IR 05000324/2011002

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IR 05000325-11-002, 05000324-11-002, on 01/01/11 - 03/31/11, Brunswick Steam Electric Plant, Units 1 & 2; Operability Evaluations, and Radiological Hazard Assessment and Exposure Controls
ML111330181
Person / Time
Site: Brunswick  Duke energy icon.png
Issue date: 05/13/2011
From: Randy Musser
NRC/RGN-III/DRP/RPB4
To: Annacone M
Carolina Power & Light Co
References
IR-11-002
Download: ML111330181 (50)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION May 13, 2011

SUBJECT:

BRUNSWICK STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT NOS.: 05000325/2011002 AND 05000324/2011002

Dear Mr. Annacone:

On March 31, 2011, 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 21, 2010, with Mr. Joe Frisco 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.

This report documents one finding associated with failure to promptly correct a condition adverse to quality regarding a manufacturing defect of a Barton Model 199 dual dampener differential pressure unit (DPU) used in the 1B residual heat removal (RHR) loop. This finding has potential safety significance greater than very low safety significance. Although the finding has potential safety significance, it did not represent an immediate safety concern because the finding did not represent a complete safety system functional failure (i.e. the other train of RHR remained operable).

In addition, the report documents one NRC-identified finding of very low safety significance (Green). The finding was determined to involve violations of NRC requirements. However, because of the very low safety significance and because it is entered into your corrective action program, the NRC is treating the finding as non-cited violations (NCV) consistent with the NRC Enforcement Policy. If you contest the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator Region 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. In addition, if you disagree with the cross-cutting aspect assigned the finding in this report, you should provide a response within 30 days of the date of

CP&L 2 this inspection report, with the basis for your disagreement, to the Regional Administrator, Region 2, and the NRC Senior Resident Inspector at Brunswick. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

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, 324/2011002 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-325, 50-324 License Nos.: DPR-71, DPR-62 Report Nos.: 05000325/2011002, 05000324/2011002 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, 2011 through March 31, 2011 Inspectors: P. OBryan, Senior Resident Inspector G. Kolcum, Resident Inspector R. Kellner, Health Physicist (in Training)(2RS1, 2RS8, 4OA1, 4OA5.2)

G. Kuzo, Senior Health Physicist (2RS3)

W. Loo, Senior Health Physicist (2RS1, 2RS2, 2RS8, 4OA1, 4OA5.2)

A. Nielsen, Senior Health Physicist (4OA6)

W. Pursley, Health Physicist (in Training) (2RS1, 2RS8, 4OA1, 4OA5.2)

R. Williams, Reactor Inspector (1R08)

D. Jones, Senior Reactor Inspector (4OA5.3)

A. Alen, Reactor Inspector (4OA5.3)

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

SUMMARY OF FINDINGS

IR 05000325/2011002, 05000324/2011002; 01/01/11 - 03/31/11; Brunswick Steam Electric

Plant, Units 1 & 2; Operability Evaluations, and Radiological Hazard Assessment and Exposure Controls.

This report covers a three-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One NRC-identified finding and one self-revealing finding were identified. The significance of most findings is indicated by their color (Green,

White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Cross-cutting aspects are 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.

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Criterion XVI, Corrective Action was identified for failure to promptly correct a condition adverse to quality regarding a manufacturing defect of a Barton Model 199 dual dampener differential pressure unit (DPU) used in the 1B residual heat removal (RHR) loop. Specifically, the licensee failed to replace the DPU after the vendor determined that the manufacturing process was incorrect and could lead to a slow response of the component in safety-related applications. This led to a failure of the RHR system 1B loop minimum flow bypass valve, 1-E11-F007B, to operate on February 18, 2011. The failure of the defective DPU was tracked as NCR 448471 in the corrective action program, and the licensee replaced the defective DPU.

The inspectors determined that the licensees failure to promptly correct a condition adverse to quality regarding a manufacturing defect for Barton Model 199 dual dampener DPUs was a performance deficiency. The finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the corrosion buildup in the DPU used in the control of the position of the minimum flow bypass valve for the 1B RHR loop had degraded, such that the availability and reliability of the 1B RHR loop was adversely affected. This finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process (SDP), Phase 1 Worksheet for mitigating systems. The finding required phase two and phase three SDP analyses by a regional senior analyst because the 1B loop of RHR was assumed to be inoperable for longer than its technical specification (TS) allowed outage time. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. This finding does not have a cross-cutting aspect because the performance deficiency occurred greater than three years ago and does not reflect current licensee performance. (Section 1R15)

Cornerstone: Occupational Radiation Safety

Green.

The inspectors identified a non-cited violation (NCV) of Technical Specification (TS) 5.4.1, Procedures, for the failure of the licensee to perform initial alpha activity analysis of air samples indicating greater than 0.3 Derived Air Concentration (DAC) beta-gamma activity on an approved alpha counter. Section 9.5.12.h of procedure HPS-NGGC-0024, Alpha Monitoring Guidelines, Rev. 3, states that if gamma scan results indicate the airborne activity is equal to or greater than the beta-gamma DAC-Fraction Action level of 0.3 DAC; (1) perform an initial alpha count on the air sample using a counter approved for air samples; and (2) assess and document the results per site-specific procedures. Contrary to this requirement, on March 10, 11, and 21, 2011, the licensee did not perform an initial alpha count on air samples using a counter approved for air samples and assess and document the results for gamma scan results that exceeded 0.3 DAC. Specifically, air samples for those selected work activities identified DAC concentrations of 0.6589, 0.3152 and 1.45. Licensee corrective actions included instructions to workers to ensure procedural adherence for sample analysis and changes to the software program to prompt the workers to do the sample analysis when the threshold limits were met or exceeded. The licensee entered the issue into its corrective action program as NCR 455307.

