IR 05000324/2013002

IR 05000325-13-002, 05000324-13-002; 01/01/13 - 03/31/13; Brunswick Steam Electric Plant, Units 1 & 2; Plant Modifications

ML13120A459
Person / Time
Site:	Brunswick
Issue date:	04/30/2013
From:	Randy Musser NRC/RGN-II/DRP/RPB4
To:	Annacone M Carolina Power & Light Co
References
EA-13-081 IR-13-002
Download: ML13120A459 (50)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ril 30, 2013

SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2013002 AND 05000324/2013002 AND EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Annacone:

On March 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Brunswick Unit 1 and 2 facilities. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 24, 2013, with you and other members of your staff.

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

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

One NRC identified finding of very low safety significance (Green) was identified during this inspection. The finding did not involve a violation of NRC requirements. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. The NRC is treating this violation as non-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation/finding or the significance of the NCV/finding, 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 II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Brunswick Steam Electric Plant. If you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the Brunswick Steam Electric Plant.

In addition, a violation of Technical Specification 3.6.4.1, Secondary Containment was identified.

Because the violation was identified during the discretion period described in Enforcement Guidance Memorandum 11-003, Revision 1, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted.

In accordance with 10 CFR 2.390 of the NRCs 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 NRCs 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/

Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62

Enclosure:

Inspection Report 05000325, 324/2013002 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62 Report Nos.: 05000325/2013002, 05000324/2013002 Licensee: Carolina Power and Light (CP&L)

Facility: Brunswick Steam Electric Plant, Units 1 & 2 Location: 8470 River Road, SE Southport, NC 28461 Dates: January 1, 2013 through March 31, 2013 Inspectors: M. Catts, Senior Resident Inspector M. Schwieg, Resident Inspector C. Dykes, Health Physicist (Section 2RS5)

L. Lake, Senior Reactor Inspection (Section 1R08)

A. Nielsen, Senior Health Physicist (Sections 2RS2, 2RS4, 4OA1, 4OA5)

W. Pursley, Health Physicist (Sections 2RS1, 2RS3, 4OA7)

J. Worosilo, Project Engineer (Sections 1R04, 1R05, 1R20)

Approved by: Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000325/2013002, 05000324/2013002; 01/01/13 - 03/31/13; Brunswick Steam Electric

Plant, Units 1 & 2; Plant Modifications.

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

The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, issued June 19, 2012 Significance Determination Process (SDP). The cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas, issued 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 operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process revision 4.

Cornerstone: Initiating Events

Green.

An NRC-identified Green finding was identified for the failure of the licensee to follow Procedure EGR-NGGC-0005, Engineering Change (EC), when performing the variable frequency drive (VFD) modification for the reactor recirculation pumps (RRPs).

Specifically, between April 4, 2010 and the present, the licensee inappropriately used a Rapid Field Release (RFR) to revise the power supplies for the relays in the VFD system without re-evaluating the EC, the 10 CFR 50.59 Screen/Evaluation, and the Failure Modes and Effects Analysis (FMEA). This resulted in a new failure mode on a loss of the power supply causing a RRP runback and placing the plant in a flow transient, and a loss of cooling to the RRP seals. The licensee entered this issue into the corrective action program (CAP) as nuclear condition report (NCR) 581202.

The performance deficiency associated with this finding was the failure of the licensee to follow Procedure EGR-NGGC-0005, Engineering Change (EC), when performing the VFD modification for the RRPs. The finding was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and affects the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, the VFD modification inappropriately causes a RRP runback on a loss of 480 VAC and core flow instability, and a loss of cooling to the RRP seals. Using IMC 0609, Appendix A, issued June 19, 2012, The SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance because as a transient initiator due to the RRP runback, the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined the finding was also of very low safety significance because as a loss of coolant accident (LOCA) initiator, after a reasonable assessment of degradation, the finding would not result in exceeding the reactor coolant system leak rate for a small break LOCA or likely affect other systems used to mitigate a LOCA resulting in a total loss of their function. The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately coordinate work activities by incorporating actions to address the impact of changes to the work scope, associated with the VFD modification, on the plant. H.3(b) (Section 1R18)

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 97 percent of rated thermal power (RTP). On February 8, 2013, the unit was down powered to 58 percent for a control rod sequence and power was returned to RTP on the same day and for the remainder of quarter.

Unit 2 began the inspection period at RTP. On January 5, 2013, the unit was down powered to 71 percent for rod improvement and power was returned to RTP on the same day. On January 12, 2013, the unit was down powered to 85 percent for rod improvement and power was returned to RTP on the same day. On March 2, 2013, the unit was shut down for a refueling outage and remained shut down for the remainder of the quarter.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 2 125 VDC during fuel movement on January 20, 2013

• Unit 1 standby liquid control on February 28, 2013

• Unit 2 standby gas treatment A on March 18, 2013

• Unit 2 emergency diesel generator (EDG) 3 during Division I outage on March 28, 2013 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, Updated Final Safety Analysis Report (UFSAR), 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 that system components and support equipment were aligned correctly and were 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 Attachment.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

During the week of March 25, 2013, the inspectors performed a complete system alignment inspection of the nuclear service water (NSW) system to verify the functional capability of the system. This system was selected because it was considered both safety-significant and risk-significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line-ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding work orders (WOs) was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Resident Inspector Tours

a. Inspection Scope

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

• Heating, ventilation and air-conditioning equipment room, 70 elevation, 0PFP-CB-24

• Turbine building, 2PFP-TB2-8b, 2PFP-TB2-8d, and 2PFP-TB2-1n

• Battery rooms (1A, 1B, 2A, 2B), 1PFP-CB-7, 1PFP-CB-8, 1PFP-CB-9, and 1PFP-CB-10

