IR 05000259/2013003

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IR 05000259-13-003, 05000260-13-003, 05000296-13-003; 04/01/2013 - 06/30/2013; Browns Ferry Nuclear Plant, Units 1, 2 and 3; Equipment Operability Evaluations and Follow-up of Events
ML13226A550
Person / Time
Site: Browns Ferry  Tennessee Valley Authority icon.png
Issue date: 08/14/2013
From: Scott Shaeffer
Reactor Projects Region 2 Branch 6
To: James Shea
Tennessee Valley Authority
References
IR-13-003
Download: ML13226A550 (63)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ust 14, 2013

SUBJECT:

BROWNS FERRY NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000259/2013003, 05000260/2013003, AND 05000296/2013003

Dear Mr. Shea:

On June 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Browns Ferry Nuclear Plant, Units 1, 2, and 3. The enclosed inspection report documents the inspection results which were discussed on April 12, May 31, July 9, and August 5, 2013, with Mr. K. Polson, Site Vice President, 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, orders, and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Two self-revealing findings of very low safety significance (Green) were identified during this inspection. Both of these findings were determined to involve violations of NRC requirements.

Further, one licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating the violations as non-cited violations (NCV) consistent with Section 2.3.2 of the Enforcement Policy. If you contest any of these non-cited violations, 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: (1) the Regional Administrator, Region II; (2) the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and (3) the NRC Resident Inspector at the Browns Ferry Nuclear Plant.

In addition, if you disagree with any cross-cutting aspect assignment in the 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 Browns Ferry Nuclear Plant. 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 the NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html.

Sincerely,

/Gerald McCoy RA for/

Scott Shaeffer, Chief Reactor Projects Branch 6 Division of Reactor Projects Docket Nos.: 50-259, 50-260, 50-296 License Nos.: DPR-33, DPR-52, DPR-68

Enclosure:

NRC Integrated Inspection Report 05000259/2013003, 05000260/2013003 and 05000296/2013003

REGION II==

Docket Nos.: 50-259, 50-260, 50-296 License Nos.: DPR-33, DPR-52, DPR-68 Report No.: 05000259/2013003, 05000260/2013003, 05000296/2013003 Licensee: Tennessee Valley Authority (TVA)

Facility: Browns Ferry Nuclear Plant, Units 1, 2, and 3 Location: Corner of Shaw and Nuclear Plant Roads Athens, AL 35611 Dates: April 1, 2013, through June 30, 2013 Inspectors: D. Dumbacher, Senior Resident Inspector L. Pressley, Resident Inspector T. Stephen, Resident Inspector C. Stancil, Resident Inspector P. Niebaum, Resident Inspector K. Miller, Resident Inspector R. Hamilton, Senior Health Physicist J. Rivera, Health Physicist R. Kellner, Health Physicist M. Riches, Project Engineer J. Montgomery, Reactor Inspector A. Sengupta, Reactor Inspector Approved by: Scott Shaeffer, Chief Reactor Projects Branch 6 Division of Reactor Projects Enclosure

SUMMARY

IR 05000259/2013003, 05000260/2013003, 05000296/2013003; 04/01/2013 - 06/30/2013;

Browns Ferry Nuclear Plant, Units 1, 2 and 3; Equipment Operability Evaluations and Follow-up of Events.

The report covered a three month period of inspection by the resident inspectors and regional 6 inspectors. Two self-revealing finding of very low safety significance (Green) were identified.

The significance of most findings is identified by their color (Green, White, Yellow, and Red)using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP); and, the cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

List of Findings and Violations

Cornerstone: Mitigating Systems

Green.

A self-revealing Non-Cited Violation (NCV) of 10 CFR 50 Appendix B, Criterion V,

Instructions, Procedures, and Drawings, was identified for the licensees failure to establish a preventive maintenance program as required by procedure NPG-SPP-06.2, Preventive Maintenance. Specifically, the Residual Heat Removal Service Water Pump D1 Cross-Tie to Emergency Equipment Cooling Water (EECW) Valve (0-FCV-067-0048) was not maintained in a manner that ensured it would perform its design function. The valve was replaced on January 16, 2013, with a new valve with a stainless steel disk. Corrective actions were planned to develop preventive maintenance activities for this valve. The licensee entered this issue into their corrective action program.

This issue was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone objective and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the 0-FCV-067-0048 valve failed and could not perform its isolation function. The finding was previously characterized as To Be Determined (TBD) in the Browns Ferry inspection report number 05000259, 260, 296/2013002, dated May 14, 2013.

The issue was screened per IMC 0609, Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, and was determined to be a Green finding because it did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The cause of this finding was directly related to the cross-cutting aspect of Appropriately Coordinating Work Activities in the Work Control component of the Human Performance area, because maintenance activities for 0-FCV-067-0048 were more reactive than preventive. H.3(b), (Section 1R15.1)

Green.

A self-revealing non-cited violation (NCV) of Technical Specifications 3.5.1,

Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC)

System was identified associated with the licensees failure to perform a post maintenance test (PMT) as required by licensee procedure NPG-SPP-06.3, Pre-/Post Maintenance Testing. Specifically, the licensee failed to perform a PMT to verify the proper operation of the 2E RMOV Board alternate feeder breaker on July 10, 2012. The licensee entered this issue as an immediate corrective action into their corrective action program and the failed alternate feeder breaker to the Unit 2 2E 480V RMOV Board trip pushbutton was restored to the proper condition on July 19, 2012, at 0303.

This finding was more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the Unit 2, 2E 480V RMOV Board alternate feeder breaker was left in a tripped condition and unable to close for nine days. The issue was screened per IMC 0609, Appendix A, Exhibit 2 -

Mitigating Systems Screening Questions, and was determined to be a Green finding because it did not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The cause of this finding was associated with the Human Performance area, Work Practices component, cross-cutting aspect of appropriate oversight of work activities because maintenance work activities for the alternate feeder breaker for the 2E 480V RMOV board did not include a check to ensure the breakers nuclear safety function was supported. H.4(c). (Section 4OA3.2)

Violations of very low safety significance or Severity Level IV that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at full Rated Thermal Power (RTP) except for a planned downpower to 75 percent from June 15-17, 2013, for rod sequence exchange, scram time testing, and main condenser water box cleaning. The unit remained near full power the remainder of the quarter.

Unit 2 started the quarter shutdown due to refueling outage 17. The unit was restarted on May 4, 2013 and synchronized to the grid on May 5, 2013. Unit 2 operated at full RTP except for three planned down powers and two unplanned downpowers. On May 8, 2013, a planned downpower from 87 percent to 71 percent was performed for rod pattern adjustment. On May 19, 2013, a planned downpower to 85 percent was performed for reactor feedwater pump maintenance. On June 8, 2013, a planned down power to 75 percent was performed for rod pattern adjustment. On June 12, 2013, an unplanned downpower occurred to 94 percent due to feedwater heater level controller problems. On June 15, 2013, an unplanned downpower occurred to 97 percent due to automatic isolation of extraction steam to B1 and B2 high pressure feedwater heaters. The unit remained near full power the remainder of the quarter.

Unit 3 operated at full RTP except for five planned downpowers. On April 18, 2013, and April 20, 2013, planned downpowers to 95 percent were performed to remove and restore extraction steam from A1/A2 high pressure heaters for maintenance. From June 15-16, 2013, a planned downpower was performed to 92 percent for main condenser waterbox flushing. From June 22-23, 2013, a planned downpower was performed to 72 percent for main condenser waterbox flushing and cleaning. On June 25, 2013, a planned downpower to 80 percent was performed for main condenser waterbox cleaning and rod sequence exchange. The unit remained near full power the remainder of the quarter.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On April 11, 2013, a Tornado Warning was declared for Morgan County, approximately ten miles southeast of the power plant. The inspectors reviewed the licensees overall preparations/protection for the unexpected onset of severe weather conditions and observed the licensees implementation of abnormal operating instruction AOI 100-7, Severe Weather, including implementation of actions for Tornado Watch. Inspectors observed applicable contingency actions associated with Unit 2 in a refueling outage and potential elevation to shutdown risk level Orange. The inspectors also reviewed and discussed the implementation of 0-AOI-100-7 with the responsible Unit Supervisors and Shift Manager. Furthermore, the inspectors witnessed the licensees execution of evacuation orders of vulnerable areas and buildings outside the power block, and the termination of work and evacuation of the turbine floor. The inspectors also toured the plant grounds for loose debris, which could become missiles during a tornado, and reviewed operator staffing and their accessibility to controls and indications for those systems required for safe control of the plant. This activity constituted one inspection sample.

b. Findings

No findings were identified.

.2 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

Prior to and during the onset of hot weather conditions, the inspectors reviewed the licensees implementation of 0-GOI-200-3, Hot Weather Inspection, including applicable checklists - Attachment #1, Hot Weather Prep Annual Checklist; Attachment #2, and Hot Weather Operational Checklist; Attachment #3. The inspectors also reviewed the Hot Weather Discrepancy Log (PA-104); and discussed implementation of 0-GOI-200-3 with responsible Operations personnel and management. Inspectors also attended a Hot Weather readiness meeting. Furthermore, the inspectors monitored the status of risk significant equipment to cool the Unit 1, 2, and 3 control rooms and the status of the 7 cooling towers on site. This activity constituted one inspection sample.

b. Findings

No findings were identified.