This finding is greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process (Monitoring and Radiation Protection Controls) and adversely affects the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from airborne radioactive material during routine civilian nuclear reactor operation.

Failure to identify potentially significant contributors to internal dose could lead to unmonitored occupational exposures. The finding was evaluated using IMC 0609,

Appendix C, Occupational Radiation SDP and was determined to be of very low safety significance (Green) because it was not related to As Low As Reasonably Achievable (ALARA) Planning and the ability to assess dose was not compromised during these instances. In addition, it did not involve overexposure or substantial potential for overexposure because of the relatively low alpha source term in the areas where the surveys were performed. This conclusion was drawn from the results of beta/gamma and alpha smear surveys performed at those selected work locations. However, if left uncorrected, unmonitored internal exposure could have occurred. The cause of this finding was directly related to the cross-cutting aspect of maintaining effective interfaces between work groups in the Work Control component of the Human Performance area. H.3(b). (Section 2RS1)

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at rated thermal power, and operated at or near full power for the entire inspection period.

Unit 2 began the inspection period at rated thermal power, and operated at or near full power until shutdown for a refueling outage on March 4, 2011. Unit 2 remained shut down for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

  • Units 1 and 2 conventional and nuclear service water systems with the 2B conventional service water pump out of service on February 1, 2011;
  • 1A RHR loop with the 1B RHR loop out of service on February 17, 2011; and
  • 2B RHR loop with the 2A RHR loop out of service on March 8, 2011.

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, 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 corrective action program with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

The inspectors performed a complete system alignment inspection of the Unit 2 core spray 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 corrective action program database to ensure that system equipment alignment problems were being identified and appropriately resolved.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Resident Inspector Tours

a. Inspection Scope

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

  • Unit 1 Cable Spreading Room 23' Elevation 1PFP-CB-5;
  • Unit 2 Cable Spreading Room 23' Elevation 2PFP-CB-6;

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 had 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 that 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 corrective action program.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the 2A RHR 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.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From March 14, 2011, through March 18, 2011, the inspectors conducted a review of the implementation of the Licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, emergency feedwater systems, containment systems, and risk-significant piping and components.

The inspections described in Sections 1R08.1 and 1R08.2 below constituted one inservice inspection sample as defined in Inspection Procedure 71111.08-05.

.1 Piping Systems ISI

a. Inspection Scope

The inspectors observed or reviewed records of the following non-destructive examinations 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.

  • Phased array ultrasonic examination of the N9 nozzle (Class 1);
  • Magnetic particle examination of three MSIV base metal repair welds (Class 1);
  • Magnetic particle examination of inboard MSIV F022D (Class 1); and
  • General visual examinations of three containment surfaces.

Since the previous refueling outage, the licensee conducted a review of ASME Code Section XI required non-destructive surface and volumetric examinations and did not identify any recordable indications. Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors observed or reviewed the following pressure boundary welds for risk-significant systems during the outage to evaluate if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the Construction Code, NRC-approved Code case, NRC-approved Code relief request or the ASME Code Section XI. 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.

The inspectors reviewed the following non-destructive examination (NDE) activities associated with the inspection of reactor vessel internal components (Boiling Water Reactors Vessel Internals Project):

  • EVT-1 of two jet pump assemblies; and
  • VT-3 of four jet pump riser arm welds (Class 1).

The inspectors also reviewed the calculations performed to support continued service for an indication discovered on jet pump JPCRS-1 during the previous outage. The inspectors verified that the indication growth since the last outage was within the requirements set forth in the applicable Code.

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 corrective action program 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 action; and
  • the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The Inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On January 16, 2011, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator training 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 (EP)actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

  • Historical performance of the Unit 1 and Unit 2 power plant computers; and
  • Electrical ground on the 2A RHR service water booster pump control power circuit on February 7, 2011.

The inspectors reviewed events where ineffective equipment maintenance may have resulted in equipment failure 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 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; and
  • 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 that maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization.

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 five 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:

  • Failure of 1-CAC-CS-4178, Unit 1 wetwell vent override switch on January 6, 2011;
  • Failure of the 2D service air compressor on January 19, 2011;
  • Emergent maintenance on the 2A RHR service water booster pump on February 7, 2011;
  • 1B RHR loop out of service for planned maintenance February 16, 2011 through February 18, 2011; and
  • Failure of the 2B-2 battery charger on March 28, 2011.

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 that risk analysis assumptions were valid and applicable requirements were met.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following five issues:

  • Damaged control room ventilation envelope door CR-113, NCR 439941;
  • Low wall thickness on Unit 2 RHR system piping, NCR 443061;
  • Incorrect ratings for the Unit 1 and Unit 2 electrical protection assemblies (EPA)circuit breakers, NCR 443476;
  • Failure of the 1B and 1D RHR service water booster pump control power voltage tests, NCR 448225; and
  • Failure of the 1B RHR loop minimum flow control valve to operate, NCR 448471, NCR 448577, and NCR 450795.

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.

b. Findings

Introduction.