• Service water building 13 & 20 elevations, 0PFP-SW-1b and 0PFP-SW-1a

• Radwaste building 23 elevation, 0PFP-RW-1b 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. 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. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On February 5, 2013, the inspectors observed fire brigade performance during an unannounced fire drill. The observation was used to determine the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

(1) proper wearing of turnout gear and self-contained breathing apparatus;

(2) proper use and layout of fire hoses;

(3) employment of appropriate fire fighting techniques;

(4) sufficient firefighting equipment brought to the scene;

(5) effectiveness of fire brigade leader communications, command, and control;

(6) search for victims and propagation of the fire into other plant areas;

(7) smoke removal operations;

(8) utilization of pre-planned strategies; (9)adherence to the pre-planned drill scenario; and

(10) drill objectives. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Review of Areas Susceptible to 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 (AOPs), for 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 area to assess the adequacy of flood protection measures, and that the licensee complied with its commitments:

• Unit 2 rattle spaces between the turbine building and the Unit 2 reactor building, between the turbine building and Unit 1 reactor building, between the radwaste building and the Unit 1 reactor building, and between the radwaste building and the Unit 2 reactor building Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the Unit 1 Reactor Building Closed Cooling Water (RBCCW) C heat exchanger to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also visually inspected the service water side of the heat exchanger to ensure that the heat exchanger was free of debris and biological growth. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R08 In-service Inspection Activities

From March 11, 2013 through March 15, 2013, the inspectors conducted a review of the implementation of the licensees In-service Inspection (ISI) Program for monitoring degradation of the reactor coolant system, emergency feedwater systems, containment systems, and risk-significant piping and components.

.1 Piping Systems ISI

a. Inspection Scope

The inspectors observed or reviewed records of the following non-destructive examinations (NDE) mandated by the American Society of Mechanical Engineers (ASME) Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement:

• Visual (VT-1) and Magnetic Particle Examination of Support 2-E21-40FS90, core spray system support

• Ultrasonic examination of weld 2E1146-20-FW62 on the residual heat removal (RHR) system

• Ultrasonic examination of weld 2E1145-15-FW58 on the RHR system

• Ultrasonic examination of Reactor Pressure Vessel (RPV) Flange to Vessel weld The inspectors reviewed evaluations for unacceptable indications in the RPV flange to vessel weld that did not meet the acceptance requirements of IWB-3000 of Section XI.

The inspectors also reviewed the results of examinations conducted this outage and the evaluations performed.

The inspectors observed or reviewed the following pressure boundary welds completed for risk-significant systems during the outage to evaluate if the licensee applied the pre-service NDE and acceptance criteria required by the construction code, NRC-approved code case, NRC-approved code relief request or the ASME Code Section XI. In addition, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to evaluate if the weld procedures were qualified in accordance with the requirements of construction code and the ASME Code Section IX.

• WO 1489566 to cut out and replace Valve 2-E11-F046 The inspectors reviewed the following NDE activities associated with the inspection of reactor vessel internal components (boiling water reactors vessel internals project):

• Visual Examination (VT-1) of core spray T box

• Visual Examination (VT-3) of core spray lower bracket Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Identification and Resolution of Problems

a. Inspection Scope

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

• The licensee had established an appropriate threshold for identifying ISI-related problems

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

• The licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

(71111.11Q - 1 sample)

a. Inspection Scope

On January 9, 2013, the inspectors observed a crew of licensed operators in the plants simulator during an emergency preparedness (EP) drill to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and to ensure that training, where appropriate, 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

• Ability to identify and implement appropriate TS actions and EP 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.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

(71111.11Q - 1 sample)

a. Inspection Scope

Inspectors observed and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Specifically, on March 13, 2013, the inspectors observed Unit 2 evolutions following entry into AOP-20, Pneumatic (Air/Nitrogen)

System Failures. The inspectors reviewed various licensee policies and procedures listed in the Attachment. The inspectors evaluated the following areas:

• Operator compliance and use of procedures

• Control board manipulations

• Communication between crew members

• Use and interpretation of plant instruments, indications and alarms

• Use of human error prevention techniques

• Documentation of activities, including initials and sign-offs in procedures

• Supervision of activities, including risk and reactivity management

• Pre-job briefs and crew briefs

b. Findings

No findings were identified.

1R13 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 equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Unit 2 elevated integrated risk during fuel loading campaign on January 7, 2013

• Unit 1 elevated risk during repairs to reactor core isolation cooling (RCIC)on January 10, 2013

• Unit 2 elevated risk due to lower vessel inventory and reactor head lift during refueling outage on March 5, 2013

• Unit 2 elevated risk due to rattle space flooding on March 13, 2013

• Unit 2 elevated risk due to EDG 3 and emergency buses E3 and E7 outages on March 29, 2013 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. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following six

(6) issues:

• Unit 2 high pressure coolant injection (HPCI) flow controller indications when pump is secured on January 21, 2013

• Unit 1 RCIC flow controller battery issue on January 29, 2013

• Unit 1 1B-1 Battery low specific gravity on February 5, 2013

• Unit 2 RCIC steam detector failure on February 16, 2013

• Unit 2 reactor protection system electrical protection assembly 6 breaker potential to not trip on undervoltage on March 16, 2013

• Unit 2 Leakage past RHR discharge valves 2-E11-F027A and 2-E11-F028A on March 25, 2013 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 also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The following modification was reviewed and selected aspects were discussed with engineering personnel:

• Permanent modification to replace the 24 VDC power supply to the RRP VFD relays with a 120 VAC power supply This document and related documentation were reviewed for adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, implementation of the modification, post-modification testing, and relevant procedures, design, and licensing documents were properly updated. The inspectors reviewed completed work activities to verify that installation was consistent with the design control documents.

b. Findings

Introduction.

