IR 05000458/2012004

IR 05000458-12-004; 07/01/2012 - 09/30/2012; River Bend Station; Integrated Resident and Regional Report; Equipment Alignment; Operability Evaluations and Functionality Assessments; Post-Maintenance Testing

ML12318A212
Person / Time
Site:	River Bend
Issue date:	11/13/2012
From:	Hagar R NRC/RGN-IV/DRP/RPB-C
To:	Olson E Entergy Operations
References
IR-12-004
Download: ML12318A212 (46)

Text

November 13, 2012

SUBJECT:

RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT 05000458/2012004

Dear Mr. Olson:

On September 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your River Bend Station. The enclosed inspection report documents the inspection results which were discussed on October 10, 2012, with you and other members of

your staff.

The inspections examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

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

Three NRC-identified findings and one self-revealing finding of very low safety significance (Green) were identified during this inspection. Three of these findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations consistent with Section 2.3.2 of the Enforcement Policy.

If you contest 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 the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear

Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at River Bend Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your

disagreement, to the Regional Administrator, Re gion IV; and the NRC Resident Inspector at River Bend Station.

UNITED STATESNUCLEAR REGULATORY COMMISSIONREGION IV1600 EAST LAMAR BLVDARLINGTON, TEXAS 76011-4511 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Managem ent System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/ Robert C. Hagar, Chief (Acting)

Project Branch C Division of Reactor Projects

Docket Nos.: 50-458

License Nos.: NPF-47

Enclosure:

Inspection Report 05000458/2012004 w/ Attachment: Supplemental Information

REGION IV Docket: 05000458 License: NPF-47 Report: 05000458/2012004 Licensee: Entergy Operations, Inc. Facility: River Bend Station Location: 5485 U.S. Highway 61 St. Francisville, LA 70775 Dates: July 1 through September 30, 2012 Inspectors: G. Larkin, Senior Resident Inspector, Project Branch C A. Barrett, Resident Inspector, Project Branch C W. Sifre, Senior Reactor Inspector, Engineering Branch 1 M. Young, Reactor Inspector, Engineering Branch 1 B. Rice, Resident Inspector, Project Branch C P. Elkmann, Sr. Emergency Preparedness Inspector, PSB 1 G. Guerra, CHP, Emergency Preparedness Inspector, PSB 1 C. Steely, Operations Engineer, Operations Branch D. Strickland, Operations Engineer, Operations Branch G. Apger, Operations Engineer, Operations Branch J. Laughlin, Emergency Preparedness Inspector, NSIR

Approved By: R. Hagar, Chief (Acting), Project Branch C Division of Reactor Projects

- 2 - Enclosure

SUMMARY OF FINDINGS

IR 05000458/2012004; 07/01/2012 - 09/30/2012; RIVER BEND STATION; Integrated Resident and Regional Report; Equipment Alignment; Operability Evaluations and Functionality Assessments; Post-Maintenance Testing

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Three green non-cited violations, and one green finding were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process." The cross-cutting aspect is determined using Inspection Manual Chapter 0310, "Components within the Cross-Cutting Areas." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a finding for the licensee's failure to calibrate the feed water Leading Edge Flow Meter (LEFM) CheckPlus System following maintenance activities. This resulted in an error in reactor feed water flow rate data used to calculate reactor core thermal power. This issue was entered into the licensee's corrective action program as Condition Report CR-RBS-2012-

06274 This performance deficiency is more-than-minor and is therefore a finding because it was associated with the procedure quality attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. The performance deficiency challenged the initiating events cornerstone objective by allowing the licensee to operate the plant outside of the prescribed analyzed uncertainty value, used in determining maximum core thermal power.

Using NRC Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process (SDP) for Findings at Power," the inspectors determined that this finding has very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that the apparent cause of this finding was that when the licensee had changed the flow meter maintenance work scope that required transducer replacement, they had not included the vendor verification requirement in the revised work order. Therefore, this finding has a cross-cutting aspect in the Human Performance area of Work Control because the licensee had failed to appropriately coordinate the impact of changes to the work scope or activity on the plant. H.3(b) (Section 1R19).

Cornerstone: Mitigating Systems

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure to correct within a reasonable period conditions adverse to quality associated with testing safety-related molded-case circuit breaker and unitized motor starter circuit breakers.

The licensee's immediate corrective actions included increasing the rate of breaker preventive maintenance and testing to reduce the long-standing risk-significant breaker backlog. The station documented the finding in Condition Report CR-RBS-2012-06364.

The performance deficiency was more-than-minor and is therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the safety-related molded-cased circuit breakers to respond to initiating events to prevent undesirable consequences. Specifically, failures of the affected breakers represent an increase in risk to safe plant operations, because to isolate a fault caused by a defective 480VAC breaker, the upstream feeder breaker would trip, thus causing a loss of power to additional safety-related components. Using Inspection Manual Chapter 0609, Appendix A, the finding is associated with the loss of mitigation equipment (Service Water pumps A and C), and so screened to a detailed risk evaluation. That evaluation determined that the incremental conditional core damage probability (ICCDP) was 2.1E-8 for a fire in one of the standby cooling tower electrical rooms, resulting in a loss of one train of service water pumps (A and C, or B and D), as a consequence of the failure of the proximate 480 VAC breaker to open. The risk was low because normal service water would be unaffected by the fire, and it would be unlikely that offsite power would be lost concurrently. The fire could also affect control room ventilation, but the analyst qualitatively concluded that this would not add more than negligibly to the overall risk. Consequently, the finding has very low safety significance (Green). The inspectors determined that the apparent cause of the finding was a combination of two factors related to resources: station management did not ensure that each work group completed its actions to support timely resolution, and personnel vacancies from key positions hampered completion of the breaker testing program. The inspectors therefore determined the finding had a cross-cutting aspect in the human performance area associated with the resources component because station management did not ensure personnel re sources were available to minimize long-standing equipment issues. H.2(a) (Section 1R04).