A self-revealing AV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action was identified for failure to promptly correct a condition adverse to quality regarding a manufacturing defect of Barton Model 199 dual dampener differential pressure unit (DPU) used in the 1B RHR loop. Specifically, the licensee failed to replace the DPU after the vendor determined that the manufacturing process was incorrect and could lead to a slow response of the component in safety-related applications. This led to a failure of the RHR system 1B loop minimum flow bypass valve, 1-E11-F007B, to operate on February 18, 2011.

Description.

The licensee failed to promptly correct a condition adverse to quality regarding manufacturing defects of Barton Model 199 dual dampener differential pressure units. Barton Instrument Systems issued an advisory related to dual dampener DPUs in October 2001. The advisory informed the licensee that water-filled DPUs built prior to 1997 were susceptible to a manufacturing defect due to an additional dampener port drilled internal to the DPU. The additional drilled port was not re-passivated.

Passivation is a chemical process to provide corrosion protection for stainless steels. As the small diameter port in the DPU corrodes over time, corrosion products may clog openings in the DPU, making it susceptible to slow operation and failure. The licensee received the Barton advisory in January 2002. The licensees evaluation of the condition concluded that if the DPUs in stores and in operation had not failed yet, they were unlikely to fail in the future, and normal testing would be sufficient to detect impending failure.

On February 15, 2011, during maintenance on the DPU for the 1B RHR loop minimum flow valve, 1-E11-F007B, the DPU failed calibration. The DPU was discovered stuck in one position, out of calibration, sluggish, and difficult to operate. Troubleshooting continued until the licensee was able to obtain a successful calibration on February 16, 2011. A post-maintenance test (PMT) was performed on February 18, 2011, for the 1B loop of RHR and approximately twenty-five minutes into the test, the minimum flow bypass valve failed to operate correctly. NCR 448471 was initiated. The minimum flow bypass valve has a safety-related function in the open direction to automatically open to permit bypass flow when the pump's flow is insufficient for pump cooling and in the closed direction to prevent diversion of flow from the pump during low pressure coolant injection and containment cooling modes. Additional failures occurred during system operation until March 7, 2011 when the licensee replaced the DPU with a non-susceptible, silicone-filled model that was not part of the 2001 advisory and installed a temporary modification to maintain the valve normally open. In addition, the licensee implemented compensatory actions to ensure that susceptible DPUs in other plant applications are not in a failed state until replacement DPUs can be procured and installed.

Analysis.

The inspectors determined that the licensees failure to promptly correct a condition adverse to quality regarding a manufacturing defect for Barton Model 199 dual dampener DPUs was a performance deficiency. The finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the corrosion buildup in the DPU used in the control of the position of the minimum flow bypass valve for the 1B RHR loop had degraded, such that the availability and reliability of the 1B RHR loop was adversely affected. This finding was evaluated using Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet for mitigating systems. The finding required phase two and phase three SDP analyses by a regional senior analyst because the 1B loop of RHR was assumed to be inoperable for longer than its TS allowed outage time. The significance of this finding is designated as To Be Determined (TBD) until the safety characterization has been completed. This finding does not have a cross-cutting aspect because the performance deficiency occurred greater than three years ago and does not reflect current licensee performance.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality are promptly corrected. Contrary to this, the licensee failed to take prompt and adequate corrective action, causing the failure of the minimum flow bypass valve in the 1B RHR loop. This issue has been entered into the licensees corrective action program as NCR 448471. Pending completion of the safety characterization, this finding is identified as AV 05000325/2011002-01, Failure To Adequately Evaluate And Correct A Condition Adverse To Quality Involving A Manufacturing Defect Of Barton Model 199 Dual Dampener Differential Pressure Units.

1R18 Plant Modifications

a. Inspection Scope

The following two engineering design packages were reviewed and selected aspects were discussed with engineering personnel:

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 and post-modification testing, and relevant procedures, design, and licensing documents were properly updated. The inspectors observed ongoing and completed work activities to verify that installation was consistent with the design control documents.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

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

  • 1MST-RPS26Q, RPS High Drywell Pressure Trip Unit Channel Calibration, after replacement of wetwell vent relays associated with switch 1-CAC-CS-4178 on January 11, 2011;
  • 0PT-12.2B, No. 2 Diesel Generator Monthly Load Test, after planned maintenance on February 15, 2011; and
  • 0PT-08.2.2b, LPCI/RHR System Operability Test - Loop B and 0PT-08.2.7, LPCI/RHR Pump Response Time Test, after modification of the 1B loop minimum flow valve logic on March 7, 2011.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following: 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 corrective action program and that the problems were being corrected commensurate with their importance to safety.

b. Findings

No findings were identified.

1R20 Outage Activities

a. Inspection Scope

The inspectors reviewed the outage plan and contingency plans for the Unit 2 refueling outage, which started on March 4, 2011, and extended through the end of the inspection period, 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 cooldown 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;
  • 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;
  • Refueling activities, including fuel handling and storage; and
  • Licensee identification and resolution of problems related to refueling outage activities.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Routine Surveillance Testing

a. Inspection Scope

The inspectors either observed surveillance tests or reviewed the test results for the three following activities to verify the tests met TS surveillance requirements, UFSAR commitments, inservice 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.

  • 0PT-08.2.2b, LPCI/RHR System Operability Test - Loop B on February 24, 2011;
  • 0PT-13.1, Unit 1 Reactor Recirculation Jet Pump Operability on March 10, 2011; and
  • 0PT-12.2B, No. 2 Diesel Generator Monthly Load Test on March 15, 2011.

b. Findings

No findings were identified.