An NRC-identified Green finding was identified for the failure of the licensee to follow Procedure EGR-NGGC-0005, EC, when performing the VFD modification for the RRPs. Specifically, between April 4, 2010 and the present, the licensee inappropriately used a RFR to revise the power supplies for the relays in the VFD system without re-evaluating the EC, the 10 CFR 50.59 Screen/Evaluation, and the FMEA. This resulted in a new failure mode on a loss of the power supply causing a RRP runback and placing the plant in a flow transient, and a loss of cooling to the RRP seals.

Description.

Unit 1 and Unit 2 motor generator (MG) sets were replaced by the VFDs on April 14, 2010 and April 27, 2011, respectively. This modification was to provide a source of variable voltage and variable frequency for control of the RRPs. The VFD/Recirculation Flow Control System (RFCS) was also installed to control the VFD inputs and outputs including inputs such as operator-demanded speed changes, runback signals and outputs such as VFD alarms and parameters. The RFCS interfaces with the digital feedwater control system (DFCS) where the DFCS generates portions of the signals needed to initiate runbacks of the RRPs on low feedwater flow or low reactor vessel water level. During the modification to install the VFDs, licensee personnel believed that the relay contacts between the RFCS and the DFCS, that open to initiate the RRP runback, used 24 VDC across the contacts. Testing revealed that the contacts required 120 VAC in order to work correctly.

The licensee found this issue during a time critical portion of system installation and implemented a RFR to address the problem. The inspectors reviewed the procedure in effect at the time, Procedure EGR-NGGC-0005, EC, Revision 30, Section 9.3.9.3, which states that If a revision is necessary during implementation of the EC, the responsible engineer may provide expedited revision information to the implementing organization using a RFR revision. The section further states to evaluate the needed change and ensure the following criteria are satisfied: 1) The revision does not involve changes to design inputs, and 2) The revision does not affect the conclusions of the original 10 CFR 50.59 Screen/Evaluation.

The 120 VAC source chosen to implement the interposing relay modification between the RFCS and the DFCS was the 480 V Emergency Buses E5 - E8, which was the same source for the previous relay configuration for the MG Set runback logic.

However, when the loss of one of these emergency buses occurs, the interposing relay drops out, which signals the RFCS to command a runback of the RRPs even though a runback is not needed for plant conditions. The previous MG Set control logic would issue a scoop tube lock when this power loss occurred and flow would remain stable.

The new VFD control logic is not able to differentiate between the interposing relay dropping out because of a loss of power versus the relay dropping out due to a real runback condition. On a loss of a 480 V Emergency bus, the RRP will runback to approximately 34 percent speed, resulting in reactor power being reduced to 78 percent power and 80 Mlb/hr core flow. This will put the plant above the maximum extended load line limit on the power to core flow map, which the plant is not licensed to operate.

Procedure 1(2)AOP-04.0, Low Core Flow, directs operations personnel to immediately take action to drive rods in and reduce core flow until recirculation flow matches between the two loops as required by TS 3.4.1, Recirculation Loops Operating, which generally occurs around 35 percent power.

The licensee identified that this new failure mode existed on April 26, 2011 during operator training in the simulator; however, the licensee did not take actions to address this new failure mode. The inspectors determined that the licensee failed to follow Procedure EGR-NGGC-0005 when the RFR was created in April 2010, that the licensee did not evaluate the consequences or the acceptability of the modification when the issue was discovered in April 2011, or take corrective actions and revise the EC, the 10 CFR 50.59 Screen/Evaluation, and the FMEA.

The relay involved in the modification also provides part of the control logic for the RRP seal staging flow and the jet pump flow circuitry. On a loss of a 480 VAC bus, the RRP seal staging valve goes closed resulting in a loss of seal cooling to the RRP seal. The licensee evaluated this issue and determined that the control room operators will receive an annunciator for the seal staging valve being closed and will be directed to re-open the valve per the alarm response procedure in a timely manner. Also, on the loss of a 480 VAC bus, when the relay loses power, it appears to the jet pump flow indication logic that the RRP is not running, as opposed to having a runback. This results in one of the core flow indications being inaccurate; however, core flow indication will be available through another indicator. The inspectors reviewed these additional issues and determined the licensees corrective actions were adequate.

After the inspectors questions, the licensee performed a10 CFR 50.59 Screen and Evaluation under NCR 581202. The licensee determined that a 10 CFR 50.59 Evaluation was needed since the 10 CFR 50.59 Screen determined the modification involved a change to a system, structure, or component that adversely effects an UFSAR analysis described design function. The licensee performed the 10 CFR 50.59 Evaluation and determined a license amendment was not required.

The licensee plans to remove the power supply issues that result in the reactor recirculation runback, the loss of seal staging flow, and the jet pump flow indication issues in the Long Range Plan tracked under LTAM BNP-11-0248.

Analysis.