.3 Offsite and Alternate AC Power Systems Readiness

a. Inspection Scope

Prior to the summer season, inspectors reviewed electrical power design features, and onsite risk and work management procedures to verify appropriate operational oversight and assurance of continued availability of offsite and alternate AC power systems.

Inspectors verified that communications protocols existed between the transmission system operator and Browns Ferry Nuclear Plant for coordination of off-normal and emergency events affecting the plant, event details, estimates of return-to-service times, and notifications of grid status changes. Inspectors also reviewed procedures to verify that they included controls to adequately monitor both offsite AC power systems (including post-trip voltages) and onsite alternate AC power systems for availability and reliability. Furthermore, inspectors interviewed onsite licensed operators to determine their understanding and implementation of the power monitoring and assessment process. Inspectors reviewed the material condition of offsite AC power systems and onsite alternate AC power systems to the plant, including switchyard and transformers.

This review included review of outstanding work orders affecting these systems and a walkdown of the switchyard with operations personnel to ensure the systems will continue to provide appropriate as designed capabilities. This activity constituted one inspection sample.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

The inspectors conducted five partial equipment alignment walkdowns to evaluate the operability of selected redundant trains or backup systems, listed below, while the other train or subsystem was inoperable or out of service. The inspectors reviewed the functional systems descriptions, Updated Final Safety Analysis Report (UFSAR), system operating procedures, and Technical Specifications (TS) to determine correct system lineups for the current plant conditions. The inspectors performed walkdowns of the systems to verify that critical components were properly aligned and to identify any discrepancies which could affect operability of the redundant train or backup system.

This activity constituted five Equipment Alignment Partial Walkdown inspection samples.

  • Unit 2 RCIC system walkdown following pressure transient to 1337 psig on May 6, 2013
  • Unit 1 Core Spray (CS) System, Loop II with Loop I out of service for Maintenance, May 9, 2013
  • Standby Gas Treatment (SBGT) trains A and B with train C without an emergency backup power source due to Emergency Diesel Generator 3D maintenance, May 17, 2013

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Walkdowns

a. Inspection Scope

The inspectors reviewed licensee procedures, Nuclear Power Group Standard Programs and Processes (NPG-SPP)-18.4.7, Control of Transient Combustibles, and NPG-SPP-18.4.6, Control of Fire Protection Impairments, and conducted a walkdown of five fire areas (FA) and fire zones (FZ) listed below. Selected FAs/FZs were examined in order to verify licensee control of transient combustibles and ignition sources; the material condition of fire protection equipment and fire barriers; and operational lineup and operational condition of fire protection features or measures. Also, the inspectors verified that selected fire protection impairments were identified and controlled in accordance with procedure NPG-SPP-18.4.6. Furthermore, the inspectors reviewed applicable portions of the Fire Protection Report, Volumes 1 and 2, including the applicable Fire Hazards Analysis, and Pre-Fire Plan drawings, to verify that the necessary firefighting equipment, such as fire extinguishers, hose stations, ladders, and communications equipment, was in place. This activity constituted five inspection samples.

  • Unit 1 Reactor building elevations 519 - 565 West (Fire Zone 1-1)
  • Unit 1 Reactor building elevations 519 - 565 East (Fire Zone 1-2)
  • Unit 3 Reactor Building elevations 519 - 565 East (Fire Zone 3-2)
  • Unit 3 4KV Shutdown Board Room 3EC and 3ED, Diesel Generator Building, elevations 565 and 583 (Fire Area 23)
  • Unit 3 4KV Bus Tie Board Room, Unit 3 Diesel Generator Building, EL 565 (Fire Area 24)

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

Unit 2 Residual Heat Removal (RHR) Heat Exchangers:

The inspectors examined activities associated with Unit 2 RHR Heat Exchangers. The inspectors also reviewed procedures used for testing flow rates; and reviewed design basis documents, calculations, test procedures, and results to evaluate the licensees program for maintaining heat sinks in accordance with the licensing basis. Furthermore, the inspectors reviewed PERs and corrective actions to verify that the licensee was identifying issues and correcting them.

The inspectors performed walkdowns of key components of RHRSW systems to verify material conditions were acceptable and physical arrangement matched procedures and drawings. The inspectors observed replacement of the floating head and cleaning and inspection activities associated with the Unit 2 A RHR heat exchanger. Inspectors reviewed licensee compliance to commitments made based on their response to the NRC Generic Letter 89-13 for service water system problems that could affect heat exchanger performance. A review of previous licensee inspections and fouling determination testing of the Unit 2 heat exchangers was performed. Licensee corrosion and mollusk control chemical addition processes for heat exchangers were also reviewed. This activity constituted one Heat Sink Performance Inspection sample.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification

.1 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors observed licensed operator performance during requalification testing and training following several weeks performing shift-work away from a training environment. The inspectors also observed the TVA training staff adequately conducting this training and correcting performance deficiencies. The inspectors also observed the fidelity of the simulator environment verifying the similarity to the actual plant control rooms. This activity constituted two Resident Inspector Quarterly Inspection samples.

  • May 13, 2013 observed Group 1 Crew D
  • May 20, 2013 observed Group 3 Crew A

b. Findings

No findings were identified.

.2 Control Room Observations

a. Inspection Scope

Several times during the inspection quarter the 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.

The inspectors reviewed various licensee policies and procedures such as OPDP-1, Conduct of Operations, NPG-SPP-10.0, Plant Operations and GOI-100-12, Power Maneuvering.

The inspectors utilized activities such as post maintenance testing, surveillance testing and refueling and other outage activities to focus on the following conduct of operations as appropriate;

  • 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.

This activity constituted one Control Room Observation inspection sample.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine

a. Inspection Scope

The inspectors reviewed the specific structures, systems and components (SSC) within the scope of the Maintenance Rule (MR) (10CFR50.65) with regard to some or all of the following attributes, as applicable:

(1) Appropriate work practices;
(2) Identifying and addressing common cause failures;
(3) Scoping in accordance with 10 CFR 50.65(b) of the MR;
(4) Characterizing reliability issues for performance monitoring;
(5) Tracking unavailability for performance monitoring;
(6) Balancing reliability and unavailability;
(7) Trending key parameters for condition monitoring;
(8) System classification and reclassification in accordance with 10 CFR 50.65(a)(1) or (a)(2);
(9) Appropriateness of performance criteria in accordance with 10 CFR 50.65(a)(2); and
(10) Appropriateness and adequacy of 10 CFR 50.65 (a)(1) goals, monitoring and corrective actions (i.e., Ten Point Plan). The inspectors also compared the licensees performance against site procedure NPG-SPP-3.4, Maintenance Rule Performance Indicator Monitoring, Trending and Reporting; Technical Instruction 0-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending and Reporting; and NPG-SPP 3.1, Corrective Action Program. The inspectors also reviewed, as applicable, work orders, surveillance records, PERs, system health reports, engineering evaluations, and MR expert panel minutes; and attended several MR expert panel meetings to verify that regulatory and procedural requirements were met. This activity constituted two Maintenance Effectiveness inspection samples.
  • May 23, 2013, Unit 2 RHR system Shift from a(1) status to a(2) status
  • June 13, 2013, Units 1, 2, 3 degraded temperature indications for the control rod drive mechanisms

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

For planned online work and/or emergent work that affected the combinations of risk significant systems listed below, the inspectors examined four on-line and one off-line maintenance risk assessments, and actions taken to plan and/or control work activities to effectively manage and minimize risk. The inspectors verified that risk assessments and applicable risk management actions (RMA) were conducted as required by 10 CFR 50.65(a)(4) applicable plant procedures, and BFN Equipment to Plant Risk Matrix.

Furthermore, as applicable, the inspectors verified the actual in-plant configurations to ensure accuracy of the licensees risk assessments and adequacy of RMA implementations. This activity constituted five Maintenance Risk Assessment inspection samples.

  • April 11, 2013; Entry into 0-AOI-100-7, Severe Weather for Tornado Watch with Unit 2 in Refueling Outage with both Shutdown Cooling Loops, Unit 1 Residual Heat Removal Loop 1, A3 RHR Service Water Pump, both Service Air Compressors, and D Control Air Compressor out-of-service (OOS)
  • April 22, 2013; Entry into 2-POI-200.5 Operations with the Potential to Drain the Reactor Vessel (OPDRV) for maintenance that was performed on the Unit 2 2A and 2B Recirculating Water Pump seals and the 2-FCV-69-1 Reactor Water Clean-Up (RWCU) pump suction inboard isolation valve.
  • May 20, 2013; Entry into the extended timeframe of the Emergency Diesel Generator (EDG) 3D outage to include availability of the other 7 EDGs and two Temporary Diesel Generators.
  • May 23, 2013; EDG 3D, 3EN LPCI MG Set, A3 RHRSW/EECW, A Control Bay Chiller, all out of service with 3E RMOV BD to ALT.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the operability/functional evaluations listed below to verify technical adequacy and ensure that the licensee had adequately assessed Technical Specification operability. The inspectors also reviewed applicable sections of the Updated Final Safety Analysis Report (UFSAR) to verify that the system or component remained available to perform its intended function. In addition, where appropriate, the inspectors reviewed licensee procedure NEDP-22, Functional Evaluations, and NEDP-27, Past Operability Evaluations, to ensure that the licensees evaluation met procedure requirements. Furthermore, where applicable, inspectors examined the implementation of compensatory measures to verify that they achieved the intended purpose and that the measures were adequately controlled. The inspectors also reviewed PERs on a daily basis to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. This activity constituted seven Operability Evaluation inspection samples.