.2 In-Service Testing (IST) Surveillance

a. Inspection Scope

The inspectors reviewed the performance of 0PT-07.2.4A, Unit 1 Core Spray System Operability Test - Loop A on January 12, 2011, to evaluate the effectiveness of the licensees American Society of Mechanical Engineers (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.

b. Findings

No findings were identified.

.3 Containment Isolation Valve Testing

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

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 corrective action program.

b. Findings

No findings were identified.

1EP6 Emergency Planning Drill Evaluation

a. Inspection Scope

The inspectors observed a site emergency preparedness training drill conducted on January 11, 2011. 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 drills performance with respect to performance indicators and assessed drill performance with respect to drill objectives.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Radiological Hazard Assessment and Exposure Controls. The inspectors evaluated licensee performance in assessing radiological hazards and controlling worker access to radiologically-significant areas. The inspectors evaluated communications to the workers, contamination and radioactive material control, radiological hazard controls to include work coverage, controls and contingencies for risk-significant high radiation areas (HRA) and very high radiation areas (VHRA), radiation worker practices and technician proficiency and problem identification and resolution.

Radiological Hazard Assessment. During facility tours, the inspectors directly observed postings and physical controls for radiation areas, HRAs, locked HRAs (LHRA), VHRA, and potential airborne radioactivity areas established within the radiologically-controlled area (RCA) of the Unit 2 drywell, Unit 1 and Unit 2 reactor and turbine buildings, Independent Spent Fuel Storage Installation (ISFSI), 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. Results were compared to current licensee surveys and assessed against established postings and Radiation Work Permit (RWP) controls. Licensee key control and access barrier effectiveness were evaluated for selected LHRA and VHRA locations. Changes to procedural guidance for LHRA and VHRA controls were discussed with radiation protection (RP) supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool (SFP) were reviewed and discussed. In addition, licensee controls for areas where dose rates could change significantly because of plant shutdown and refueling operations associated with the Unit 2 refueling outage (RFO) were reviewed and discussed. The licensees deployment of portable air monitors was reviewed and the airborne radioactivity monitoring program was discussed with cognizant RP personnel.

Instructions to Workers. As part of the review, the inspectors reviewed the As Low As Reasonably Achievable (ALARA) packages and RWPs for selected Unit 2 RFO activities. The inspectors observed RP personnel providing entry briefings to workers entering the Unit 2 drywell and reactor building to conduct work associated with snubber inspections, motor-operated valve activities, chemical decontamination associated with reactor water cleanup activities, inboard MSIV activities, and torus diving activities.

Container labeling was reviewed for legibility, currency and clarity for selected areas of the Unit 2 drywell, Unit 1 and Unit 2 reactor and turbine buildings, radwaste processing areas, ISFSI, and in the RCA of the yard.

Contamination and Radioactive Material Control. The inspectors observed the routine release of materials and personnel from the RCA. The sensitivity of the instrumentation was discussed with selected RP personnel. The inspectors reviewed the radioactive source inventory and verified the physical presence of the most radiologically-significant sources. The inspectors reviewed a memo documenting the transmittal of database information submitted to the National Source Tracking System (NSTS) per 10 CFR 20.2207.

Radiological Hazards Control and Work Coverage. The inspectors reviewed radiological conditions for consistency with posted surveys, RWPs and worker briefings. The RP controls were assessed for area radiation surveys, radiation postings, radiation contamination controls and RP job coverage for selected Unit 2 RFO work activities.

The inspectors observed selected Unit 2 RFO job coverage for activities associated with the refueling floor and controls for highly activated or contaminated materials stored underwater. The inspectors observed selected Unit 2 RFO work activities via closed circuit television in the remote monitoring room. During tours of the licensee facilities, the inspectors checked postings and verified locking on areas with dose rates greater than 1,000 millirem per hour at 30 centimeters from the source.

Risk-Significant HRAs and VHRA Controls. The inspectors discussed the controls for high risk HRAs and VHRAs with the RP Manager. The procedures that would be implemented where conditions had changed or were reasonably expected to change resulting in the creation of HRAs, LHRAs or VHRAs were discussed with selected operational RP Supervisors. The inspectors observed RP staff issuing LHRA keys for selected Unit 2 RFO work activities.

Radiation Worker and Technician. The inspectors observed radiation worker performance and RP technician proficiency during tours of selected areas of the plant.

The inspectors reviewed corrective action program documents identifying radiation worker performance issues and RP technician proficiency. The inspectors reviewed the corrective action program documents for determination of reporting threshold, as well as adequacy of resolution of the reported problems. The review included an evaluation of selected electronic dosimeter (ED) alarms to determine if the identified events constituted exceeding the performance indicator reporting thresholds.

RP activities were evaluated against the requirements of UFSAR Section 12; TS 5.7.1 and 5.7.2. 10 CFR Parts 19 and 20; and approved licensee procedures.

Problem Identification and Resolution. Licensees corrective action program documents associated with access control to radiologically-significant areas were reviewed and assessed. This included review of selected Condition Reports (CRs) related to radworker and RP technician performance. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure CAP-NGGC-200, Condition Identification and Screening Process, Revision 33. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

The inspectors completed all specified line-items detailed in Inspection Procedure (IP)71124.01 (sample size of 1).

b. Findings

Introduction.