The performance deficiency associated with this finding was the failure of the licensee to follow Procedure EGR-NGGC-0005, Engineering Change (EC), when performing the VFD modification for the RRPs. The finding was more than minor because it was associated with the design control attribute of the Initiating Events Cornerstone and affects the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the VFD modification inappropriately causes a RRP runback on a loss of 480 VAC and core flow instability, and a loss of cooling to the RRP seals. Using IMC 0609, Appendix A, issued June 19, 2012, The SDP for Findings At-Power, the inspectors determined the finding was of very low safety significance because as a transient initiator due to the RRP runback, the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined the finding was also of very low safety significance because as a LOCA initiator, after a reasonable assessment of degradation, the finding would not result in exceeding the reactor coolant system leak rate for a small break LOCA or likely affect other systems used to mitigate a LOCA resulting in a total loss of their function. The finding has a cross-cutting aspect in the area of human performance associated with the work control attribute because the licensee did not appropriately coordinate work activities by incorporating actions to address the impact of changes to the work scope, associated with the VFD modification, on the plant. H.3(b)

Enforcement.

This finding does not involve enforcement action because no regulatory requirement violation was identified since the reactor recirculation pumps are not safety-related. The licensee entered this issue into the CAP as NCR 581202. Because this finding does not involve a violation and is of very low safety or security significance, it is identified as FIN 05000325/2013002-01 and 05000324/2013002-01, Failure to Follow Procedure for Variable Frequency Drive Reactor Recirculation Pump Design Modification.

1R19 Post Maintenance Testing

a. Inspection Scope

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

• 0PT-08.2.2b, 1B RHR Room Cooler Fan and Damper Test after damper failure and repair on November 9, 2012

• 0PT-09.2, HPCI Operability Test after planned maintenance on January 8, 2013

• 0PT-12.2C, EDG 3 Operability Monthly Load Test after diesel outage on January 13, 2013

• 1PT-24.1-1, Unit 1 1B NSW pump after planned maintenance on January 16, 2013

• 0PT-10.1.8, Unit 2 RCIC after maintenance outage on January 23, 2013

• 2OP-43, NSW header restoration after planned outage on March 22, 2013 These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following, as applicable:

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing, and test documentation was properly evaluated. The inspectors evaluated the activities against TS and the UFSAR 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.

b. Findings

No findings were identified.

1R20 Outage Activities

Refueling Outage Activities (71111.20)

a. Inspection Scope

The inspectors reviewed the outage plan and contingency plans for the Unit 2 refueling outage, conducted March 2, 2013 through the end of the quarter, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth.

During the refueling outage, the inspectors observed portions of the shutdown and cool down processes and monitored licensee controls over the outage activities listed below.

• Licensee configuration management, including maintenance of defense-in-depth for key safety functions and compliance with the applicable TS when taking equipment out of service

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error

• Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities

• Monitoring of decay heat removal processes, systems, and components

• Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system

• Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss

• Controls over activities that could affect reactivity

• Maintenance of secondary containment as required by TS

• Defueling activities, including fuel handling and sipping to detect fuel assembly leakage

• Licensee identification and resolution of problems related to refueling outage activities The completed sample will be documented in the second quarter report at the conclusion of the refueling outage. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Routine Surveillance Testing (71111.22 - 3 surveillance test samples)

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed the test results for the following activities to verify the tests met TS surveillance requirements, UFSAR commitments, in-service testing requirements, and licensee procedural requirements.

The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs were operationally capable of performing their intended safety functions. Documents reviewed are listed in the Attachment.

• 0MST-BATT12W, Diesel Fire Pump Starting Batteries Weekly Operability Test on January 27, 2013

• 1MST-RSDP21R, Remote Shutdown and Main Control Panel Reactor Water Level Indication Channel Calibration on February 8, 2013

• 2MST-BATT11AR, 125VDC Battery 2A-1 Service Capacity Test on March 26, 2013

b. Findings

No findings were identified.

.2 In-Service Testing (IST) Surveillance (71111.22 - 1 IST sample)

a. Inspection Scope

The inspectors reviewed the performance of the following test:

• 0PT-08.1.4B, RHR Service Water System Operability Test - Loop B on February 7, 2013 Inspectors evaluated the effectiveness of the licensees ASME Section XI testing program for determining equipment availability and reliability. The inspectors evaluated selected portions of the following areas: 1) testing procedures; 2) acceptance criteria; 3)testing methods; 4) compliance with the licensees IST program, TS, selected licensee commitments, and code requirements; 5) range and accuracy of test instruments; and 6)required corrective actions. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.3 Containment Isolation Valve Testing (71111.22 - 2 isolation valve samples)

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:

• 0PT-20.3-E11, RHR Local Leak Rate Testing for 2-E11-F015B on March 18, 2013

• 0PT-20.3-E21, CS Local Leak Rate Testing for 2-E21-F004A on March 19, 2013 The inspectors observed in-plant activities and reviewed procedures and associated records to determine whether: any preconditioning occurred; acceptance criteria were clearly stated and were consistent with the system design basis; 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; test data and results were accurate, complete, within limits, and valid; where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable; 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.

b. Findings

No findings were identified.

1EP6 Emergency Planning Drill Evaluation

a. Inspection Scope

The inspectors observed a site EP training drill conducted on January 9, 2013. The inspectors reviewed the drill scenario narrative to identify the timing and location of classifications, notifications, and protective action recommendations development activities. During the drill, the inspectors assessed the adequacy of event classification and notification activities. The inspectors observed portions of the licensees post-drill critique. The inspectors verified that the licensee properly evaluated the drill performance with respect to performance indicators and assessed drill performance with respect to drill objectives. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

RADIATION SAFETY

[RS]

Cornerstones: Occupational Radiation Safety and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRA)s, Locked High Radiation Areas (LHRA)s, and Very High Radiation Areas (VHRA)s established within the radiologically controlled area (RCA) of the Unit 1 (U1) and Unit 2 (U2) reactor buildings, U1 and U2 turbine buildings, and radioactive waste (radwaste) processing and storage locations. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas, including the Independent Spent Fuel Storage Installation (ISFSI). The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, discrete radioactive particles, airborne radioactivity, and pre-job surveys for upcoming tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected outage jobs, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices: The inspectors evaluated access barrier effectiveness for selected LHRA locations and discussed procedural guidance for LHRA and VHRA controls with health physics (HP) supervisors. The inspectors reviewed implementation of controls for the storage of irradiated material within the spent fuel pool (SFP). Established radiological controls (including airborne controls) were evaluated for workers entering the U2 drywell and reactor building to conduct work associated with Quality Control (QC) inspections, motor operated valve activities, chemical decontamination associated with reactor water cleanup activities, inboard main steam isolation valve (MSIV) activities, and torus diving activities. In addition, the inspectors reviewed licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations.