Green.

The inspectors identified a non-cited violation of 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," associated with inadequate instructions for tuning the reactor core isolation cooling (RCIC) terry turbine speed governor. The licensee's immediate corrective actions included revising the maintenance procedure and recalibrating the RCIC turbine speed controller. The station documented the finding in Condition Reports CR-RBS-2012-01750 and CR-RBS-2012-01904.

This performance deficiency is more-than-minor and is therefore finding because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, during operation, this performance deficiency resulted in improper tuning of the turbine speed control system, which caused the turbine exhaust check valve to repeatedly slam against its open and shut valve stops and abnormally large turbine governor valve oscillations. Because the licensee had not tuned the turbine speed control system to run at a steady speed, the licensee removed RCIC from service to properly calibrate the control syst em, thereby adversely affecting RCIC availability. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," the inspectors determined that the issue affected the Mitigating Systems Cornerstone.

Using NRC Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process (SDP) for Findings at Power," the inspectors determined that the issue had very low safety significance (Green) because the finding was not a deficiency affecting the design or qualification; did not represent a loss of system and/or function, did not represent either an actual loss of function of at least a single train for greater than its Technical Specification Allowed Outage Time, or two separate safety systems out-of-service for greater than its Technical Specification Allowed Outage Time; and 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 licensee's 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 inspectors determined the apparent cause of this finding was the licensee's failure to incorporate industry and vendor operating experience into the work instructions on February 12, 2011, to correct RCIC governor valve oscillations. Therefore, this finding has a cross-cutting aspect in the area of problem identification and resolution associated with the operating experience component because the licensee did not implement and institutionalize industry knowledge, including vendor recommendations, to support plant safety. P.2(b)

(Section 1R15.b.2)

Cornerstone: Barrier Integrity

Green.

The inspectors reviewed a self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for the failure to correctly translate the design bases for the power supply for the hydrogen igniter system into procedures used to set the associated power system supply breaker trip coil. The licensee's immediate corrective actions included evaluating the proper trip coil setting and adjusting the trip coil accordingly. The station documented the finding in Condition Report CR-RBS-2012-02623.

This performance deficiency is more-than-minor and is therefore a finding because it is associated with the design control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone's objective to ensure that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events.

Specifically, this performance deficiency resulted in an incorrect trip coil setting, which decreased the reliability of the hydrogen igniters, which burn hydrogen in a controlled manner to prevent containment damage. Using Inspection Manual Chapter 0609.04, "Initial Characterization of Findings," the finding required a significance evaluation per Inspection Manual Chapter 0609, Appendix H, "Containment Integrity Significance Determination Process," because the unavailable Division 1 hydrogen igniters represented a degraded condition affecting containment barrier integrity that can potentially increase large early release frequency (LERF) without affecting the core damage frequency (CDF). Inspectors determined that this was a type B finding. Using section 6.0, the inspectors determined that the finding was of very low safety significance (Green) because the hydrogen igniters are arranged in two independent divisions such that each containment region has two igniters, one from each division, controlled and powered redundantly so that ignition would occur in each region even if one division failed to energize. The inspectors determined that the apparent cause of this finding was that in response to earlier failures of the trip coil, the licensee had not investigated the problem thoroughly enough to identify and correct this performance deficiency. However, because the earlier failures had all occurred more than seven years ago, the inspectors determined that this cause did not reflect present licensee performance, so the inspectors did not assign a cross-cutting aspect to it. (Section 1R15.b.1).

B. Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

River Bend Station began the inspection period at 100 percent reactor power. On September 14, 2012, operators reduced reactor power to 69.5 percent for a control rod sequence exchange, turbine valve testing, control rod settle testing, bypass valve testing, and feedwater pump P1B gear increaser oil leak repair. On September 16, 2012, the plant resumed 100 percent power operations. On September 21, 2012, operators reduced reactor power to 91.7 percent to set the final rod pattern from the September 14 th rod sequence exchange, and to perform settle time testing on two rods. On September 22, 2012, the plant reached 100 percent and remained at 100 percent reactor power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

Since Hurricane Isaac was projected to make landfall on the gulf coast on August 28, 2012, the potential for thunderstorms, tornados, and high winds were forecast in the vicinity of the facility for August 28-30, 2012. The inspectors reviewed the plant personnel's overall preparations/protection for the expected weather conditions. On August 27 and 28, 2012, the inspectors walked down the the standby service water cooling tower, the main transformer yard, service water and circulating water systems because their important to safety functions could be affected, or required, as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the plant staff's preparations against the site's procedures and determined that the staff's actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensee's procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Safety Analysis Report and performance requirements for the systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. The inspectors also reviewed a sample of corrective action program items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the corrective action program in accordance with station corrective action procedures. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one readiness for impending adverse weather condition sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness to Cope with External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review to check for deviations from the descriptions provided in the Updated Safety Analysis Report for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable. Additionally, the inspectors performed an inspection of the protected area to identify any modification to the site that would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier.