The inspectors identified a NCV of TS 5.4.1 for the failure of the licensee to perform initial alpha activity analysis of air samples indicating greater than 0.3 Derived Air Concentration (DAC) beta-gamma activity on an approved alpha counter as required by the licensees procedures.

Description.

On March 10, 11, and 21, 2011, the licensee did not perform an initial alpha count on air samples where gamma scan results exceeded 0.3 DAC. Specifically, air samples for selected work activities identified DAC concentrations of 0.6589, 0.3152 and 1.45. These samples were not evaluated for alpha in accordance with HPS-NGGC-0024, Alpha Monitoring Guidelines, Rev. 3. When an air sample was collected, RP performed an initial screening count to determine if further evaluation would be required.

If the screening results exceeded the 0.3 DAC criteria, then the sample would be sent to Chemistry for an isotopic analysis. If the isotopic analysis confirmed that the results exceeded the 0.3 DAC criteria then the sample would be further evaluated on an approved alpha counter by Chemistry personnel at the request of RP. For those selected work activities, RP did not request Chemistry to perform an initial alpha count using an approved counter. The licensee had identified low levels of alpha activity in the source term based on the results of 10 CFR 61 sample analysis and area radiation contamination surveys of the plant.

Analysis.

The inspectors determined that the routine failure to follow the procedural requirement to perform alpha activity analysis of air samples exceeding the trigger level of 0.3 DAC beta-gamma activity, was a performance deficiency. This finding is greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Program and Process (Monitoring and RP Controls) and adversely affects the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from airborne radioactive material during routine civilian nuclear reactor operation. Failure to identify potentially significant contributors to internal dose could lead to unmonitored occupational exposures. The finding was evaluated using the Occupational Radiation Safety SDP and was determined to be of very low safety significance (Green) because it was not related to ALARA planning and the ability to assess dose was not compromised during these instances. In addition, it did not involve overexposure or substantial potential for overexposure because of the relatively low alpha source term in the areas where the surveys were performed. This conclusion was drawn from the results of beta/gamma and alpha smear surveys performed at those selected work locations. However, if left uncorrected, unmonitored internal exposure could have occurred in areas of the plant where alpha emitters would be present. The cause of this finding was directly related to the cross-cutting aspect of maintaining effective interfaces between work groups in the Work Control component of the Human Performance area. H.3(b).

Enforcement.

TS 5.4.1, Administrative Control (Procedures), requires that written procedures shall be established, implemented, and maintained, covering applicable procedures recommended in RG 1.33, App. A, Nov. 1972 (Safety Guide 33, Nov. 1972).

Section G.5.c of RG 1.33, App. A, Nov. 1972 (Safety Guide 33, Nov. 1972) states that the licensee has procedures for control of radioactivity for personnel monitoring and special work permit for surveys and monitoring. Procedure HPS-NGGC-0024, Alpha Monitoring Guidelines, Rev. 3 implements the requirement to perform alpha monitoring activities. Sect. 9.5.12.h. of the procedure states that if gamma scan results indicate the airborne activity is equal to or greater than the beta-gamma DAC-Fraction Action level of 0.3 DAC:

(1) perform an initial alpha count on the air sample using a counter approved for air samples; and
(2) assess and document the results per site-specific procedures.

Contrary to the above, on March 10, 11, and 21, 2011, the licensee did not perform an initial alpha count on air samples using a counter approved for air samples and assess and document the results for gamma scan results that exceeded 0.3 DAC. Specifically, air samples for those selected work activities identified DAC concentrations of 0.6589, 0.3152 and 1.45, which had exceeded the 0.3 DAC concentration criteria and had not been counted on an approved alpha counter, assessed, and documented per site-specific procedures. Licensee corrective actions included instructions to workers to ensure procedural adherence for sample analysis and changes to the software program to prompt the workers to do the sample analysis when the threshold limits were met or exceeded. Because this violation was of very low significance and was entered into the licensees corrective action program (NCR 455307), this violation is being treated as an NCV, consistent with the NRC Enforcement Policy, and is identified as NCV 05000325/324, 20110002-02, Failure to follow procedures for analyzing radiological air samples for the presence of alpha emitters.

2RS2 As Low As Reasonably Achievable (ALARA)

a. Inspection Scope

ALARA Program Status. The inspectors reviewed and discussed plant exposure history and current trends including the sites three-year rolling average (TYRA) collective exposure history for calendar year (CY) 2007, through CY 2009. Current and proposed activities to manage site collective exposure and trends regarding collective exposure were evaluated through review of previous TYRA collective exposure data and review of the licensees 5-year ALARA program implementing plan. Current ALARA program guidance and recent changes, as applicable, regarding estimating and tracking exposure were discussed and evaluated.

Radiological Work Planning The inspectors reviewed planned work activities and their collective exposure estimates for Unit 2 RFO. Work activities, exposure estimates and mitigation activities were reviewed for selected Unit 2 RFO work activities that included B220R1 motor operated valve project, insulation removal and replacement, main steam isolation valve, scaffolding, refuel floor, integrated inspections, 2-B32-F023A and F031A seal weld repair, and 2-E11-F050A repair. For the selected tasks, the inspectors reviewed dose mitigation actions and established dose goals. During the inspection, use of remote technologies including teledosimetry and remote visual monitoring were verified as specified in RWP or procedural guidance. Current collective dose data for selected tasks were compared with established estimates and, where applicable, changes to established estimates were discussed with responsible licensee ALARA planning representatives. The inspectors reviewed previous post-job reviews conducted for the previous Unit 1 RFO and verified that the items were entered into the licensees CAP for evaluation.