  • Unit 2 RCIC system pressure transient during normal quarterly surveillance
  • Various RCIC, RWCU, and HPCI MOV stroke time requirements used nominal voltage and design packing loads versus calculated DC voltage and measured packing loads, May 24, 2013.

b. Findings

.1 Failure to Implement Preventive Maintenance Program (closeout of AV 05000259, 260,

296/2013002-001)

Introduction:

A self-revealing Green non-cited violation (NCV) of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to establish a preventive maintenance program to maintain the 0-FCV-067-0048, RHR Service Water Pump D1 Cross-Tie to Emergency Equipment Cooling Water (EECW) Valve, in a manner that ensured it would perform its design function as required by licensee procedure NPG-SPP-06.2, Preventive Maintenance.

Description:

The 0-FCV-067-0048 valve was a quarter-turn butterfly valve with a motor operator that allowed remote operation of the valve. The valve was the RHRSW/EECW cross tie valve installed in the discharge piping between the D1 RHRSW pump and the D3 EECW pump. The valve was required to be closed to maintain a boundary between these two interfacing systems. The licensee determined that the valve had not been replaced since its original installation during construction in August 1974. An inspection on January 10, 2013, revealed the 0-FCV-067-0048 cast iron valve disc separated from the valve stem with pieces of the valve disc found in the downstream pipe at the inlet of the D EECW strainer. The licensees root cause report (PER 671314) determined the direct cause of the valve failure was the cumulative effects of age and the pressure transients in the system. Licensee procedure NPG-SPP-06.2, Preventive Maintenance paragraph 3.2.1.B, required preventive maintenance programs to be structured to maintain components in a manner that permits them to perform their design functions.

According to BFN-50-7067, General Design Criteria Document for EECW, a design function of the 0-FCV-067-0048 valve was to isolate the EECW system from interfacing systems when necessary so that the EECW system may perform its required nuclear safety function. The inspectors concluded the lack of preventive maintenance prevented identification of valve degradation. No internal preventative maintenance was performed on the valve and the valve was left in service until it catastrophically failed and could not perform its design function. This valve failure resulted in unavailability of the D3 EECW pump and required the D1 RHRSW pump be aligned to supply the South EECW header.

Analysis:

The licensees failure to establish a preventive maintenance program to ensure the 0-FCV-067-0048 valve would perform its design function as required by procedure NPG-SPP-06.2, Preventive Maintenance, was a performance deficiency.

This finding was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone objective and adversely affected the cornerstone objective to ensure availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the 0-FCV-067-0048 valve failed and could not perform its isolation function. The inspectors initially evaluated the significance of the finding using Inspection Manual Chapter (IMC) 0609 Appendix F, "Fire Protection Significance Determination Process" and assigned the finding a Moderate Degradation rating. Additional information provided by the licensee indicated that although the capability of the EECW system to provide flow to components required for safe shutdown during a fire scenario was reduced; the system was capable of providing sufficient flow for equipment to perform their intended safety functions. Therefore the performance deficiency was determined not to affect the ability to reach and maintain safe shutdown conditions in case of a fire and was it more appropriate to assess the risk significance of this finding using IMC 0609, Appendix A. The issue was screened using IMC 0609, Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, and was determined to be a Green finding because it did not represent an actual loss of function of one or more non-Technical Specification Trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The cause of this finding was directly related to the Human Performance area Work Control component cross-cutting aspect of Appropriately Coordinating Work Activities because maintenance activities for 0-FCV-067-0048 were more reactive than preventive, H.3(b).

Enforcement:

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, required, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Procedure NPG-SPP-06.2, Preventive Maintenance, prescribed activities affecting quality related to the implementation of the preventive maintenance program. NPG-SPP-06.2 paragraph 3.2.1.B required the preventive maintenance program be structured to maintain components in a manner that permits them to perform their design functions. Contrary to the above, since the original installation of 0-FCV-067-0048, the licensee failed to implement a preventive maintenance program as prescribed by NPG-SPP-06.2, Preventive Maintenance. Specifically, the licensee failed to ensure the preventive maintenance program was structured to maintain 0-FCV-067-0048 in a manner that permitted it to perform its design function. This issue was entered in the licensees corrective action program as problem event report (PER) 671314 and 735824. The failed valve was replaced on January 16, 2013, with a stainless steel disk. Further corrective actions were planned to develop adequate preventive maintenance activities for this valve. This finding was identified as a non-cited violation: NCV 05000259, 260, 296/2013002-01, Failure to Implement an Adequate Preventive Maintenance Program.

.2 Unresolved Item (URI). The NRC identified an issue of concern associated with the April

14, 2009 2A Residual Heat Removal (RHR) Heat Exchanger (HX) raw water side inspection. It was determined that the licensee had failed to identify a degraded non-conforming condition of excessive fouling by Asiatic clams that exceeded the established tube plugging criteria.

Description:

The NRC working with organizations such as the Electric Power Research Institute (EPRI) had provided information to nuclear power plant license holders regarding fouling issues with raw water heat exchangers. In 1989, the NRC issued Generic Letter (GL) 89-13 to provide approved means to address heat exchanger fouling. Browns Ferrys response to GL 89-13, originally committed the licensee to perform once per cycle inspection and cleaning of the RHR HXs and periodically perform thermal performance testing to prove continued operability per TVA letter dated March 16, 1990. Once per cycle during this period in time was once per 18 months. In this letter, TVA reported that they had observed issues with Asiatic clam fouling in their HXs.

Browns Ferry later shifted the inspection and cleaning frequency to once every two years and then to once every four years without providing a basis or thermal performance testing of all the RHR HXs.

On April 14, 2009, Browns Ferry performed a GL 89-13 inspection of the 2A Residual Heat Removal (RHR) Heat Exchanger (HX). TVA inspections documented results which included pictures of the raw water side of the HX. The pictures showed 245 tubes had shells that were either partially or fully obstructed by shells. This exceeded the maximum calculated 77 clogged tubes needed to maintain the HX operable. The TVA inspections failed to adequately document the visible Asiatic clam fouling, and did not enter the degraded non-conforming condition into the corrective action program, as required by NPG-SPP-03.1 Corrective Action Program section 3.1.R. This would have necessitated an operability evaluation, as required by NPG-SPP-09.14 Generic Letter 89-13 Implementation procedure.

On April 24, 2013, the NRC challenged past operability of the 2A RHR HX from 2005 to 2009. The licensee stated that implementing a new revision to the NPG-SPP 09.14 procedure would prove operability. The update to the NPG-SPP 09.14 procedure for analyzing clam fouling was inadequate to prove operability. TVA then utilized a new (2012) Electric Power Research Institute (EPRI) analysis for determination of the effect of fouling on heat exchanger tubes to determine that the 2A RHR HX remained operable from 2005 to 2009. This method gives full heat transfer credit to any tube not greater than 85 percent clogged.

Additional inspection of the licensees application of the EPRI guidance and operability determinations is required to provide additional information needed for the NRC to disposition this issue. This unresolved item was tracked as URI 05000259, 260, 296/2013003-03.

1R18 Plant Modifications

.1 Permanent Plant Modifications

a. Inspection Scope

The inspectors reviewed the maintenance and repair of the Unit 2 High Pressure Coolant Injection (HPCI) turbine pump shaft (WO 114609716) including related documents and procedures. The inspectors reviewed licensee procedures NPG-SPP-09.3, Plant Modifications and Engineering Change Control, NPG-SPP-09.4, 10 CFR 50.59 Evaluations of Changes, Tests, and Experiments, NPG-SPP-09.20, Vendor Manual Control and NPG-SPP-06.9.3, Post-Modification Testing, and observed part of the licensees activities to implement this possible modification. The inspectors reviewed the associated 10 CFR 50.59 screening against the system design bases documentation to verify that the modifications had not affected system operability/availability. The inspectors reviewed selected ongoing and completed work activities to verify that installation was consistent with the design control documents. This activity constituted one Permanent Plant Modification sample.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors witnessed and reviewed the eight post-maintenance tests (PMT) listed below to verify that procedures and test activities confirmed Structures, Systems, and Components (SSC) operability and functional capability following the described maintenance. The inspectors reviewed the licensees completed test procedures to ensure any of the SSC safety function(s) that may have been affected were adequately tested, that the acceptance criteria were consistent with information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed and/or reviewed the test data, to verify that test results adequately demonstrated restoration of the affected safety function(s). The inspectors verified that PMT activities were conducted in accordance with applicable WO instructions, or licensee procedural requirements.

Furthermore, the inspectors verified that problems associated with PMTs were identified and entered into the CAP. This activity constituted eight Post Maintenance Test inspection samples.