The inspectors also reviewed the abnormal operating procedure for mitigating the design basis flood to ensure it could be implemented as written. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one external flooding sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial Walkdown

a. Inspection Scope

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

• Division 1 control building chilled water

• 480 VAC system

• Division 2 control room fresh air system

• Normal service water The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures,

system diagrams, Updated Safety Analysis Report, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure to correct within a reasonable period conditions adverse to quality associated with testing safety-related molded-case circuit breaker and unitized motor starter circuit breakers. The licensee's immediate corrective actions included increasing the rate of breaker preventive maintenance and testing to reduce the long-standing risk-significant breaker backlog.

Description.

In August 2008, an NRC inspection team determined, in part, that the licensee had failed to establish a comprehensive periodic test and preventive-maintenance program for Class 1E molded-case circuit breakers to assess age-related degradation. The team had documented this issue as non-cited violation 2008006-03 in Inspection Report 05000458/2008006. The inspectors determined that, in response to this violation, the licensee had not initiated a condition report with action to address this issue until June 2009. As described to the inspectors, the licensee had developed a program to inspect and test safety-related molded-case circuit breaker and unitized motor starter circuit breakers that involved multiple work groups working in a series of uncoordinated actions with each other, in part, to identify specific maintenance and testing requirements, perform preparatory walk downs, component tag outs, obtain replacement parts, and schedule the work. To these tasks, the licensee originally assigned a schedule completion date of December 31, 2010. Then, following personnel losses to key positions that had occurred during a hiring freeze, the licensee extended that completion date, so that actual testing of circuit breakers did not begin until October

2011.

By May 15, 2012, six of 35 tested breakers had failed their test criteria. The resulting apparent-cause evaluation determined that several of the failed circuit breakers were located in buildings cooled by outside air, and were therefore exposed to environmental conditions that would aggravate breaker reliability. On July 17, 2012, in Condition

Report CR-RBS-2012-04666, the licensee identified two additional failures. The associated operability evaluation had prompted the inspectors to complete additional reviews, recognize that the affected circuit breakers were associated with corrective actions that were associated with the subject non-cited violation in August, 2008, and conclude that those corrective actions had not been timely. In response to the inspectors concerns, the licensee's immediate corrective actions included promptly testing the breakers installed in areas with poor environmental conditions. That testing was completed in August, 2012. In addition, the licensee increased the rate of breaker preventive maintenance and testing to address the long-standing risk significant breaker backlog. The licensee has scheduled to achieve full compliance with the testing requirements by August 23, 2013. By the end of September 2012, the station had tested 89 of approximately 370 breakers. Twenty of those breakers had failed their test criteria, resulting in a breaker failure rate of 22 percent.

Analysis.

The inspectors determined that the licensee's failure to take effective timely corrective actions to implement a test program to assure that all installed safety-related molded-case and unitized motor starter circuit breakers would perform satisfactorily in service was a performance deficiency. The performance deficiency was more-than-minor and is therefore a finding because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone objective of ensuring the availability, reliability, and capability of the safety-related molded-cased circuit breakers to respond to initiating events to prevent undesirable consequences. Specifically, failures of the affected breakers represent an increase in risk to safe plant operations, because to isolate a fault caused by a defective 480VAC breaker, the upstream feeder breaker would trip, thus causing a loss of power to additional safety-related components. Using Inspection Manual Chapter 0609, Appendix A, the finding is associated with the loss of mitigation equipment (Service Water pumps A and C), and so screened to a detailed risk

evaluation. That evaluation determined that the incremental conditional core damage probability (ICCDP) was 2.1E-8 for a fire in one of the standby cooling tower electrical rooms, resulting in a loss of one train of service water pumps (A and C, or B and D), as a consequence of the failure of the proximate 480 VAC breaker to open. The risk was low because normal service water would be unaffected by the fire, and it would be unlikely that offsite power would be lost concurrently. The fire could also affect control room ventilation, but the analyst qualitatively concluded that this would not add more than negligibly to the overall risk. Consequently, the finding has very low safety significance (Green). The inspectors determined that the apparent cause of the finding was a combination of two factors related to resources: station management did not ensure that each work group completed its actions to support timely resolution, and personnel vacancies from key positions hampered completion of the breaker testing program. The inspectors therefore determined the finding had a cross-cutting aspect in the human performance area associated with the resources component because station management did not ensure personnel res ources were available to minimize long-standing equipment issues. H.2(a)

Enforcement.

10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and

equipment, and nonconformance are promptly identified and corrected. Contrary to the above, from August 26, 2008, to September 30, 2012, measures established by the licensee failed to assure that conditions adverse to quality were promptly identified and corrected. Specifically, the lack of a program to complete periodic testing of installed safety related molded-case circuit breakers and unitized motor starters was a condition adverse to quality, and measures established by the licensee failed to assure that that condition was promptly corrected, in that after that condition had been identified in October 2008, the licensee did not begin the associated testing until October 2011.

The licensee's immediate corrective actions included testing the breakers installed in areas with poor environmental conditions before August 2012. In addition, to address the long-standing risk-significant breaker backlog, the licensee increased the rate at which they completed breaker preventive maintenance and testing. The licensee has scheduled to achieve full compliance with the testing requirements by August 23, 2013. Because this violation was determined to be of very low safety significance and was entered into the licensee's corrective action program as Condition Report CR-RBS-2012-06364, this violation is being treated as a non-cited violation, consistent with Section 2.3.2a of the NRC Enforcement Policy: NCV 05000458/2012004-02, "Untimely Corrective Actions to Ensure Reliability of the 480 VAC Molded Case Circuit Breakers and Unitized Motor Starters."