Verification of Dose Estimates and Exposure Tracking Systems. The inspectors reviewed select ALARA work packages and discussed assumptions with responsible planning personnel regarding the bases for the current estimates. The licensees on-line RWP cumulative dose data bases used to track and trend current personal and cumulative exposure data and/or to trigger additional ALARA planning activities in accordance with current procedures were reviewed and discussed. Selected work-in-progress reviews for thimble and reactor coolant pump motor replacement project activities and adjustments to cumulative exposure estimate data were evaluated against work scope changes or unanticipated elevated dose rates.

Source Term Reduction and Control. The inspectors reviewed historical dose rate trends for shutdown chemistry, cleanup, and resultant chemistry and RP trend-point data against the current Unit 2 RFO data. Licensee actions to mitigate noble gas and iodine exposures resulting from fuel leaks were discussed in detail.

Problem Identification and Resolution. The inspectors reviewed and discussed selected CRs associated with ALARA program implementation. The reviewed items included CRs, self-assessments, and quality assurance audit documents. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with licensee procedure CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 33.

The licensees ALARA program activities and results were evaluated against the requirements of UFSAR Section 12; TS Sections 5.4 and 5.7; 10 CFR Parts 19 and 20; and approved licensee procedures.

Radiation worker performance was reviewed as part of observations conducted for IP 71124.01 and is documented in section 2RS1. The inspectors completed all specified line items detailed in IP 71124.02 (sample size of 1).

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Plant Airborne Radioactivity Controls and Mitigation. The inspectors reviewed the plants UFSAR and current Unit 2 RFO tasks to identify areas and tasks with the potential for elevated airborne radionuclide concentrations. Selected engineering controls including the Unit 2 dry well purge, refueling floor ventilation, and temporary HEPA filtration units for minimizing personal exposure, and airborne radiation monitoring instrumentation located within the low level radioactive waste processing building and refueling floor areas were discussed with RP and operations staff. In addition, selected licensee documents including TS, UFSAR, design basis documents, Emergency Response Organization (ERO) rosters, and procedures associated with plant airborne radioactivity controls and monitoring, and with respiratory protection program and emergency planning implementation were reviewed and discussed with cognizant licensee representatives.

Engineering Controls. Licensee engineering controls to control and mitigate airborne radioactivity were reviewed and discussed. The inspectors evaluated engineering controls use for RP purposes including operation of the Unit 2 Dry Well Purge and Refueling Floor ventilation, and installation of temporary HEPA systems for selected tasks and operations with the potential for generating airborne activity conditions during the current Unit 2 RFO. The evaluation included procedural guidance, operability testing, and established configurations during specific tasks. In addition, plant guidance and its implementation for the monitoring of potential airborne beta-gamma and alpha-emitting radionuclides for insulation removal were reviewed and discussed with licensee representatives.

Use of Respiratory Protection Devices. Program guidance for issuance and use of respiratory protection devices was reviewed and discussed with responsible licensee representatives. The inspectors reviewed Total Effective Dose Equivalent (TEDE)-

ALARA evaluations conducted for the select Unit 2 RFO tasks with an emphasis on insulation removal activities. Selected whole-body count routine and investigative analysis results for occupational workers were reviewed and discussed. Use of respiratory protective equipment was evaluated for the workers involved in Unit 2 RFO 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 verified Grade D or greater air certification for all on-site compressors. Training, fit testing, and medical qualifications for selected RP, maintenance, and operations staff using respiratory protection activities for Unit 2 RFO activities were reviewed and verified.

Self-Contained Breathing Apparatus (SCBA) for Emergency Use. The inspectors verified current status, operability and availability of select SCBA equipment maintained within the firehouse, operations support center, Unit 1 and Unit 2 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 was verified for selected SCBA units. Training, fit testing, and medical qualifications for selected RP, maintenance, and operations staff assigned ERO duties was reviewed and verified. For selected Unit 1 and Unit 2 control room operators, the inspectors discussed and verified annual hands-on SCBA training activities including donning, doffing and functionally checking SCBA equipment and availability of corrective lenses, as applicable, for on-shift personnel.

Problem Identification and Resolution. The inspectors reviewed selected corrective action program documents within the area of radiological airborne controls and respiratory protection activities. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 33, and CAP-NGGC-205, Condition Evaluation and Corrective Action Process, Rev. 12. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

RP 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 Procedures, 10 CFR Part 20; and approved licensee procedures.

Documents reviewed are listed in Sections 2RS1, 2RS2, and 2RS3. The inspectors completed all specified line-items detailed in IP 71124.03 (sample size of 1).

a. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation

a. Inspection Scope

Waste Processing and Characterization. During inspector walk-downs, accessible sections of the liquid and solid radioactive waste (radwaste) processing systems were assessed for material condition and conformance with system design diagrams.

Inspected equipment included radwaste storage tanks; resin transfer piping, resin and filter packaging components; and unused evaporator equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee staff. In addition, the inspectors completed a walkdown of a spent resin transfer system and dewatering facility and observed shredding and compacting of Dry Active Waste (DAW) in the low level radioactive waste facility.