  • April 24, 2013, Unit 2 Core Spray Loop I Comprehensive Testing following hand-switch replacement and valve disassembly and inspection, WO 113870368
  • April 29, 2013, Unit 2 Residual Heat Removal (RHR) Loop I auto initiation test following maintenance performed during Refueling Outage 17, 2-SR-3.5.1.9 (RHR I)
  • May 5, 2013, Unit 2 High Pressure Coolant Injection System comprehensive pump testing following system maintenance and modifications performed during Unit outage, 2-SR-3.5.1.7(COMP)
  • May 10, 2013, Unit 1 Core Spray Flow Rate Loop I following preventative maintenance items performed, 1-SR-3.5.1.6(CS1)

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

.1 Unit 2 Scheduled Refueling Outage (U2R17)

a. Inspection Scope

From March 14 to May 4, 2013, the inspectors examined critical outage activities to verify that they were conducted in accordance with Technical Specifications (TS),applicable procedures, and the licensees outage risk assessment and management plans. Activities observed March 14 through March 31 are documented in Inspection Report 2013-002. Significant inspection activities conducted by the inspectors were as follows:

Outage Risk Assessment The inspectors also reviewed the daily U2R17 Refueling Outage Reports, including the Outage Risk Assessment Management (ORAM) Safety Function Status, and regularly attended the twice a day outage status meetings. These reviews were compared to the requirements in licensee procedure NPG-SPP-07.2, Outage Management, and TS.

These reviews were also done to verify that for identified high risk significant conditions, due to equipment availability and/or system configurations, contingency measures were identified and incorporated into the overall outage and contingency response plan.

Furthermore, the inspectors frequently discussed risk conditions and designated protected equipment with Operations and outage management personnel to assess licensee awareness of actual risk conditions and mitigation strategies. The inspectors reviewed licensee compliance with 10 CFR 26 Nuclear Fatigue Rule through interviews with the site coordinator and reviews of 12 fatigue assessments and hours worked for 11 TVA employees and contractors.

Decay Heat Removal The inspectors reviewed licensee procedures 2-OI-74, Residual Heat Removal System (RHR); 2-OI-78, Fuel Pool Cooling and Cleanup System; and Abnormal Operating Instruction 0-AOI-72-1, Alternate Decay Heat Removal System Failures; and conducted a main control room panel and in-plant walkdowns of system and components to verify correct system alignment. During planned evolutions that resulted in an increased outage risk condition of Orange for shutdown cooling, inspectors verified that the plant conditions and systems identified in the risk mitigation strategy were available. In addition, the inspectors reviewed controls implemented to ensure that outage work was not impacting the ability of operators to operate spent fuel pool cooling, RHR shutdown cooling, and/or Alternate Decay Heat Removal (ADHR) system. Furthermore, the inspectors conducted several walkdowns of the ADHR system during operation with the fuel pool gates removed.

Critical Outage Activities The inspectors examined outage activities to verify that they were conducted in accordance with TS, licensee procedures, and the licensees outage risk control plan.

Some of the more significant inspection activities accomplished by the inspectors were as follows:

  • Walked down selected safety-related equipment clearance and associated with tagout numbers.

o 2-071-0010C, 2-071-0012A, 2-071-0013, 2-071-0023D, 2-071-0029A, 2-071-0035; Reactor Core Isolation Cooling System o 2-073-0011A, 2-073-0012B, 2-073-0024, 2-073-0026; High Pressure Coolant Injection System o 2-074-0027; Residual Heat Removal System o 2-075-0003A; Core Spray System o 2-074-0018; Residual Heat Removal System o 2-075-0018B; Core Spray System o 2-075-0020; Core Spray System

  • Verified Reactor Coolant System (RCS) inventory controls, especially during evolutions involving operations with the potential to drain the reactor vessel (OPDRV) controlled per 2-POI-200.5
  • Verified electrical systems availability and alignment
  • Monitored important control room plant parameters (e.g., RCS pressure, level, flow, and temperature) and TS compliance during the various shutdown modes of operation, and mode transitions
  • Evaluated implementation of reactivity controls
  • Reviewed control of containment penetrations and overall integrity
  • Examined foreign material exclusion controls particularly in proximity to and around the reactor cavity, equipment pit, and spent fuel pool
  • Routine tours of the control room, reactor building, refueling floor and drywell Reactor Vessel Disassembly and Refueling Activities The inspectors witnessed selected activities associated with reactor vessel reassembly, and reactor cavity flood-up in accordance with 2-GOI-100-3A, Refueling Operations (Reactor Vessel Disassembly and Floodup). Also, the inspectors witnessed fuel handling operations during the two Unit 2 reactor core fuel shuffles performed in accordance with TS and applicable operating procedures, such as 0-GOI-100-3A, Refueling Operations (In Vessel), 0-GOI-100-3B, Operations in the Spent Fuel Pool, and 0-GOI-100-3C, Fuel Movement Operations During Refueling. The inspectors verified specific fuel movements as delineated by the Fuel Assembly Transfer Sheets (FATF).

Furthermore, the inspectors also witnessed and examined the video verification of the final completed reactor core conducted per Attachment 6, of 0-GOI-100-3C.

Drywell Closeout On May 1 and 2, the inspectors reviewed the licensees conduct of 2-GOI-200-2, Drywell Closeout, and performed an independent detailed closeout inspection of the Unit 2 drywell.

Restart Activities The inspectors specifically conducted the following:

  • Reviewed and verified completion of selected items of 0-TI-270, Refueling Test Program, Attachment 2, Startup Review Checklist
  • Witnessed Unit 2 approach to criticality and power ascension per 2-GOI-100-1A, Unit Startup, and 2-GOI-100-12, Power Maneuvering
  • Reactor Coolant Heatup/Pressurization to Rated Temperature and Pressure per 2-SR-3.4.9.1, Reactor Heatup and Cooldown Rate Monitoring Corrective Action Program The inspectors reviewed PERs generated during U2R17 and attended management review committee (MRC) meetings to verify that initiation thresholds, priorities, mode holds, operability concerns and significance levels were adequately addressed.

Resolution and implementation of corrective actions of several PERs were also reviewed for completeness.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors witnessed portions of, and/or reviewed completed test data for the following surveillance tests of risk-significant and/or safety-related systems to verify that the tests met Technical Specification surveillance requirements, UFSAR commitments, and in-service testing and licensee procedure requirements. The inspectors review confirmed whether the testing effectively demonstrated that the SSCs were operationally capable of performing their intended safety functions and fulfilled the intent of the associated surveillance requirement. This activity constituted eight inspection samples, three in-service, four routine tests, and one reactor coolant system leakage detection test.

In-Service Tests:

  • May 14, 2013, 3-SR-3.5.1.7, HPCI Main and Booster Pump Set Developed Head and Flow Rate Test at Rated Rx Pressure Routine Surveillance Tests:
  • June 1, 2013, 3-SR-3.8.1.1(3A), Diesel Generator 3A Monthly Operability Test Reactor Coolant System Leak Detection Tests:
  • June 17, 2013, 2-SR-3.4.4.1, Manual Calculation of Unidentified, Identified and Total Leakage

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

a. Inspection Scope

During the report period, the inspectors observed an Emergency Preparedness (EP) drill that contributed to the licensees Drill/Exercise Performance (DEP) and Emergency Response Organization (ERO) performance indicator (PI) measures on May 8, 2013, to identify any weaknesses and deficiencies in classification, notification, dose assessment and protective action recommendation (PAR) development activities. The inspectors observed emergency response operations in the simulated control room and certain Emergency Response Facilities to verify that event classification and notifications were done in accordance with EPIP-1, Emergency Classification Procedure and other applicable Emergency Plan Implementing Procedures. The inspectors also attended the post-drill critique to compare any inspector-observed weakness with those identified by the licensee in order to verify whether the licensee was properly identifying weaknesses.

This inspection activity satisfied one inspection sample for the Drill Evaluation of emergency preparedness.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Occupational Radiation Safety and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Control

a. Inspection Scope

Radiological Hazard Assessment The inspectors reviewed a number of radiological surveys, including those performed for airborne areas, of locations throughout the facility including the Unit 2 drywell, Unit 1, Unit 2, and Unit 3 reactor buildings, the turbine building, and the Independent Spent Fuel Storage Installation (ISFSI). The inspectors also walked down many of the same areas and select radioactive material storage locations with a survey instrument, evaluating material condition, postings, and radiological controls. The inspectors observed jobs in radiologically risk-significant areas including high radiation areas and areas with, or with the potential for, airborne activity.

The inspectors evaluated the surveys in relation to the identified hazards for sufficient detail and frequency.

Instructions to Workers During plant walk downs, the inspectors observed labeling and radiological controls on containers of radioactive material. The inspectors also reviewed radiation work permits (RWP) used for accessing high radiation areas and airborne areas, verifying that appropriate work control instructions and electronic dosimeter (ED)setpoints had been provided and to assess the communication of radiological control requirements to workers. The inspectors reviewed selected ED dose and dose rate alarms, to verify workers properly responded to the alarms and that the licensees review of the events was appropriate. The inspectors observed pre-job RWP briefings and health physics technician coverage of workers. The inspectors reviewed the various methods being used to notify workers of changing or changed radiological conditions.

Contamination and Radioactive Material Control The inspectors observed the release of potentially contaminated items from the radiologically controlled area (RCA) and from contaminated areas such as the drywell. The inspectors also reviewed the procedural requirements for, and equipment used to perform, the radiation surveys for release of personnel and materiel. During plant walk downs, the inspectors evaluated radioactive material storage areas and containers, including satellite RCAs, assessing material condition, posting/labeling, and control of materials/areas. In addition, the inspectors reviewed the sealed source inventory and verified labeling, storage conditions, and leak testing of selected sources. The inspectors verified if Category 1 and 2 sealed sources had been appropriately reported to the National Source Tracking System and physically verified the presence and controls of these sources. The sources were verified to be physically present and in proper working order.