.2 Complete Walkdown

a. Inspection Scope

On September 27, 2012, the inspectors performed a complete system alignment inspection of the high pressure core spray system to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensee's probabilistic risk assessment. The inspectors inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and ap propriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one complete system walkdown sample as defined in Inspection Procedure 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Fire Inspection Tours

a. Inspection Scope

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

• July 9, 2012, turbine building, 67-foot and 123-foot elevations

• July 10, 2012, reactor building, 98-foot, 141-foot, and 186-foot elevations

• July 17, 2012, fire pump house

• July 22, 2012, control building, fire area C-2, southeast cable chase

• September 13, 2012, normal switchgear building, 98-foot and 123-foot elevations The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensee's fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plant's ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensee's corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On September 13, 2012, the inspectors observed a fire brigade activation for a mock fire in the normal switchgear building. The observation evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took

appropriate corrective actions. Specific attributes evaluated were

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

(2) proper use and layout of fire hoses;

(3) employment of appropriate fire fighting techniques;

(4) sufficient firefighting equipment brought to the scene;

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

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

(7) smoke removal operations;

(8) utilization of preplanned strategies;

(9) adherence to the preplanned drill scenario; and

(10) drill objectives.

These activities constitute completion of one annual fire-protection inspection sample as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance (71111.11 and 71111.11B)

.1 Quarterly Review of Licensed Operator Requalification Program

a. Inspection Scope

On September 11, 2012, the inspectors observed a crew of licensed operators in the plant's simulator during training. The inspectors assessed the following areas:

• Licensed operator performance

• The modeling and performance of the control room simulator

• The quality of post-scenario critiques

• Follow-up actions taken by the licensee for identified discrepancies The inspectors used Operating Experience Smart Sample FY 2010-02 "Sample Selections for Reviewing Licensed Operator Examinations and Training Conducted on the Plant-Referenced Simulator" for this inspection. These activities constitute completion of one quarterly licensed operator requalification program sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Quarterly Observation of Licensed Operator Performance

a. Inspection Scope

On September 11, 2012, the inspectors observed the performance of on-shift licensed operators in the plant's main control room. At the time of the observations, the plant was in a period of heightened activity due to planned surveillances on the fuel building ventilation system and operations support of work on the auxiliary building HVAC system.

The inspectors assessed the operators' adherence to plant procedures, including EN-OP-115, "Conduct of Operations," Revision 013 and other operations department policies.

These activities constitute completion of one quarterly licensed-operator performance sample as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.3 Biennial Inspection

The licensed operator requalification program involves two training cycles that are conducted over a 2-year period. In the first cycle, the annual cycle, the operators are administered an operating test consisting of job performance measures and simulator scenarios. In the second part of the training cycle, the biennial cycle, operators are administered an operating test and a comprehensive written examination.

a. Inspection Scope

To assess the performance effectiveness of the licensed operator requalification program, the inspectors conducted personnel interviews, reviewed both the operating tests and written examinations, and observed ongoing operating test activities. The inspectors interviewed four licensee personnel, consisting of four operators to determine their understanding of the policies and practices for administering requalification examinations. The inspectors also reviewed operator performance on the written exams and operating tests. These reviews included observations of portions of the operating tests by the inspectors. The operating tests observed included five job performance measures and two scenarios that were used in the current biennial requalification cycle. These observations allowed the inspectors to assess the licensee's effectiveness in conducting the operating test to ensure operator mastery of the training program content. The inspectors also reviewed medical records of five licensed operators for conformance to license conditions and the licensee's system for tracking qualifications.

The results of these examinations were reviewed to determine the effectiveness of the licensee's appraisal of operator performance and to determine if feedback of performance analyses into the requalification training program was being accomplished. The inspectors interviewed members of the training department and reviewed minutes of training review group meetings to assess the responsiveness of the licensed operator requalification program to incorporate the lessons learned from both plant and industry events. Examination results were also assessed to determine if they were consistent with the guidance contained in NUREG 1021, "Operator Licensing Examination Standards for Power Reactors", Revision 9, Supplement 1, and NRC Manual Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance Determination Process." In addition to the above, the inspectors reviewed examination security measures, simulator fidelity and existing logs of simulator deficiencies. On August 20, 2012, the licensee informed the lead inspector of the results of the written examinations and operating tests for the Licensed Operator Requalification Program. The inspectors compared these results to the Appendix I, "Licensed Operator Requalification Significance Determination Process," values and determined that there were no findings based on these results and because all of the individuals that failed the applicable portions of their exams and/or operating tests were remediated, retested, and passed their retake exams prior to returning to shift. The inspectors completed one inspection sample of the biennial licensed operator requalification program.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• Drains - floor and equipment

• Emergency response information system The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

• Scoping of systems in accordance with 10 CFR 50.65(b)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1)

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Assessment of functionality of standby service water system during maintenance on breakers for MOV-501B/511B, August 9, 2012

• HVR-UC5 maintenance impact, August 23, 2012

• Remote shutdown panel calibration of residual heat removal flow indication with reactor core isolation cooling unavailable, September 4, 2012

• EPA breaker testing per work order 52405157, September 5, 2012 The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples as defined in Inspection

Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following assessments:

• CR-RBS-2012-04629, electric fire pump degraded suction piping, reviewed on July 17, 2012

• CR-RBS-2012-04666, 480V molded case circuit breakers increased failure rate, reviewed on July 24, 2012

• CR-RBS-2012-02782, spent fuel pool liner deficiencies, reviewed on August 1, 2012

• CR-RBS-2012-01750, reactor core isolation cooling turbine governor valve cycling, reviewed on July 1, 2012

• CR-RBS-2012-03640, operability of Division 1 and Division 2 hydrogen igniters, reviewed on May 30, 2012 The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems. The inspectors evaluated

the technical adequacy of the evaluations to ensure technical specification operability was properly justified and to verify the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and the Updated Safety Analysis Report to the licensee's evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the

inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b. Findings

===.1

=

The inspectors reviewed a Green, self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for the failure to correctly translate the design bases for the power supply for the hydrogen igniter system into procedures used to set the associated power system supply breaker trip coil.