Through direct observations and interviews with licensee staff, the inspectors evaluated occupational workers adherence to selected RWPs and HP technician proficiency in providing job coverage. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for selected U2 Refueling Outage 21 (B221R1) job tasks. As part of Inspection Procedure (IP) 71124.04, the inspectors reviewed the use of personnel dosimetry (ED alarms, extremity dosimetry, multi-badging in high dose rate gradients, etc.). The inspectors also evaluated worker responses to dose and dose rate alarms during selected work activities.

Control of Radioactive Material: The inspectors observed surveys of material and personnel being released from the RCA using small article monitor (SAM), personnel contamination monitor (PCM), and portal monitor (PM) instruments. The inspectors reviewed calibration records for selected release point survey instruments and discussed equipment sensitivity, alarm setpoints, and release program guidance with licensee staff.

The inspectors evaluated the appropriateness of radionuclide sources used for detector testing and calibration. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution: The inspectors reviewed and assessed CAP documents associated with radiological hazard assessment and exposure control. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. The inspectors also reviewed recent self-assessment results.

Radiation protection activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 12, Technical Specifications (TS) Sections 5.7.1 and 5.7.2, 10 Code of Federal Regulations (CFR) Parts 19 and 20, and approved licensee procedures. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

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

a. Inspection Scope

Work Planning and Exposure Tracking: The inspectors reviewed planned work activities and their collective exposure estimates for the B221R1 outage. The inspectors reviewed ALARA planning packages for the following high collective exposure tasks: refuel floor work, small bore pipe replacement, and control rod drive activities. For the selected tasks, the inspectors reviewed established dose goals and discussed assumptions regarding the bases for the current estimates with responsible ALARA planners. The inspectors evaluated the incorporation of exposure reduction initiatives and operating experience, including historical post-job reviews, into RWP requirements. Day-to-day collective dose data for the selected tasks were compared with established dose estimates and evaluated against procedural criteria (work-in-progress review limits) for additional ALARA review. Where applicable, the inspectors discussed changes to established estimates with ALARA planners and evaluated them against work scope changes or unanticipated elevated dose rates.

Source Term Reduction and Control: The inspectors reviewed the collective exposure three-year rolling average from 2009 - 2011. The inspectors evaluated historical dose rate trends for recirculation system piping and compared them to current B221R1 data.

Source term reduction initiatives, including cobalt reduction and noble metals injection, were reviewed and discussed with Chemistry and HP staff. The inspectors also reviewed temporary shielding packages for the B221R1 outage.

Radiation Worker Performance: The inspectors observed radiation worker performance for MSIV work and under-vessel activities. The inspectors observed ALARA briefings for Control Rod Drive Mechanism (CRDM) replacement and for various HRA jobs in the U2 reactor building and drywell. Radiation worker performance was also evaluated as part of IP 71124.01. While observing job tasks, the inspectors evaluated the use of remote technologies to reduce dose including teledosimetry and remote visual monitoring.

Problem Identification and Resolution: The inspectors reviewed and discussed selected CAP documents associated with ALARA program implementation. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. The inspectors also reviewed recent self-assessment results.

ALARA program activities were evaluated against the requirements of UFSAR Section 12, TS Section 5.4, 10 CFR Part 20, and approved licensee procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls: The inspectors evaluated the use of engineering controls to mitigate potential airborne conditions including operation of the U2 dry well purge, refueling floor ventilation, and installation of temporary High Efficiency Particulate Air (HEPA) filtration systems for selected tasks and operations during B221R1. The evaluation included procedural guidance, operability testing, and equipment configurations during specific tasks. In addition, plant guidance and its implementation for the monitoring of potential airborne beta-gamma and alpha-emitting radionuclides during insulation removal were reviewed and discussed with licensee representatives.

Use of Respiratory Protection Devices: The inspectors reviewed procedural guidance for the issuance and use of respiratory protection devices and discussed program implementation with responsible licensee representatives. The inspectors reviewed Total Effective Dose Equivalent (TEDE)-ALARA evaluations conducted for selected B221R1 tasks. The inspectors reviewed whole-body count routine and investigative analysis results for occupational workers. The use of respiratory protective equipment was evaluated for the workers involved in B221R1 initial dry well entry and those involved in dry well insulation removal activities. The inspectors toured selected onsite compressors available for supplying breathing air for current outage activities and reviewed Grade D or greater air certification records. The inspectors reviewed training, fit testing, and medical qualification records for selected HP, maintenance, and operations staff using respiratory protection devices for B221R1 activities.

Self-Contained Breathing Apparatus (SCBA) for Emergency Use: The inspectors reviewed the current status, operability and availability of selected SCBA equipment maintained within the operations support center, U1 and U2 control rooms, and reactor auxiliary building. Maintenance activities for selected respiratory protective equipment, e.g., compressed gas cylinders, regulators, valves, and hose couplings, by certified vendor technicians were evaluated for selected SCBA units. The inspectors evaluated training, fit testing, and medical qualification records for selected HP, maintenance, and operations staff assigned emergency response duties. The inspectors discussed SCBA use and training activities, including maintenance of corrective lens inserts and hands-on annual requalification training, with on-shift control room operators.