Radiological Hazards Control and Work Coverage The inspectors evaluated licensee performance in controlling worker access to radiologically significant areas and monitoring jobs in-progress associated with the Unit 2 refueling outage. Established radiological controls were evaluated for selected tasks including control rod drive removal and reinstallation activities, radioactive waste processing, fuel handling, and closeout inspections for Unit 1 restart. The inspectors evaluated the effectiveness of radiation exposure controls, including air sampling, barrier integrity, engineering controls, and postings through a review of both internal and external exposure results.

During walk downs with a radiation survey meter, the inspectors independently verified if ambient radiological conditions were consistent with licensee performed surveys, RWPs, and pre-job briefings; observed the adequacy of radiological controls; and observed controls for radioactive materials stored in the spent fuel pool. ED alarm set points and worker stay times were evaluated against area radiation survey results for drywell and refueling floor activities. The inspector did an independent radiological survey of the Browns Ferry ISFSI installation.

Risk-Significant High Radiation Area and Very High Radiation Area Controls The inspectors discussed the controls and procedures for locked-high radiation areas (LHRAs) and very high radiation areas (VHRAs) with health physics supervisors and the radiation protection manager. During plant walk downs, the inspectors verified the posting/locking of LHRA/VHRA areas.

Radiation Worker Performance and Radiation Protection Technician Proficiency-The inspectors observed radiation worker performance through direct observation, via remote camera monitoring, and via telemetry. These jobs were performed in high radiation, airborne, and/or contaminated areas. The inspectors also observed health physics technicians providing field coverage of jobs and providing remote coverage.

Problem Identification & Resolution - Licensee Corrective Action Program (CAP)documents associated with radiation monitoring and exposure control were reviewed and assessed. This included review of selected Problem Evaluation Reports (PERs)related to radworker and health physics technician performance. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure NPG-SPP-3.1, Corrective Action Program, Revision 5. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results. Documents reviewed are listed in the Attachment.

Radiation protection activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 12; TS Sections 5.4 and 5.7; 10 Code of Federal Regulations (CFR) Parts 19 and 20; and approved licensee procedures.

Radiological control activities for ISFSI areas were evaluated against 10 CFR Part 20, 10 CFR Part 72, and TS details. Documents reviewed are listed in the Attachment.

The inspectors completed 1 sample, as described in Inspection Procedure (IP)71124.01.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

Radiological Work Planning Inspectors evaluated As Low As Reasonably Achievable (ALARA) program guidance and implementation for ongoing tasks associated with U2R17. Inspectors also evaluated tasks and review of post-outage ALARA activities associated with U3R15 refueling outage. A list was obtained from the licensee of work activities for their current outage. Inspectors selected four work activities to evaluate the ALARA Plan and associated documentation for jobs, including under-vessel maintenance; refuel floor maintenance activities, disassembly and refurbishing of Reactor Water Cleanup (RWCU) system isolation valve 2-FCV-069-0001, and other valve work activities. Inspectors evaluated dose mitigation features, dose goals and other factors that went into planning the dose goal for each task, including the review of TEDE ALARA evaluations for the decrease of worker efficiency from the use of respiratory protective devices. Selected RWPs were reviewed by inspectors to verify the integration of ALARA requirements into the documents for worker instruction. Inspectors followed the progression of available work activities to compare dose rates accrued and work evolution to the ALARA planning. Since inspectors were not at the site through the end of the outage, post job reviews from the previous U3R15 outage were reviewed.

Verification of Dose Estimates and Exposure Tracking Systems Three ALARA work packages and the assumptions and basis for the current collective exposure estimates were reviewed by inspectors. The inspectors reviewed ALARA procedures, had discussions with ALARA personnel, reviewed daily exposure graphs and outage reports that tracked and trended the dose of ongoing work, and reviewed monthly Station ALARA Committee Meeting Minutes. The use of Work-In-Progress reviews for ALARA trigger points were also evaluated by the inspectors.

Source Term Reduction and Radiation Worker Performance The inspectors evaluated source term reduction methods through the review of licensee documents and records, and discussions with ALARA personnel. Inspectors reviewed actions already executed by the licensee to reduce source term, including replacing various plant components with Stellite free components, performing ultrasonic cleaning on fuel bundles, electro-polishing of various valves, pumps, and piping, and utilizing the Radiation Protection Closed Circuit Television (CCTV) Remote Monitoring System. The inspectors also reviewed future plans for source reduction, including the reduction of hotspots and soluble cobalt concentrations, and the use of permanent shielding.

The inspectors observed radiation worker performance through CCTV remote monitoring and direct observations. This included Control Rod Drive (CRD) removals, a PSC Head Tank hotspot flush, and the attendance of ALARA, High Radiation Area (HRA), and pre-job briefs.

Problem Identification and Resolution The inspectors reviewed licensee corrective action documents associated with ALARA planning and controls. This included review of selected Problem Evaluation Reports (PERs) and self-assessments. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure NPG-SPP-3.1 Revision 5. Radiation worker performance was evaluated against the requirements found in TS Sections 5.4 and 5.7; Title 10 Code of Federal Regulations (CFR) Parts 19 and 20; and approved licensee procedures. Documents reviewed are listed in the Attachment.

The inspectors completed 1 sample, as described in Inspection Procedure (IP)71124.02.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls The inspectors reviewed the use of temporary and permanent engineering controls to mitigate airborne radioactivity during refueling outage U2R17. In addition, during observations of jobs in-progress and containment walk-downs, inspectors observed the placement and use of HEPA negative pressure units, and air sampling equipment.

Use of Respiratory Protection Devices & Self-Contained Breathing Apparatus for Emergency Use Inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material, including devices used for routine tasks and devices stored for use in emergency situations. Inspectors observed the physical condition of Self-Contained Breathing Apparatus (SCBA) units, negative pressure respirators (NPRs), powered air purifying respirators (PAPRs) and device components staged for routine and emergency use throughout the plant. SCBA bottle air pressure, the number of units, and the number of spare masks and air bottles available was also evaluated by inspectors. The inspectors reviewed maintenance records for selected SCBA units for the past year and evaluated SCBA and NPR compliance with National Institute for Occupational Safety and Health certification requirements. The inspectors also reviewed records of Grade D (or better) air quality testing for supplied-air devices and SCBA bottles. The inspectors reviewed the status and surveillance records of SCBAs staged for in-plant use during emergencies through review of records and walk-down of SCBA staged in the control room and selected locations.

The inspectors verified the licensee had procedures in place to ensure that the use of respiratory protection devices was ALARA when engineering controls were not practicable. Control room operators and fire brigade were interviewed on the use of the devices including SCBA bottle change-out and use of corrective lens inserts. In addition, qualifications for individuals responsible for testing and repairing SCBA vital components were evaluated through review of training records. Selected maintenance records for SCBA units and air cylinder hydrostatic testing documentation were reviewed.

The inspectors verified that the licensee has procedural requirements in place for evaluating air samples for the presence of alpha emitters and reviewed airborne radioactivity and contamination survey records for selected plant areas to ensure air samples are screened and evaluated per the procedure requirements.

The inspectors walked-down the respirator issue and storage locations and verified that the equipment was appropriately stored and maintained. Records of monthly and quarterly inventory and inspection of the equipment were also reviewed by the inspectors. The inspectors discussed the process for issuing respirators, and verified that selected individuals qualified for respirator and/or self-contained breathing apparatus (SCBA) use had completed the required training, fit-test, and medical evaluation.

Problem Identification and Resolution Licensee CAP documents associated with the control and mitigation of in-plant radioactivity were reviewed and assessed. This included review of selected SRs related to use of respiratory protection devices including SCBA. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure NPG-SPP-03.1, Corrective Action Program, Revision 5. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results. Documents reviewed are listed in the Attachment.

Radiation protection activities were evaluated against the requirements specified in 10 CFR Parts 19 and 20; and approved licensee procedures. Documents reviewed are listed in the Attachment.

The inspectors completed all specified line-items detailed in IP 71124.03 (sample size of 1).

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 and discussed program guidance for storage, processing, and evaluation of results for active and passive personnel dosimeters currently in use. Comparisons between Electronic Dosimeter (ED) and Thermo Luminescent Dosimeter (TLD) data were discussed in detail. The inspectors reviewed ED alarm logs and reviewed licensees dosimeter incident reports and assessment actions for selected alarm events.

Internal Dosimetry: Program guidance and assessment results for internally deposited radionuclides were reviewed. The inspectors reviewed selected Whole Body Count (in vivo) analyses from January 2012 to March 2013. Capabilities for collection and analysis of special bioassay samples were discussed with licensee staff, there were no dose assessments based on biological samples to review.

Special Dosimetric Situations: The inspectors evaluated the licensees use of multi-badging, extremity dosimetry, and dosimeter relocation within non-uniform dose rate fields and reviewed assessments. Worker monitoring in neutron areas was discussed with licensee staff. The inspectors also reviewed records of monitoring for declared pregnant workers from September 2011 to March 2013 and discussed monitoring guidance with dosimetry staff. In addition, shallow dose assessments for selected Personnel Contamination Events occurring between September 2011 and March 2013 were reviewed and discussed.