Description.

On April 13, 2012, when operators attempted to start the Division 1 hydrogen igniters, none of the Division 1 igniters energized because the circuit breaker, EHS-MCC2A-3A, for the Division 1 hydrogen igniter control circuit had tripped. The circuit breaker contains a magnetic trip coil which provides instantaneous over-current protection. That trip coil is adjustable with current amperage settings of "Low", "1", "2",

"3", "4", "5" and "High". The inspectors' historical review found that the subject breaker had previously tripped in 1999, 2000, 2004 and 2005, when operators had attempted to start the Division 1 hydrogen igniters. In response to the 1999 event, the licensee had moved the trip setting for EHS-MCC2A-3A from position 1 to position 2, and in response to the 2000 event, they moved the setting from position 2 to position 3. Both times, the licensee had used Note 5 of BE-200A ("Time Sheet - Relay Set Point Data Sheet Index

") as justification for increasing the trip setting. That note states that trip coil size selection is based on the criteria in calculation E-164, "Procedure for Selection Trip Coils, Motor Overload Heaters, and Overload Relays for 460 V Normal and Safety Class Motors and MOVS." After the breaker trips in 2004 and 2005, the licensee's evaluations did not result in changing the trip coil setting, so the setting remained at position 3.

To determine the appropriate trip coil setting, the inspectors noted that according to the EHS-MCC3A-2A breaker nameplate, with the trip coil set on position 3, the trip setting is 422 amps, and that according to Procedure CMP-1026, "MCC Circuit Breakers, Starters, and Thermal Overloads," that trip setting is subject to a inrush current tolerance of -30% to +40%. The inspectors also noted that during its current-injection test, EHS-MCC2A-3A had tripped at 331 amps. Therefore, the inspectors concluded that the position 3 setting had not been adequate to prevent a spurious circuit breaker trip for the estimated 375-amp 15 KVA transformer inrush current.

After the 2012 breaker trip, the licensee evaluated the proper trip coil setting in Condition Report CR-RBS-2012-02623 and in Engineering Change EC-37897, "Evaluation to Raise Trip Setting of EHS-MCC2A-3A and EHS-MCC2K-6B for Hydrogen Igniters." In Condition Report CR-RBS-2012-02623, the licensee had determined that calculation E-164 was specific to motors only, and was not applicable to the EHS- MCC2A-3A breaker, because EHS-MCC2A-3A energizes the Division 1 hydrogen igniter panels via a 15 KVA transformer and not through motors. In EC-37897, the licensee established criteria which required that for each phase, the trip coil shall trip at 400 amps and 515 amps, and subsequently adjusted the trip coil to "High" on June 1, 2012, to meet those criteria.

Analysis.

The licensee's failure to establish an appropriate procedure for properly setting the hydrogen igniter breaker trip coil was a performance deficiency. This performance deficiency is more-than-minor and is therefore a finding because it is associated with the design control attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstone's objective to ensure that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, this performance deficiency resulted in an incorrect trip coil setting, which decreased the reliability of the hydrogen igniters, which burn hydrogen in a controlled manner to prevent containment damage. Using Inspection Manual Chapter 0609.04, "Initial Characterization of Findings," the finding required a significance evaluation per Inspection Manual Chapter 0609, Appendix H, "Containment Integrity Significance Determination Process," because the unavailable Division 1 hydrogen igniters represented a degraded condition affecting containment barrier integrity that can potentially increase large early release frequency (LERF) without affecting the core damage frequency (CDF). Inspectors determined that this was a type B finding. Using section 6.0, the inspectors determined that the finding was of very low safety significance (Green) because the hydrogen igniters are arranged in two independent divisions such that each containment region has two igniters, one from each division, controlled and powered redundantly so that ignition would occur in each region even if one division failed to energize. The inspectors determined that the apparent cause of this finding was that in response to earlier failures of the trip coil, the licensee had not investigated the problem thoroughly enough to identify and correct this performance deficiency. However, because the earlier failures had all occurred more than seven years ago, the inspectors determined that this cause did not reflect present licensee performance, so the inspectors did not assign a cross-cutting aspect to it.

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that measures shall be established to assure that applicable regulatory requirements and the design basis for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, before June 1, 2012, measures established by the licensee did not assure that applicable regulatory requirements and the design basis for a certain system to which this appendix applies were correctly translated into specifications, drawings, procedures, and instructions. Specifically, measures established by the licensee did not assure that the design bases for the power supply for the hydrogen igniter system were correctly translated into procedures used to

test and adjust the power supply system trip coil setting, in that those measures did not assure that the design-basis requirement to establish a trip coil setting to accommodate a possible breaker inrush current of approximately 375 amps without tripping was correctly translated into the procedures used to test and adjust the power supply system trip coil setting. This issue was entered into the licensee's corrective action program as

Condition Report CR-RBS-2012-02623. The licensee's immediate corrective actions included an evaluation of the proper trip coil setting, which resulted in adjusting the trip coil to "High". Because this finding was determined to be of very low safety significance and was entered into the licensee's corrective action program, this violation is being treated as a non-cited violation, consistent with Section 2.3.2a of the NRC Enforcement Policy: NCV 05000458/2012004-01, "Improper Hydrogen Igniter Breaker Trip Coil

Setting."