Problem Identification and Resolution: The inspectors reviewed CAP documents within the area of radiological airborne controls and respiratory protection activities. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with licensee procedural guidance. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

HP program activities associated with airborne radioactivity monitoring and controls were evaluated against details and requirements documented in the UFSAR Sections 11 and 12; TS Section 5.4, 10 CFR Part 20; and approved licensee procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry: The inspectors reviewed National Voluntary Laboratory Accreditation Program (NVLAP) certification data (including thermoluminescent dosimeter (TLD) testing for neutron, gamma, and beta exposures) and discussed program guidance for storage, processing, and evaluation of results for active and passive personnel dosimeters currently in use. Comparisons between ED and TLD data were discussed in detail. In addition, the inspectors reviewed ED alarm logs and evaluated licensee assessment actions for selected alarm events.

Internal Dosimetry: Program guidance, instrument detection capabilities, and assessment results for internally deposited radionuclides were reviewed in detail. The inspectors reviewed selected in vivo (Whole Body Count) analyses associated with intakes of radionuclides. Capabilities for collection and analysis of bioassay samples collected from torus divers were evaluated and discussed with licensee staff.

Special Dosimetric Situations: The inspectors evaluated the licensees use of multi-badging, extremity dosimetry, and dosimeter relocation within non-uniform dose rate fields (e.g. during under-vessel work) and discussed worker monitoring in neutron areas with licensee staff. The inspectors also reviewed records of monitoring for declared pregnant workers from March 2010 to March 2013 and discussed monitoring guidance with dosimetry staff. In addition, the adequacy of shallow dose assessments for selected Personnel Contamination Events occurring between March 2010 and December 2012 were reviewed and discussed.

Problem Identification and Resolution: The inspectors reviewed and discussed selected CAP documents associated with occupational dose assessment. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. The inspectors also reviewed recent self-assessment results.

Occupational dose assessment activities were evaluated against the requirements of UFSAR Section 12; TS Section 5.4; 10 CFR Parts 19 and 20; and approved licensee procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

Walkdowns and Observations: During tours of the reactor buildings, SFP areas, control room, and RCA exit point, the inspectors observed installed radiation detection equipment including the following instrument types: area radiation monitors (ARM)s, continuous air monitors, PCMs, SAMs, PMs, and liquid and gaseous effluent monitors.

The inspectors observed the physical location of the components, noted the material condition, and compared sensitivity ranges with UFSAR requirements. In addition to equipment walk-downs, the inspectors observed source checks and alarm setpoint testing of various portable and fixed detection instruments, including ion chambers, a telepole, PCMs, SAMs, and PMs. Material condition of source check devices, device operation, and establishment of source check acceptance ranges were also discussed with calibration lab personnel.

Calibration and Testing: The inspectors reviewed the last two calibration records for selected ARMs, PCMs, PMs, SAMs, and containment high-range ARMs and the most recent calibration record for a whole body counter. Inspectors reviewed records of survey instrument function/source checks and observed and discussed performance of required checks with calibration lab personnel. Calibration source documentation was reviewed for the ARM high-range calibrator and the Cs-137 source used for portable instrument checks. Calibration stickers on portable survey instruments were reviewed and inspections of storage areas for 'ready-to-use' equipment were completed during walkdowns. The inspectors reviewed alarm setpoint values for selected ARMs, PCMs, PMs, SAMs, and effluent monitors. The inspectors also reviewed count room QC records for germanium detectors and liquid scintillation detectors.

Problem Identification and Resolution: The inspectors reviewed selected NCRs in the area of radiological instrumentation. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Operability and reliability of selected radiation detection instruments were reviewed against details documented in the following: 10 CFR Part 20; NUREG-0737, Clarification of TMI Action Plan Requirements; TS Section 3; UFSAR Chapters 11 and 12; and applicable licensee procedures. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

.1 Initiating Events Cornerstone

a. Inspection Scope

To verify the accuracy of the PI data reported to the NRC, the inspectors compared the licensees basis in reporting each data element listed below to the PI definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Indicator Guideline.

• Units 1 and 2 unplanned scrams per 7000 critical hours

• Units 1 and 2 unplanned scrams with complications

• Units 1 and 2 unplanned power changes per 7000 critical hours The inspectors sampled licensee submittals for the performance indicators listed above for the period from the 1st quarter 2012 through the 4th quarter 2012. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC inspection reports for the period to validate the accuracy of the submittals. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Occupational Radiation Safety Cornerstone (711151 - 1 sample)

a. Inspection Scope

The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from January 2012 through December 2012. For the assessment period, the inspectors reviewed ED alarm logs and NCRs related to controls for exposure significant areas. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data.

Documents reviewed are listed in the report Attachment.

b. Findings

No findings were identified.

.3 Public Radiation Safety Cornerstone (711151 - 1 sample)

a. Inspection Scope

The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from January 2012 through December 2012. For the assessment period, the inspectors reviewed cumulative and projected doses to the public contained in liquid and gaseous release permits and NCRs related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in the report Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered Into the CAP

a. Inspection Scope

To aid in the identification of repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed frequent screenings of items entered into the licensees CAP. The review was accomplished by reviewing daily action request reports.

b. Findings

No findings were identified.