Problem Identification and Resolution: The inspectors reviewed and discussed selected Corrective Action Program (CAP) documents associated with occupational dose assessment. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure NPG-SPP-03.1, Corrective Action Program, Rev.

5. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

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

The inspectors completed 1 sample as required by IP 71124.04.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors reviewed the licensees radiation monitoring instrumentation programs to verify the accuracy and operability of radiation monitoring instruments used to monitor areas, materials, and workers to ensure a radiologically safe work environment and to detect and quantify radioactive process streams and effluent releases.

Walkdowns and Observations: The inspectors walked down effluent and process monitoring systems, including the Main Stack Radiation Monitoring System (0-RE-90-147 and 148), Unit 1 and (U1 and U2) Reactor Building Vent Exhaust (1-RM-249 and 250), and Liquid Radwaste Monitor (0-RE-90-130), evaluating material condition and verifying configurations were consistent with Offsite Dose Calculation Manual (ODCM)descriptions. The inspectors also evaluated the material condition and location of area radiation monitors (ARMs) 1-RE-90-1, 2-RE-90-4, 2-RE-90-17, and continuous air monitors. For selected effluent monitors and ARMs, the inspectors verified in-field responses were consistent with readings obtained in the control room.

During plant tours and observations in the calibration lab, the inspectors assessed material condition and operability of portable survey instruments in addition to verifying calibration and source checks were current. The inspectors reviewed records of survey instrument function/source checks and observed and discussed performance of required checks with calibration lab personnel. Material condition of source check devices, device operation, and establishment of source check acceptance range were also discussed with calibration lab personnel.

The inspectors evaluated material condition and observed performance of source checks on personal contamination monitors and small article monitors located at the RCA exit and discussed differences in source check geometries for portal monitors located at the protected area exit.

Calibration and Testing Program: The inspectors reviewed the last two calibration records for the following effluent, process, area radiation, and post-accident monitors:

2-RM-90-250 (Unit 2 Reactor Building Vent Exhaust), 1-RM-90-272A and 273A (Unit 1 Containment High Range Radiation Monitors), 0-RE-90-130 (Liquid Radwaste Monitor),and 0-RE-90-147/148 (Main Stack). In addition to evaluating the calibration procedures, calibration geometry, functional tests, and calibration sources, the inspectors verified monitor set-points were consistent with and/or changed in accordance with ODCM and/or site procedures.

Instrumentation used in the chemistry and health physics counting rooms was evaluated for material condition, operability, and use. Daily background and quality control charts for select high-purity germanium spectroscopy, low background counting systems, and alpha counting systems were reviewed. The inspectors also reviewed the cross-check analysis results for several quarters of calendar year 2011 and 2012.

For the whole body counter, the inspectors reviewed the most recent calibration, assessed the isotope library, reviewed and discussed performance of daily quality control (QC) checks, and verified appropriate check and calibration sources were used.

In addition, the inspectors reviewed calibrations of, and observed performance of source checks on select portal monitor, personnel monitor, and small article monitor equipment.

Documents reviewed are listed in the Attachment.

The inspectors reviewed performance of the portable instrument calibration lab through review and discussion of instrument calibrations, direct observation of source and response checks, review of instrument calibration records, assessment of the established source check ranges of the Shepherd calibrator (geometry, sources, etc.),

and review of the annual recertification of the Western Area Radiological Laboratory (WARL) high level gamma well calibrator. Portable instrument calibration records review included three ion chamber instruments, two neutron instruments, four low volume air samplers, and three friskers.

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; UFSAR Chapters 7 and 13; TS Sections 3.3.3.1, Post Accident Monitoring, 3.3.6.2, Secondary Containment Isolation Instrumentation, 5.4, Procedures, and 5.5 Programs and Manuals; and applicable licensee procedures.

Document reviewed are listed in the Attachment.

Problem Identification and Resolution: Selected corrective action program documents associated with radiation monitoring instruments, including condition reports and audits, were reviewed and assessed. This review of corrective action documents included evaluating the licensees response to indications of degraded count room instrument performance. The inspectors verified that problems were being identified at an appropriate threshold and resolved in accordance with procedures NPG-SPP-03.1, Corrective Action Program.

The inspectors completed the specified line-item samples detailed in Inspection Procedure (IP) 71124.05. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

.1 Cornerstone: Mitigating Systems

Mitigating Systems Performance Indicator (MSPI)- Heat Removal (Reactor Core Isolation Cooling and High Pressure Coolant Injection)

a. Inspection Scope

The inspectors reviewed the licensees procedures and methods for compiling and reporting the following Performance Indicators (PIs), including procedure NPG-SPP-02.2 Performance Indicator Program. The inspectors examined the licensees PI data for the specific PIs listed below for the second quarter 2012 through first quarter of 2013. The inspectors reviewed the licensees data and graphical representations as reported to the NRC to verify that the data was correctly reported. The inspectors also validated this data against relevant licensee records (e.g., PERs, Daily Operator Logs, Plan of the Day, Licensee Event Reports, etc.), and assessed any reported problems regarding implementation of the PI program. Furthermore, the inspectors met with responsible plant personnel to discuss and go over licensee records to verify that the PI data was appropriately captured, calculated correctly, and discrepancies resolved. The inspectors also used the Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, to ensure that industry reporting guidelines were appropriately applied. This activity constituted six mitigating systems performance indicator inspection samples.

b. Findings

One finding is documented as a licensee identified violation in Section 4OA7.

.2 Radiation Protection

a. Inspection Scope

Occupational Radiation Safety Cornerstone: The inspectors reviewed Performance Indicator (PI) data collected from April 14, 2012, through May 1, 2013, for the Occupational Exposure Control Effectiveness PI. For the reviewed period, the inspectors assessed PER 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 inspectors reviewed radiologically controlled area exit transactions with exposures greater than 100 mrem to determine if they were consistent with the requirements of the RWP. The reviewed data were assessed against guidance contained in Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Indicator Guideline," Rev. 6. Documents reviewed are listed in the Attachment.

Public Radiation Safety Cornerstone: The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from June 22, 2012, through March 1, 2013. For the assessment period, the inspectors reviewed cumulative and projected doses to the public and PER documents related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Review of items entered into the Corrective Action Program:

As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished by reviewing daily PER and Service Request (SR) reports, and periodically attending Corrective Action Review Board (CARB) and PER Screening Committee (PSC) meetings.

.2 Annual Follow-up of Selected Issues - Operator Aids and Permanent Information

Postings

a. Inspection Scope

The inspectors reviewed the deficiencies from an audit of operator aids (OAs) and permanent information postings (PIPs) conducted in May 2011. The audit was one of the corrective actions associated with PER 344224, which addressed that an audit of OAs and PIPs had not been performed since October 2004. Procedure 0-TI-414, Component Labeling, Signs, Operator Aids, and Permanent Information Postings, requires an audit to be performed every 24 months. In addition to directing the performance of the audit, the PER captured the need to documentation of any deficiencies and schedule a subsequent audit by May 2013. The audit was completed in May 2011. The inspectors reviewed the results of the audit and did a sampling of the identified deficiencies to verify the deficiencies had been corrected. The inspectors also verified that the audit scheduled for May 2013 had been conducted and reviewed the results. The inspectors verified the deficiencies identified from the May 2013 audit have been entered into the corrective action program. This activity constituted one in-depth selected issue. Documents reviewed are listed in the Attachment.

b. Findings and Observations

No findings were identified. However, the inspectors had the following observations:

PER 344224 The PER addressed the failure to perform an audit of operator aids (OAs) and permanent information postings (PIPs). The corrective actions included completing the audit, identifying any deficiencies with the OAs /PIPs, and scheduling a subsequent audit within two years of the previous audit. The inspectors performed a walkdown of twenty-four OAs / PIPs from the list of deficiencies identified during the 2011 audit to verify the deficiencies had been addressed. Of the OAs/PIPs sampled, one PIP had not been installed and another PIP was unmounted laying on a piece of equipment approximately 10 feet from its associated component. A review of the recent audit, completed in May 2013, determined that while this audit identified several deficiencies it failed to identify either the missing PIP or the improperly mounted PIP identified during the inspectors walkdown. The information was provided to the licensee who entered the issue into the corrective action program and took immediate actions to correct the deficiencies identified during the inspectors walkdown.

.3 Semiannual Review to Identify Trends

a. Inspection Scope

As required by Inspection Procedure 71152, the inspectors performed a review of the licensees corrective action program (CAP) implementation and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review included the results from daily screening of individual PERs (see Section 4OA2.1 above), licensee trend reports and trending efforts, and independent searches of the PER database and WO history. The inspectors review nominally considered the six-month period of January 2013 through June 2013, although some searches expanded beyond these dates. Additionally, the inspectors review also included the Integrated Trend Reports (ITR) from October 1, 2012, to March 31, 2013.

Furthermore, the inspectors verified that adverse or negative trends identified in the licensees PERs, periodic reports and trending efforts were entered into the CAP.

Inspectors interviewed the appropriate licensee staff and also reviewed procedures, NPG-SPP-02.7, PER Trending and NPG-SPP-02.8, Integrated Trend Review.

The purpose of the licensees integrated trend reviews was to identify the top site and departmental issues (gaps to excellence) requiring management attention. Other objectives were to provide status of the top issues and their progress to resolution, identify continuing issues, emerging trends and issues to be monitored, review progress towards resolving past top issues, review issues identified by external organizations such as the NRC, Nuclear Safety Review Board (NSRB), Quality Assurance, etc., and determine why they were not identified by line organizations.