===.2

=

The inspectors identified a Green, non-cited violation of 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," associated with inadequate instructions for tuning the reactor core isolation cooling (RCIC) terry turbine

speed governor.

Description.

During RCIC system maintenance on February 12, 2011, technicians had replaced the electric governor remote hydraulic actuator (EG-R), ramp generator and signal converter, and electronic governor magnetic pickup control system (EG-M). Following that maintenance, technicians had calibrated the turbine speed control system components using maintenance procedure MCP-4195, "Calibration of the RCIC Turbine Speed Controls." This procedure performs a coarse calibration of the turbine speed control system, and if needed, a fine tuning of the speed control circuitry by adjusting the EG-M gain potentiometer. This procedure states that if the EG-M gain potentiometer is adjusted, then a technician should repeat the EG-M coarse calibration from a zero value.

However, the inspectors determined that this procedural step was contrary to the vendor technical manual "Woodward Governor Co. EG-3C and EG-R Actuators Installation and

Operation," which states that "the EG-M gain is an expected adjustment during fine tuning while the turbine is running. A base recalibration is not needed unless the turbine will not settle and a faulty EG-M is suspected." So, repeating the EG-M calibration from a zero value in accordance with the procedure changed the EG-M gain and stability adjustments. As a result, the RCIC turbine speed governor was not tuned to run steady, free of oscillations.

On March 8, 2012, inspectors observed the RCIC terry turbine speed governor steam valve control linkage oscillating and the steam exhaust check valve repeatedly slamming against its open and shut valve stops. Plant operations personnel documented these oscillations in condition report CR-RBS-2012-01750. The licensee declared the RCIC system inoperable, revised the maintenance procedure, and recalibrated the RCIC turbine speed controls, thereby removing the oscillations in the governor valve position. The licensee reviewed historical data following RCIC system maintenance performed on February 12, 2011, and found that the governor valve position had oscillated as much as 18 percent of nominal governor valve position. To verify RCIC operability following the

maintenance performed on February 12, 2011, the inspectors reviewed records which showed RCIC performance at low pump flow rates, during RCIC turbine slow rolls

performed on November, 10, 2011 and during an actual reactor vessel injection on December 23, 2011. From that review, the inspectors concluded that although RCIC speed had oscillated at those times, the RCIC speed control system had remained functional during the subject period.

Analysis.

The licensee's failure to establish an appropriate procedure for calibrating the reactor core isolation cooling turbine speed governor was a performance deficiency.

This performance deficiency is more-than-minor and is therefore finding because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, during operation, this performance deficiency resulted in improper tuning of the turbine speed control system, which caused the turbine exhaust check valve to repeatedly slam against its open and shut valve stops and abnormally large turbine governor valve oscillations. Because the licensee had not tuned the turbine speed control system to run at a steady speed, the licensee removed RCIC from service to properly calibrate the control system, thereby adversely affecting RCIC availability. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," the inspectors determined that the issue affected the Mitigating Systems Cornerstone. Using NRC Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process (SDP) for Findings at Power," the inspectors determined that the issue had very low safety significance (Green) because the finding was not a deficiency affecting the design or qualification; did not represent a loss of system and/or function, did not represent either an actual loss of function of at least a single train for greater than its Technical Specification Allowed Outage Time, or two separate safety systems out-of-service for greater than its Technical Specification Allowed Outage Time; and 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 licensee's 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 inspectors determined the apparent cause of this finding was the licensee's failure to incorporate industry and vendor operating experience into the work instructions on February 12, 2011, to correct RCIC governor valve oscillations. Therefore, this finding has a cross-cutting aspect in the area of problem identification and resolution associated with the operating experience component because the licensee did not implement and institutionalize industry knowledge, including vendor recommendations, to support plant

safety. P.2(b)

Enforcement.

10 CFR 50, Appendix B, Criterion V, "Procedures," requires in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Contrary to this requirement, from before February 12, 2011, to March 17, 2012, activities affecting quality were prescribed by documented procedures of a type that was not appropriate to the circumstances. Specifically, during that period, the station's procedures to setup the reactor core isolation cooling turbine speed governor failed to ensure that the turbine speed control system gain setting was appropriately calibrated. The licensee's immediate corrective actions included revising the maintenance procedure to remove the requirement to re-perform the EG-M calibration if gain is adjusted, and recalibration of the RCIC turbine

speed controller. This violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy because it was of very low safety significance and it was entered into the licensee's corrective action program as Condition Reports CR-RBS-2012-01750 and CR-RBS-2012-01904, NCV 05000458/2012004-03, "Failure to Appropriately Tune the Reactor Core Isolation

Cooling Turbine Speed Controller."

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the following temporary modifications:

• Engineering Change EC-38941, "Provide Acceptability for Lubricating Gould/ITE Starters," Revision 0 The inspectors reviewed the permanent modification and the associated safety-evaluation screening against the system design bases documentation, including the Updated Safety Analysis Report and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

These activities constitute completion of one sample for permanent plant modifications as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

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

• WO-00319201, "E22-EGS001 Cylinder #16 Temperature High," reviewed on July 2, 2012

• WO-00232294, "FWS-AIT200 Check the Transducer Cables per VTD C126-0102," reviewed on July 12, 2012

• WO-00322911, "Test Molded Case Circuit Breaker EHS-MCC16A 2A / SWP-FN1J," reviewed on August 2, 2012

• WO-50348003, "EHS-MCC16A - Clean, Inspect, Record," reviewed on August 7, 2012

• WO-00316561, "EHS-MCC2K-6B Adjust Trip Coil to Setting per EC37897," reviewed on August 15, 2012 The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following (as applicable):

• The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate The inspectors evaluated the activities against the technical specifications, the Updated Safety Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of five post-maintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

Introduction.