.2 Selected Issue Follow-up Inspection

a. Inspection Scope

The inspectors reviewed a sample of critical components with no preventative maintenance scheduled. The inspectors reviewed these components to verify that the licensee fully identified all required preventative maintenance and that no further corrective actions were needed for these components. The inspectors evaluated these components against the requirements in the licensees preventative maintenance program and the CAP. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA3 Follow-up of Events

Notice of Unusual Event for Toxic, Corrosive, Asphyxiant or Flammable Gases in Amounts that Have or Could Adversely Affect Normal Plant Operation

a. Inspection Scope

For the plant event listed below, the inspectors reviewed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional NRC personnel, and compared the event details with criteria contained in IMC 0309, issued October 28, 2011, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that the licensee made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR 50.72. The inspectors reviewed the licensees follow-up actions related to the events to assure that the licensee implemented appropriate corrective actions commensurate with their safety significance. Documents reviewed are listed in the Attachment.

• On February 26, 2013, a Freon leak from the 2A turbine building chiller oil pump discharge line was discovered by an area operator, meeting the criteria for a Notice of Unusual Event declaration in accordance with Emergency Action Level HU 3.1, Toxic, Corrosive, Asphyxiant or Flammable Gases in Amounts that Have or Could Adversely Affect Normal Plant Operations.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

Inspectors also observed security shift turnover. These observations took place during both normal and off-normal plant working hours. These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews and inspection activities.

b. Findings

No findings were identified.

.2 Operation of an Independent Spent Fuel Storage Installation (ISFSI) (60855.1 -

2 samples)

a. Inspection Scope

During the inspection period the inspectors conducted two observations of ISFSI cask loadings to ensure fuel was loading in accordance with procedures. Inspectors walked down the ISFSI pad to ensure that the licensee has maintained fuel stored in the ISFSI in a safe manner and in compliance with approved procedures. Inspectors also reviewed selected records to ensure that the licensee has identified each fuel assembly placed in the ISFSI, has recorded the parameters and characteristics of each fuel assembly, and has maintained a record of each fuel assembly as a controlled document.

b. Findings

No findings were identified.

.3 Implementation of Enforcement Guidance (EGM)11-003, Revision 1, Enforcement

Guidance Memorandum on Dispositioning Boiling Water Reactor Licensee Noncompliance with Technical Specification Containment Requirements During Operations with a Potential for Draining the Reactor Vessel

a. Inspection Scope

The inspectors reviewed the plants implementation of NRC EGM 11-003, Revision 1, during Unit 2 maintenance activities which had the potential to drain the reactor vessel during the Unit 2 refueling outage. The activities were:

• Draining of the control rod drive hydraulic control units on March 7, 2013

• Reactor bottom head drain maintenance on March 8, 2013

• RHR Service Water B Loop draining on March 20, 2013

• RHR Service Water A Loop draining on March 23, 2013

• Reactor bottom head drain valve maintenance on March 25, 2013 These activities took place without secondary containment being operable. Inspectors verified compliance with the guidelines of EGM 11-003 prior to and during these activities.

b. Findings

A violation of TS 3.6.4.1 was identified. However, because the violation was identified during the discretion period described in EGM 11-003, Revision 1, the NRC is exercising enforcement discretion in accordance with Section 3.5, Violations Involving Special Circumstances, of the NRC Enforcement Policy and, therefore, will not issue enforcement action for this violation, subject to a timely license amendment request being submitted.

.4 (Closed) NRC Temporary Instruction 2515/187 - Inspection of Near-Term Task Force

Recommendation 2.3 Flooding Walkdowns

a. Inspection Scope

Inspectors verified the following licensees walkdown packages contained the elements as specified in Nuclear Energy Institutes 12-07 Walkdown Guidance document:

• Units 1 and 2, Flood Protection Feature 6BL, Service Water Building, 4 Elevation, Pipe Penetration Seal\20-8 Pipe Sleeves

• Units 1 and 2 Flood Protection Feature 6BL, Emergency Diesel Building, 12 Elevation, Pipe Penetration Seal\24-5 Pipe Sleeves The inspectors accompanied the licensee on their walkdown of:

• Units 1 and 2 Flood Protection Feature 6BL, Emergency Diesel Building, 12 Elevation, Pipe Penetration Seal\20-5 Pipe Sleeves The inspectors 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

• Reasonable simulation

• 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 The inspectors independently performed their walkdown and verified that the following flood protection features were in place:

• Unit 1 Reactor Building Rail Road Doors (Severe Weather Doors 209 and 210)

The inspectors 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

• Flood protection feature functionality was determined using either visual observation or by review of other documents The inspectors verified that noncompliance 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.

b. Findings

(Opened) Unresolved ltem (URl)05000325/2013002-02 and 05000324/2013002-02, Potential Flood Impacts due to Degraded Flood Protection Measures

Introduction:

The inspectors are opening a URI associated with the potential for flood intrusion into the service water building, reactor building, and emergency diesel generator building due to degraded flood protection measures to determine if a performance deficiency exists.

Description:

From August through October, 2012, the licensee performed walkdowns of flood protection measures in accordance with Nuclear Energy Institutes 12-07 Walkdown Guidance. The licensee and inspectors identified degraded or missing flood protection measures in the service water building, reactor building, and emergency diesel generator building. The inspectors are opening a URI to review the licensees evaluation of these flood protection deficiencies and determine if a performance deficiency exists.

The licensee entered these issues into the CAP as NCR 600850. This issue is being tracked as: URI 05000325/2013002-02 and 05000324/2013002-02, Flood Impacts due to Degraded Flood Protection Measures.

