SX System Code Examinations

05000455/2012002-04 (Section 1R18)

05000454/2012002-05 NCV Failure to Control the Operating Status of Eight New Valves

05000455/2012002-05 Affecting Two Safety-Related Systems (Section 1R18)

Closed

05000455/2012002-01 NCV Structural Steel Beam Missing Fireproofing Materials (Section 1R05)

05000454/2012002-04 NCV Incomplete CC System and SX System Code Examinations

05000455/2012002-04 (Section 1R18)

05000454/2012002-05 NCV Failure to Control the Operating Status of Eight New Valves

05000455/2012002-05 Affecting Two Safety-Related Systems (Section 1R18)

Discussed

05000454/2011013-01 VIO Restoring Compliance with Respect to Single Failures

05000455/2011013-01 (Section 4OA5.1)

Attachment