The inspectors identified a Green finding for the licensee's failure to calibrate the feed water Leading Edge Flow Meter (LEFM) CheckPlus System following maintenance activities.

This resulted in an error in reactor feed water flow rate data used to calculate reactor core thermal power.

Description.

The licensee uses the LEFM CheckPlus System to accurately determine core thermal power. Cameron Engineering Report ER-260, "Bounding Uncertainty Analysis for Thermal Power Determination at River Bend Using the LEFM CheckPlus System" determined that bounding uncertainty for a fully functioning flow meter at River

Bend is less than or equal to plus or minus 0.25%. Use of the properly calibrated flow meter, in part, permits the licensee to increase core thermal power by approximately 1.7% as permitted by the 10CFR50, Appendix K, ""ECCS Evaluation Model," power up-rate.

In February 2011, instrumentation and control technicians replaced all existing transducers and transducer cables associated with the flow meter per work order 00232294-01. Following transducer replacement, the vendor technical manual requires that the vendor review various system attributes associated with transducer signal quality, setting alarm limits, fluid velocity and sound velocity data analysis. However, the licensee returned the flow meter to service without any additional technical justification to ensure flow meter accuracy. Later, after responding to inspector concerns about the missing vendor review, the licensee determined that the original work scope had not included transducer replacement, and that when they had added transducer replacement to the revised work order, the planners had failed to explicitly state that vendor review was required. The technicians had closed the work order without vendor

oversight because the vendor review requirement was contained in a note that was located in the vendor manual after the work step that required the transducer replacement. At River Bend Station, notes that pertain to a work step are required to precede the work step. Therefore, the technicians did not believe that the note applied to their work.

Again, on March 13, 2012, the licensee installed all new transducers. Following the work, the vendor reviewed the flow meter operation and concluded that the flow meter met the requirements of Cameron Engineering Report ER-260. The licensee then placed the flow meter back into service. The inspectors compared 100% steady state core thermal power values calculated by the licensee's "best estimate of core thermal power" method before and after March 13, 2012, and found that core thermal was greater by approximately 22 Megawatts thermal, or about 0.66% power, before March 13, 2012. The inspectors concluded that the licensee's failure to validate acceptable flow meter operation after transducer change out in February 2011, had resulted in the observed change in core thermal power that had exceeded the bounding uncertainty analysis in Cameron Engineering Report ER-260. In response, the licensee was unable to identify any other plant parameter other than the flow meter transducer change out that would explain the increase in plant output. To prevent recurrence of an additional power anomaly, the licensee changed the model work order to require vendor support and system verification following transducer work. This condition is entered into the licensee's corrective action program as Condition Report CR-RBS-2012-06274.

Analysis.

The failure to calibrate the flow meter following maintenance is a performance deficiency with respect to the LEFM vendor's technical manual (Cameron Engineering Report ER-260), which bounds the flow meter uncertainty as less than or equal to +/-0.25% of core thermal power. Contrary to this, the licensee placed the flow meter into service with an uncertain of greater than +/-0.25% of core thermal power. This performance deficiency is more-than-minor and is therefore a finding because it was associated with the procedure quality attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of those events that upset plant

stability and challenge critical safety functions. The performance deficiency challenged the initiating events cornerstone objective by allowing the licensee to operate the plant outside of the prescribed analyzed uncertainty value, used in determining maximum core thermal power. Using NRC Inspection Manual Chapter 0609, Appendix A, "The Significance Determination Process (SDP) for Findings at Power," the inspectors determined that this finding has very low safety significance (Green) because it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The inspectors determined that the apparent cause of this finding was that when the licensee had changed the flow meter maintenance work scope that required transducer replacement, they had not included the vendor verification requirement in the revised work order.

Therefore, this finding has a cross-cutting aspect in the Human Performance area of Work Control because the licensee had failed to appropriately coordinate the impact of changes to the work scope or activity on the plant H.3(b).

Enforcement.

The finding does not involve enforcement action because no regulatory requirement violation was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as FIN 05000458/2012004-04, "Inadequate Verification of Leading Edge Flow Meter Functionality."

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Updated Safety Analysis Report, procedure requirements, and technical specifications to ensure that the surveillance activities listed below

demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Restoration of plant systems

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• STP-257-0202, Revision 013, "Standby Gas Treatment System Filter Train B Monthly Operability Test," performed on August 16, 2012 (inservice test)

• STP-309-0203, Revision 314, "Division III Diesel Generator Operability Test," performed on August 23, 2012 (routine)

• STP-201-6310, Revision 309, "SLC Pump and Valve Operability Test," performed on August 24, 2012 (inservice test)

• STP-200-4205, "RSS_RHR System Flow Loop A Channel Calibration (C61-N001:C61-R005)," performed on September 4, 2012 (routine)

• STP-309-0203, Revision 315, "Division III Diesel Generator Operability Test," performed on September 17, 2012 (routine)

• WO-52432497, "Perform Diagnostic Testing on Cable 1SWPANH303," performed on September 20, 2012 (routine)

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six surveillance testing inspection samples as defined in Inspection Procedure 71111.22-05.

b. Findings

No findings were identified.