.5 Teleconference to Discuss Status Of Groundwater Monitoring Program

On March 12, 2013, the inspectors held a teleconference with licensee staff to discuss the status of the groundwater monitoring program. The licensee provided an update on tritium concentrations in water collected from onsite and offsite groundwater and surface water sampling locations and discussed ongoing remediation efforts associated with the Storm Drain Stabilization Pond (SDSP) and areas near a U1 Condensate Storage Tank (CST) underground pipe leak. Although seasonal fluctuations can occur, the inspectors noted that onsite tritium concentrations in and near the SDSP have generally trended downward since 2007 when the contamination was discovered and corrective actions were initiated. The licensee has installed shallow and intermediate-depth wells in the vicinity of a U1 CST piping leak (from December 2010) in order to better characterize the tritium plume and to facilitate remediation of the groundwater. Some of these wells have detected low levels of tritium in the top of the Castle-Hayne aquifer in the area immediately below the Brunswick site. Wells have also been constructed further away from the leak site to monitor any plume migration through the Castle-Hayne. Samples taken from these wells have not shown any detectable tritium. The inspectors noted that although very low concentrations of tritium have been identified periodically in the offsite environs, e.g., Nancys Creek immediately adjacent to the SDSP, all reported values for offsite samples have remained significantly below established regulatory limits. The licensee is currently remediating the groundwater around the SDSP through a network of sub-surface pumping wells. Water pumped from this network is transferred to a double-lined retention pond. Publicly available information regarding onsite groundwater monitoring and radionuclide concentrations in the environment near Brunswick Steam Electric Plant can be found in the Annual Radiological Environmental Operating Report.

Recently issued reports can be found on the NRCs public website:

http://www.nrc.gov/reactors/operating/ops-experience/tritium/plant-specific-reports/bru1-2.html.

4OA6 Management Meetings

Exit Meeting Summary

On April 24, 2013, the inspectors presented the inspection results of the quarterly integrated inspection activities to Mr. Michael Annacone, and other members of the licensee staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection period.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.

Technical Specification 5.7.1, High Radiation Area, requires posting and barricading of HRAs with dose rates not exceeding 1 Rem/hour at 30 centimeters from the radiation source or from any surface penetrated by the radiation. Contrary to this, on April 25, 2012, an unposted and unbarricaded HRA was identified by the licensee in the Unit 1 Reactor Building 80 elevation Reactor Water Clean-Up (RWCU) Precoat Tank area. During the previous shift, following a RWCU Back Wash Receiving Tank (BWRT)resin transfer drop to the Radwaste RWCU phase separators, a survey was performed and the area was downposted from HRA to RA. However, the survey failed to detect dose rates on the piping underneath the Unit 1 RWCU Precoat tank of 2.5 Rem/hour contact and 0.4 Rem/hour at 30 centimeters. The elevated dose rates were not found until a procedurally required follow-up survey was performed approximately 3.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later by another HP technician. The technician took immediate corrective actions including posting and barricading the affected area. This finding was of very low safety significance (Green) because there was no substantial potential for overexposure. This was based on the fact that no workers entered the hotspot area underneath the Precoat tank during the brief period that the area was not properly controlled. In addition, the dose rates involved were not high enough to provide a substantial potential for overexposure. The licensee entered the issue into their CAP as NCR 532588.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

M. Annacone, Site Vice President

Y. Anagostopoulos, General Manager - Major Porjects

A. Brittain, Manager - Security

P. Dubrouillet, Manager - Nuclear Systems Engineering

C. Dunsmore, Manager - Shift Operations

G. Galloway, Superintendent - Nuclear Oversight

S. Gordy, Manager - Maintenance

L. Grzeck, Supervisor - Regulatory Affairs

K. Hamm, Superintendent - Mechanical Maintenance

B. Houston, Manager - Environmental and Radiological Controls

F. Jefferson, Manager - Nuclear Systems Engineering

J. Kalamaja, Manager - Operations

G. Kilpatrick, Manager - Training

J. Krakuszeski, Plant General Manager

S. Larsen, Engineer - ISI Program

M. McGowan, Supervisor - Environmental

M. Millinor, Senior Chemistry Specialist

W. Murray, Licensing Specialist

D. Petrusic, Superintendent - Environmental and Chemistry

A. Pope, Manager - Nuclear Support Services

J. Price, Director - Engineering

M. Regan, Contractor - Outage and Project Support

T. Sherrill, Licensing Specialist

T. Silar, Control Silar Services

M. Stacy, Manager - Nuclear Major Projects

J. Sullivan, Engineer - Containment

M. Turkal, Licensing Specialist

S. Williams, Internals Engineer - Containment

E. Wills, Director - Site Operations

O. Wrisbon, Superintendent - Electrical, Instrumentation and Controls Maintenance

NRC Personnel

R. Cady, Sr. Performance Assessment Analyst, Office of Nuclear Regulatory Research

R. Conatser, Health Physicist, Office of Nuclear Reactor Regulation

G. Hopper, Chief, Reactor Projects Branch 7, Division of Reactor Projects Region II

T. Nicholson, Sr. Technical Advisor for Radionuclide Transport, Office of Nuclear Regulatory

Research

R. Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region II

T. Reis, Director, Division of Reactor Safety

J. Worosilo, Project Engineer, Division of Reactor Projects Region II

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000325, 324/2013002-01 FIN Failure to Follow Procedure for Variable Frequency Drive Reactor Recirculation Pump Design Modification (Section 1R18)

Opened

05000325, 324/2013002-02 URI Flood Impacts due to Degraded Flood Protection Measures (Section 4OA5.4)

Closed

NRC Temporary Instruction TI Inspection of Near-Term Task Force 2515/187 Recommendation 2.3 Flooding Walkdowns (Section 4OA5.4)