The 2009 Radioactive Effluent Release Report and radionuclide characterizations from 2009 - 2010, for each major waste stream, were reviewed and discussed with radwaste staff. For reactor water and condensate (primary) resin, reactor coolant system filters, and DAW the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream mixing and concentration averaging methodology for resins and filters was evaluated and discussed with radwaste staff. The inspectors also reviewed the licensees procedural guidance for monitoring changes in waste stream isotopic mixtures.

Radwaste processing activities and equipment configuration were reviewed for compliance with the licensees Process Control Program (PCP) and UFSAR, Chapter 11. Waste stream characterization analyses were reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 61, and guidance provided in the Branch Technical Position on Waste Classification (1983).

Radioactive Material Storage. During walk-downs of indoor and outdoor radioactive material storage areas, the inspectors observed the physical condition and labeling of storage containers and the posting of Radioactive Material Areas. The inspectors also reviewed licensee procedural guidance for storage and monitoring of radioactive material.

Radioactive material and waste storage activities were reviewed against the requirements of 10 CFR Part 20.

Transportation. The inspectors directly evaluated licensee actions during preparation of a condensate pump motor for shipment and inspected a previously-prepared rail car shipment containing five c-van containers awaiting shipment. The inspectors noted package markings and labeling, performed independent dose rate measurements, and interviewed shipping technicians regarding their knowledge of Department of Transportation (DOT) regulations.

Selected shipping records were reviewed for consistency with licensee procedures and compliance with NRC and DOT regulations. The inspectors reviewed emergency response information, DOT shipping package classification, waste classification, and radiation survey results, and evaluated whether receiving licensees were authorized to accept the packages. Licensee procedures for opening and closing Type A shipping containers were compared to manufacturer requirements. In addition, training records for selected individuals currently qualified to ship radioactive material were reviewed.

Transportation program implementation was reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 71, 49 CFR Parts 172-178, as well as the guidance provided in NUREG-1608. Training activities were assessed against 49 CFR Part 172 Subpart H.

Problem Identification and Resolution. The inspectors reviewed CRs in the area of radwaste/shipping. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure CAP-NGGC-0200, Condition Identification and Screening Process, Rev. 33, and CAP-NGGC-0205, Condition Evaluation and Corrective Action Process, Rev. 12. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

The inspectors completed all specified line-items detailed in IP 71124.08 (sample size of 1).

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

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.

Initiating Events Cornerstone

  • Unplanned scrams per 7000 Critical Hours;
  • Unplanned scrams with complications; and
  • Unplanned power changes per 7000 Critical Hours The inspectors sampled licensee submittals for the performance indicators listed above for the period of the first quarter 2010 through the fourth quarter 2010. 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.

Occupational Radiation Safety Cornerstone The inspectors reviewed, evaluated, and discussed PI data collected from January 1, 2010, through February 28, 2011, for the Occupational Exposure Control Effectiveness PI. For the reviewed period, the inspectors assessed corrective action program records to determine whether HRA, VHRA or unplanned exposures, resulting in TS or 10 CFR 20 non-conformances, had occurred during the review period. The review included evaluation of selected personnel contamination event data, internal dose assessment results, and electronic dosimeter (ED) alarms for cumulative doses and/or dose rates exceeding established set-points.

Public Radiation Safety Cornerstone The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from January 1, 2010, through February 28, 2011. For the assessment period, the inspectors reviewed cumulative and projected doses to the public and CR documents related to Radiological Effluent TS/Offsite Dose Calculation Manual issues.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

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 corrective action program. The review was accomplished by reviewing daily action request reports.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Independent Spent Fuel Storage Installation (ISFSI) Inspections

a. Inspection Scope

The inspectors reviewed reported changes made to the licensees procedures and programs for the ISFSI to verify the changes made were consistent with the license and Certificate of Compliance (CoC), and did not reduce the effectiveness of the program.

The inspectors, through direct observation and independent evaluation, verified that cask loading activities were performed in a safe manner and in compliance with approved procedures for the Unit 1 fuel loading activities during the week of February 7, 2011. Based on direct observation and review of selected records, the inspectors verified the licensee had properly identified each fuel assembly placed in the ISFSI, had recorded the parameters and characteristics of each fuel assembly, and had maintained a record of each as a controlled document. Activities observed include: transport and storage of a cask; loading of spent fuel into a cask; drying and cask seal welding activities; and lifting and rigging the cask from the spent fuel pool. The inspectors reviewed the design limitation for each cask and compared the specified cask loading to the casks loading limitations. The inspectors verified that limitations for heavy load lifts in and around the spent fuel pool had been incorporated into the licensees procedures and were being implemented.

b. Findings

No findings were identified.

.2 (Closed) Temporary Instruction (TI) 2515/179 Verification of Licensee Responses to

NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

a. Inspection Scope

The inspectors performed the TI concurrent with IP 71124.01, Radiation Hazard

Analysis.

The inspectors reviewed the licensees source inventory records and identified the sources that met the criteria for reporting to the National Source Tracking System (NSTS). The inspectors visually identified the sources contained in various calibration systems and verified the presence of the source by direct radiation measurement using a calibrated portable radiation detection survey instrument. The inspectors reviewed the physical condition of the irradiation device. The inspectors reviewed the licensees procedures for source receipt, maintenance, transfer, reporting and disposal. The inspectors reviewed documentation that was used to report the sources to the NSTS.

This completes the Region II inspection requirements.

b. Findings

No findings were identified.