In addition to reviewing the sites progress on the above issues, the inspectors conducted an independent review of the licensees CAP to independently identify potential adverse trends.

b. Findings and Observations

No findings were identified. However, the inspectors had the following observations discussed below:

Inspectors noted licensee-identified issues and trends in both the first and second quarter trend reports. The licensee continued to trend weaknesses related to human performance. This issue was identified as site wide and was a major area of concern to the site. The licensee developed a performance improvement plan and actions were initiated to eliminate the performance gap in this area.

Inspectors continue to see increased focus and improvement on the licensees trending efforts and trending related products. The stations departmental accountability in terms of responding to trending issues is slowly improving.

Inspectors identified three issues that were either not clearly identified or were not being trended by the licensees PI group.

Inspectors identified a potential adverse trend with the adequacy of briefings conducted to support complex infrequently performed tests or evolutions (CIPTE). The licensee initiated PER 746111 to address this trend. The following PERs were provided as data points support this trend:

  • PER 707725, Briefing for an operation with potential to drain the reactor vessel (OPDRV) for repair of 2-FCV-69-1.
  • PER 724721, CIPTE test director and manager not assigned in a timely manner.
  • PER 702110, Quality Assurance (QA) identified gaps in CIPTE brief for control rod (CR) exchange brief.
  • PER 702679, QA identified CIPTE issues during CR brief.

4OA3 Follow-up of Events

.1 (Closed) Licensee Event Report (LER) 05000296/2013-002-00; 05000296/2013-002-01,

Manual Actuation of Reactor Core Isolation Cooling (RCIC) System During Reactor Shutdown

a. Inspection Scope

The inspectors reviewed LER 05000296/2013-002-00 dated April 12, 2013 and revised LER 05000296/2013-002-01 dated June 7, 2013. Inspectors reviewed the information from the Root Cause Analysis for PER 710216 related to this event. The RCIC system was required due to a failure of the Reactor Feedwater recirculation piping separation which caused a loss of condenser vacuum. The Condensate System is currently in a(1)status for Maintenance Rule tracking. The corrective actions associated with the a(1)plan are being implemented to minimize future recurrences of this issue. The use of RCIC and the Safety Relief Valves to control reactor level and pressure during the planned shutdown and cooldown of the reactor was performed in accordance with Browns Ferry procedures. These LERs were closed.

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Reports (LER) 05000260/2012-003-00 and 05000260/2012-

003-01 Reactor Motor Operated Board Transfer Failure

a. Inspection Scope

The inspectors reviewed LERs 05000260/2012-003-00 dated September 17, 2012, and revised LER 05000260/2012-003-01 dated March 15, 2013. Inspectors reviewed the information from the Root Cause Analysis for PER 581478 related to this event. The cause of the Reactor Motor Operated Valve Board transfer failure was due to a failure to perform a post maintenance test which subsequently caused a manual trip pushbutton to remain stuck in the trip position. Corrective actions were to revise the maintenance test procedures with verification steps to ensure the trip pushbuttons had returned from the depressed position. One violation of regulatory requirements was identified and is discussed below. These LERs were closed.

b. Findings

Introduction:

A self-revealing Green non-cited violation (NCV) Technical Specifications (TS) Limiting Conditions for Operation (LCO) 3.5.1, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) System was identified associated with the licensees failure to perform a post maintenance test (PMT) which rendered an ECCS injection subsystem power supply inoperable for greater than TS allowed outage time.

Description:

On July 19, 2012, while Operations personnel were performing a manual transfer of the Browns Ferry Unit 2, 480V RMOV board 2E to its alternate power supply, the alternate feeder breaker failed to close. Operations personnel found the manual trip pushbutton in the depressed position. Section 3.2.2 A.1 of procedure NPG-SPP-06.3, Pre-/Post Maintenance Testing required, in part, post maintenance testing (PMT) to be sufficiently comprehensive to ensure that the maintenance performed does not adversely affect the equipments ability to perform its intended function, and that no new or related problems were created by the maintenance activity. The licensee failed to perform a PMT to test the Unit 2 2E 480V RMOV Board alternate feeder breaker on July 10, 2012. As a result, the breaker was left in a tripped condition and unable to close when the 2E RMOV board was returned to operable status. It was subsequently discovered, nine days later, that the trip push button was stuck during a manual transfer attempt from the normal power source to the alternate power source on July 19, 2012.

Analysis:

Failure to perform a post maintenance test before returning the 2E 480V RMOV board to operable status as required by licensee procedure NPG-SPP-06.3, Pre-

/Post Maintenance Testing was a performance deficiency. This finding was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone objective and adversely affected the cornerstone objective to ensure availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the Unit 2 2E 480V RMOV Board alternate feeder breaker was left in a tripped condition and unable to close for nine days. The significance of this finding was evaluated using Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings and IMC 0609, Appendix A of the Significance Determination Process (SDP)

The issue was screened using IMC 0609, Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, and was determined to be a Green finding because it did not represent an actual loss of function of one or more non-Technical Specification Trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The cause of this finding was directly related to the cross-cutting aspect of appropriate oversight of work activities in the Work Practices component of the Human Performance area because maintenance work activities for the alternate feeder breaker for the 2E 480V RMOV board did not include a check to ensure the breaker nuclear safety function was supported, H.4(c).

Enforcement:

Technical Specifications(TS) 3.5.1, Emergency Core Cooling Systems (ECCS) and Reactor Core Isolation Cooling (RCIC) System required, in part, that while the plant is in Mode 1, 2 and 3, each ECCS injection/spray subsystem shall be OPERABLE. The TS ACTION statement requires that with One low pressure ECCS injection/spray subsystem inoperable, restore low pressure ECCS injection/spray subsystem(s) to OPERABLE status within seven days or be Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Mode 4 within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Contrary to the above, while the Unit was in Mode 1, from July 10 until July 19, 2012, division 2 of low pressure ECCS was inoperable due to the Unit 2, 480V RMOV board 2E being unable to perform its intended transfer function as described in Technical Specification Surveillance Requirement 3.5.1.12 and action was not taken to either restore the system to operable status within seven days or place the unit in Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in Mode 4 within the following 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This issue was captured in the licensees corrective action program as PER 581478. The failed alternate feeder breaker to the Unit 2 2E 480V RMOV Board trip pushbutton was restored to the proper condition on July 19, 2012, at 0303. This violation was applicable to Unit 2 and is identified as NCV 05000260/2013003-01, Failure to Perform Post Maintenance Testing on the 2E 480V RMOV board.

.3 (Discussed) Licensee Event Report (LER) 05000296/2013-003-00, Automatic Reactor

Shutdown Due to an Actuation of the Reactor Protection System from a Turbine Trip.

Licensee Event Report (LER) 05000259/2013-002-00, Manual Reactor Shutdown Due to Decreasing Condenser Vacuum

a. Inspection Scope

On February 25, 2013 at 1313 hours0.0152 days <br />0.365 hours <br />0.00217 weeks <br />4.995965e-4 months <br />, Unit 3 automatically scrammed due to a turbine trip. The turbine trip was caused by low condenser vacuum as a result of a failure of a long cycle return line piping connection to the miscellaneous drain header. The licensee initiated PER 687732 to enter the event into the corrective action program. Inspectors reviewed LER 05000296/2013-003-00 and all associated documentation which included the Root Cause Analysis (RCA) for PER 687732. This LER was Open.

On March 19, 2013 at approximately 0402 hours0.00465 days <br />0.112 hours <br />6.646825e-4 weeks <br />1.52961e-4 months <br />, Unit 1 was manually scrammed due to decreasing main condenser vacuum. The degrading condenser vacuum was caused by the failure of a vent and drain pipe joint to a miscellaneous drain header which connected to the main condenser. The licensee initiated PER 698870 to enter the event into the corrective action program. Inspectors reviewed event report LER 05000259/2013-002-00 and all associated documentation which included the Root Cause Analysis (RCA) for PER 698870. The direct cause of the event was attributed to cyclic fatigue of the drain piping to header connection. The root cause was attributed to upstream valve leakage and the stations failure to consider and address the possible failure of the piping due to the valve leakby. This LER was open.

b. Findings

Introduction:

Unresolved Item (URI). A self-revealing issue of concern was identified with the Unit 3 automatic reactor shutdown due to the turbine trip from loss of condenser vacuum on February 25, 2013 and the Unit 1 manual reactor shutdown due to a decreasing vacuum manual scram on March 19, 2013.

Description:

On February 25, 2013, Unit 3 was operating at approximately 92 percent power following a forced midcycle outage for repairs on the condenser circulating water (CCW) system. At 1313 hours0.0152 days <br />0.365 hours <br />0.00217 weeks <br />4.995965e-4 months <br /> the unit automatically scrammed due to a turbine trip.

The turbine trip was caused by low condenser vacuum as a result of a failure of a long cycle return line piping connection to the miscellaneous drain header which connects with the main condenser. Main steam isolation valves (MSIVs) were manually closed and main turbine bypass valves were unavailable due to the loss of condenser vacuum.

During the transient all available mitigating equipment performed as designed. The licensee initiated PER 687732 to enter the event into the corrective action program.

Licensee investigation revealed the failure of a feedwater long cycle return line connection to the miscellaneous drain header was a result of seat leakage from the reactor feedwater system long cycle return flow control valves (3-FCV-003-0071, 72, and 73). This seat leakage caused the water within the pipe to flash to steam which translated to excessive vibration on the pipe and resulted in fatigue failure of the connection between the 8 inch pipe and 24 inch miscellaneous drain header.

On March 19, 2013, Unit 1 was operating at approximately 80 percent power. At 0402 hours0.00465 days <br />0.112 hours <br />6.646825e-4 weeks <br />1.52961e-4 months <br /> the unit was manually scrammed due to decreasing main condenser vacuum.

Following the manual scram condenser vacuum recovered and all available mitigating equipment was available and performed as designed.

The vacuum degradation was caused by the separation of a 4 inch vent and drain pipe from a 24 inch miscellaneous drain header which connected to the main condenser.

The separation was caused by vibration induced cyclic fatigue as a result of the combination of leaking drain valves and repeated operation of dump valves associated with feedwater heaters. The licensee initiated PER 698870 to enter the event into the corrective action program.

Additional inspection of the maintenance history, service requests (SRs), problem evaluation reports (PERs), cause analyses and mitigating system responses concerning these two reactor trips are required to provide additional information into the issue. This unresolved item was tracked as URI 05000259, 260, 296/2013003-02.

.4 (Closed) Licensee Event Report (LER) 05000259/2010-001-01, Unit 1, 2, and 3

Appendix R Safe Shutdown Instruction Procedures Contain Incorrect Operator Manual Actions (Closed) Licensee Event Report (LER) 05000259/2012-001-01, Unanalyzed Conditions Discovered During NFPA 805 Transition Review (Closed) Licensee Event Report (LER) 05000259/2012-002-01, Fault Propagation During a Postulated Appendix R Event Could Result in an Inability to Close Motor Operator Valves (Closed) Licensee Event Report (LER) 05000259/2012-003-01: Reactor Protection System Circuit Could Potentially Remain Energized During An Appendix R Fire

a. Inspection Scope

On December 26, 2012, the licensee submitted revisions to the subject LERs to reflect that conditions that were originally submitted are not considered as safety system functional failures, as described in NEI 99-02, Regulatory Assessment Performance Indicator Guidelines. The regulatory aspects of LER 2010-001-01 were reviewed and documented in NRC Inspection report 05000259, 260, 296/2012-007. Similarly, the regulatory aspects of LERs 2012-001-01, 2012-002-01, and 2012-003-01 were reviewed and documented in NRC Inspection Report 05000259, 260, 296/2012-004.

Inspectors reviewed the subject LERs to determine if the facts supporting the original LER reviews were still applicable, and that no new conditions that had not been reviewed by the NRC were associated with this revision. Inspectors also reviewed NEI 99-02 to verify the licensees basis for determining that these conditions were not safety system functional failures was consistent with the guidance in NEI 99-02.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Temporary Instruction (TI) -2515/182 - Review of the Implementation of the Industry

Initiative to Control Degradation of Underground Piping and Tanks, Phase 1

a. Inspection Scope

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

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

b. Observations The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraphs 03.01.a through 03.01.c of TI-2515/182 and was found to meet all applicable aspects of NEI 09-14 Revision 1, as set forth in Table 1 of the TI.

Based upon the scope of the review described above, Phase I of TI-2515/182 was completed.

c. Findings

No findings were identified.

.2 Independent Spent Fuel Storage Installation (ISFSI) Change Evaluations.

a. Inspection Scope

Under the guidance of IP 60857, the inspectors reviewed the licensees evaluations of the changes to the Independent Spent Fuel Storage Installation (ISFSI) in accordance with 10 CFR 72.48, Changes, Tests, and Experiments, as well as the licensees procedure for implementing 72.48 evaluations. The review focused on the changes that were implemented since the last inspection. The review determined that the evaluations were consistent with the requirements of 10 CFR 72.48 and the evaluations were documented in accordance with NPG-SPP-09.9, 10 CFR 72.48 Evaluations of Changes, Tests and Experiments for Independent Spent Fuel Storage Installation. The inspectors also reviewed the changes to10CFR72.212, Report of Evaluations since the last inspection.

b. Findings

No findings were identified.

.3 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.

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.

4OA6 Meetings, Including Exit

.1 Exit Meeting Summary

On April 12, 2013, the health physics inspectors discussed results of the onsite radiation protection inspections with Mr. Phil Summers, Director of Safety & Licensing, and other responsible staff. The inspectors noted that one proprietary document was reviewed during the course of the inspection that would be properly disposed of when no longer needed.

On May 31, 2013, an exit meeting was conducted by phone with Steve Norris, Component Engineering Manager, members of the buried pipe program and licensee staff. The inspectors verified that all proprietary information was returned to the licensee.

On July 9 and August 5, 2013, the resident inspectors presented the quarterly inspection results to Mr. Keith Polson, Site Vice President, and other members of the licensees staff, who acknowledged the findings.

4OA7 Licensee-Identified Violations

The following Severity Level IV violation was identified by the licensee and is a violation of NRC requirements which met the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-Cited Violation.

The licensee identified a violation of Title 10 CFR Part 50.9(a), Completeness and Accuracy of Information, which required, in part, that information provided to the NRC by all licensees be complete and accurate in all material respects. Contrary to the above, on January 21, 2013, the licensee failed to provide to the NRC fourth quarter 2012 performance indicator data for the Unit 2 MSPI - emergency AC power systems that were complete and accurate in all material respects. Specifically, the licensee failed to include the December 2012 failure of D EDG as an MSPI run failure. Once the information was corrected, the Unit 2 MSPI performance indicator changed from Green to White. This violation was characterized as a Severity Level IV non-cited violation, consistent with Example 6.9.d.11 of the Enforcement Policy. The violation was entered into the licensees corrective action program as PERs 704392, 669462, and 740285.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Austin, Licensing Engineer
E. Bates, Licensing Engineer
A. Bolduc, I&C Supervisor
T. Cagle-Jaudon, RP Supervisor - Instruments
P. Campbell, System Engineer
J. Covey, Radiation Protection - ALARA
S. Cowan, Superintendant Radiation Protection Operations
D. Drummonds, Underground and Buried Piping Program Owner
M. Ellet, BFN Maintenance Rule Engineer
J. Emens, Site Licensing Manager
J. Ferguson, Radiation Protection Manager
M. Floyd, Nuclear Fatigue Rule Manager
R. Givens, Senior Reactor Operator
D. Green, Licensing Contractor
J. Guthrie, System Engineer
P. Hermann, Technical Consultant, Licensing
L. Hughes, Manager Operations
S. Jeffers, Radiation Protection - Dosimetry
J. Lacasse, System Engineer
B. McNutt, Shift Manager
T. Mingus, Engineering
S. Norris, Components Mgr.
J. Oates, System Engineer - I&C
M. Oliver, Licensing Engineer
K. Polson, Site Vice President
B. Rinne, Components Engineer
M. Roy, System Engineer
J. Solley, I&C Supervisor
P. Summers, Director of Safety and Licensing
S. Wentzel, System Engineer
A. Yarborough, System Engineer

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened

05000259, 260, 296/2013003-02 URI LER
05000296/2013-003-00 (Section 4OA3.3) and
05000259/2013-002-00 (Section 4OA3.3)
05000260/2013003-03 URI Residual Heat Removal (RHR) Heat Exchanger (HX) excessive fouling (1R15.2)

Opened and Closed

05000259, 260, 296/2013002-01 NCV Failure to Implement Preventive Maintenance Program (Section 1R15.1)
05000260/2013003-01 NCV Failure to perform Post Maintenance Testing on the 2E 480V RMOV board (Section 4OA3.2)

Closed

05000296/2013-002-00 LER Manual Actuation of Reactor Core Isolation Cooling (RCIC) System During Reactor Shutdown (Section 4OA3.1)
05000296/2013-002-01 LER Manual Actuation of Reactor Core Isolation Cooling (RCIC) System During Reactor Shutdown (Section 4OA3.1)
05000260/2012-003-00 LER Reactor Motor Operated Valve Board transfer Failure (Section 4OA3.2)
05000260/2012-003-01 LER Reactor Motor Operated Valve Board transfer Failure (Section 4OA3.2)
05000259, 260, 296/2010-001-01 LER Unit 1, 2, and 3 Appendix R Safe Shutdown Instruction Procedures Contain Incorrect Operator Manual Actions (Section 4OA3.4)
05000259, 260, 296/2012-001-01 LER Unanalyzed Conditions Discovered During NFPA 805 Transition Review (Section 4OA3.4)
05000259, 260, 296/2012-002-01 LER Fault Propagation During a Postulated Appendix R Event Could Result in an Inability to Close Motor Operator Valves (Section 4OA3.4)
05000259, 260, 296/2012-003-01 LER Reactor Protection System Circuit Could Potentially Remain Energized During An Appendix R Fire (Section 4OA3.4)
05000259, 260, 296/2013002-01 AV Failure to Implement Preventive Maintenance Program, (Section 1R15.1)

Discussed

05000296/2013-003-00 LER Automatic Reactor Shutdown Due to an Actuation of the Reactor Protection System from a Turbine Trip (Section 4OA3.3)
05000259/2013-002-00 LER Manual Reactor Shutdown Due to Decreasing Vacuum (Section 4OA3.3)

LIST OF DOCUMENTS REVIEWED

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