.3 (Closed) TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling, Decay

Heat Removal, and Containment Spray Systems (NRC Generic Letter (GL) 2008-01)

a. Inspection Scope

The inspectors reviewed the implementation of the licensees actions in response to Generic Letter 2008-01. The systems reviewed included the high pressure coolant injection, low pressure coolant injection, and core spray systems. The inspectors performed the following inspection activities. Documents reviewed are listed in the

.

  • Reviewed the licensing basis to verify that actions to address gas accumulation were consistent with the operability requirements
  • Reviewed the design basis to verify that actions taken to address gas accumulation were appropriate
  • Reviewed analyses performed by the licensee to verify that methodologies for predicting gas void accumulation, movement, and impact were appropriate
  • Reviewed test procedures and test results to verify that test procedures were appropriate to detect gas accumulations that could challenge the safety function of these systems
  • Reviewed the testing frequencies to verify that the testing intervals were appropriate based on historical gas accumulation events and susceptibility to gas accumulation
  • Reviewed the test programs and processes to verify that they were sensitive to precursors to gas accumulation
  • Reviewed corrective actions associated with gas accumulation to verify that identified issues were being appropriately identified and corrected
  • Reviewed plant modifications including the installation of additional vent valves
  • Reviewed selected vent valve installations to verify that the locations selected were appropriate
  • Performed walk downs of selected subject systems to verify that the reviews and design verifications conducted by the licensee had drawn appropriate conclusions with respect to piping configurations and pipe slope which could result in gas accumulation susceptibility

b. Findings

No findings were identified.

4OA6 Management Meetings

On January 26, 2011, the inspectors held a teleconference with licensee staff and a State of North Carolina radiation protection representative to discuss the status of BSEPs 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 onsite storm drain stabilization pond (SDSP). 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 action was initiated. The inspectors also 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 nearing completion of a network of sub-surface pumping wells designed to remediate the groundwater in and around the SDSP and will soon begin construction of a new-double lined pond to replace the SDSP. The details surrounding a leak of tritiated water from underground piping associated with the Unit 1 condensate storage tank (CST) in December 2010 were also discussed. More information on this leak can be found in Inspection Report 2010-005 and in a docketed 30-day report to the NRC. The meeting details are documented in NCR 402755. Publicly available information regarding onsite groundwater monitoring, and radionuclide concentrations in the environment near BSEP, can be found in the Annual Radiological Environmental Operating Report. The 2009 Annual Report is currently available through the Agency-Wide Documents Access and Management Systems (ADAMS) at http://www.nrc.gov/reading-rm/adams.html (accession number ML101380657). The 30-day report regarding the CST piping leak is also available through ADAMS (accession number ML110190210).

An exit meeting was conducted for the ISI inspection activities (section 1R08) on March 18, 2011, with Mr. Michael Annacone, and other members of the licensee staff. The licensee did not identify any material provided to the inspector to be proprietary.

On March 25, 2011, the inspectors discussed preliminary results of the onsite RP inspection with Mr. Michael Annacone, and other members of the licensee staff. The inspectors noted that proprietary information was reviewed during the course of the inspection but would not be included in the documented report.

On April 21, 2011 the resident inspectors presented the remaining inspection results to Mr. Joe Frisco, and other members of the licensee staff.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

M. Annacone, Site Vice President
C. Barnhill, Dosimetry Supervisor
L. Beller, Superintendent, Operations Training
W. Brewer, Manager - Maintenance
A. Brittain, Manager - Security
J. Burke, Manager - Outage and Scheduling
B. Davis, Director - Engineering
P. Dubrouillet, Manager - Training
C. Dunsmore, Manager - Shift Operations
J. Frisco, Plant General Manager
C. George, Manager - Technical Support Engineering
K. Gerald, Superintendent - Mechanical Maintenance
S. Gordy, Manager - Operations
L. Grzeck, Lead Engineer - Technical Support
R. Ivey, Manager - Nuclear Oversight Services
F. Jefferson, Manager - Systems Engineering
J. Johnson, Manager - Environmental and Radiological Controls
M. Millinor, Sr. Chemistry Specialist
P. Mentel, Manager - Support Services
R. Mullis, Supervisor - Operations Training
D. Petrusic, Superintendent - Environmental and Chemistry
A. Pope, Supervisor - Licensing and Regulatory Affairs
E. Rochelle, Supervisor, Radiation Control
T. Sherrill, Engineer - Technical Support
P. Smith, Superintendent - Electrical, Instrumentation, and Controls Maintenance
S. Taylor, Supervisor, Radioactive Waste Shipping
J. Titrington, Manager - Design Engineering
M. Turkal, Lead Engineer - Technical Support
J. Vincelli, Superintendent - Radiation Protection
E. Wills, Director - Site Operations

NRC Personnel

Randall

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

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000325/2011002-01 AV Failure To Adequately Evaluate And Correct A Condition Adverse To Quality Involving A Manufacturing Defect Of Barton Model 199 Dual Dampener Differential Pressure Units (Section 1R15)

Opened and Closed

05000325,324/2011002-02 NCV Failure to follow procedures for analyzing radiological air samples for the presence of alpha emitters (Section RS01)

Closed

TI 2515/179 TI Verification of Licensee Responses to NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207) (Section 4OA5.2)

TI 2515/177 TI Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter (GL) 2008-01)

(Section 4OA5.3)

LIST OF DOCUMENTS REVIEWED

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