===Cornerstone: Emergency Preparedness

=

The licensee submitted the preliminary exercise scenario to the NRC on April 13, 2012, in accordance with the requirements of Appendix E to 10 CFR 50, Part IV.F.2(a). The

inspectors performed an in-office review of the scenario to determine whether the exercise would acceptably test major elements of the emergency plan, provide opportunities to demonstrate key emergency response organization skills, challenge the emergency response organization, and avoid participant preconditioning.

The scenario was designed to escalate through all four emergency classifications from a Notification of Unusual Event through General Emergency. The scenario simulated:

• Damage to a spent fuel cask being transported to the Independent Spent Fuel Storage Installation;

• A line break in the Low Pressure Containment Spray system that flooded plant rooms;

• Failures in the Technical Support Center emergency ventilation system;

• Leaks in a Control Rod Drive pump;

• A failure in the Reactor Protection System causing a reactor scram, with rods that failed to insert;

• A reactor cooling system leak through an open safety relief valve, with a drywell leak into primary containment through a failed relief valve tailpipe vacuum breaker; and,

• A radiological release from primary containment into the Auxiliary Building and the environment because of a failed seal on the interior personnel airlock door and a stuck-open exterior airlock door.

The inspectors evaluated exercise performance by focusing on the risk-significant activities of event classification, offsite notification, recognition of offsite dose

consequences, and development of protective action recommendations, in the Control Room Simulator and the following dedicated emergency response facilities:

• Technical Support Center

• Operations Support Center

• Emergency Operations Facility The inspectors also assessed recognition of, and response to, abnormal and emergency plant conditions, the transfer of decision making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of emergency workers, emergency repair evaluation and capability, and the overall implementation of the emergency plan to protect public health and safety and the environment. The inspectors reviewed the current revision of the facility emergency plan, emergency plan implementing procedures associated with operation of the licensee's emergency response facilities, procedures for the performance of associated emergency functions, and other documents as listed in the attachment to this report.

The inspectors compared the observed exercise performance with the requirements in the facility emergency plan, 10 CFR 50.47(b), 10 CFR Part 50, Appendix E, and with the guidance in the emergency plan implementing procedures and other federal guidance.

The inspectors attended the postexercise critiques in each emergency response facility to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended a subsequent formal presentation of critique items to plant management.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.01-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The NSIR Headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML12194A042 as listed in the Attachment. The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment. These activities constitute completion of one sample as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on August 14, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the Technical Support Center, Simulator, and Emergency Operations Facil ity to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the second quarter 2012 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, "Performance Indicator Program."

This review was performed as part of the inspectors' normal plant status activities and, as such, did not constitute a separate inspection sample.

b. Findings

No findings were identified.

.2 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill and Exercise Performance, performance indicator for the period January 2011 through March 2012. The performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, were used to determine the accuracy of the performance indicator data reported during the inspection period. The inspectors reviewed the licensee's records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator; assessments of performance indicator opportunities during predesignated control room simulator training sessions, performance during the 2012 biennial exercise, and performance during other drills. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the drill/exercise performance sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspectors sampled licensee submittals for the Emergency Response Organization Drill Participation performance indicator for the period January 2011 through March 2012. The performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, "Regulatory Assessment Performance Indicator Guideline,"

Revision 6, were used to determine the accuracy of the performance indicator data reported during the inspection period. The inspectors reviewed the licensee's records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator, rosters of personnel assigned to key emergency response organization positions, and exercise participation records. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the emergency response organization drill participation sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Alert and Notification System (EP03)

a. Inspection Scope

The inspectors sampled licensee submittals for the Alert and Notification System performance indicator for the period January 2011 through March 2012. The performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, were used to determine the accuracy of the performance indicator data reported during the inspection period. The inspectors reviewed the licensee's records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.

Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator and the results of periodic alert notification system operability tests. The specific documents reviewed are described in the attachment to this report.

These activities constitute completion of the alert and notification system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensee's corrective action program because of the inspectors' observations are included in the attached list of documents reviewed.

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's corrective action program. The inspectors accomplished this through review of the station's daily corrective action documents.

The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit Exit Meeting Summary

On May 4, 2012, the inspectors had discussed the in-office review of the preliminary exercise scenario with Mr. T. Burnett, Manager, Emergency Preparedness, and other members of the licensee's staff.

On June 15, 2012, the inspectors had discussed the the on-site inspection of the licensee's biennial emergency plan exercise with Mr. E. Olson, Site Vice President, and other members of the licensee's staff.

On July 18, 2012, the inspectors conducted an exit meeting to present the results of the on-site and in-office inspection of the licensee's biennial emergency plan exercise with Mr. J. Roberts, Director, Nuclear Safety Assurance, and other members of the licensee's staff; the meeting was conducted by conference call. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

The inspectors debriefed Mr. Eric Olson, Site Vice President, and other members of the licensee's staff of the results of the licensed operator requalification program inspection on August 10, 2012, and telephonically exited with Mr. John Fralic and other staff members on September 13, 2012. The inspectors asked the licensee whether any materials examined

during the inspection should be considered proprietary. No proprietary information was identified. On October 10, 2012, the inspectors presented the integrated inspection results to Mr. Eric Olson, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

A-1 Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Boulanger, Manager, Maintenance

D. Burnett, Manager, Emergency Preparedness

G. Bush, Manager, Material, Procurement, and Contracts

M. Chase, Manager, Training

J. Clark, Manager, Licensing

C. Colman, Manager, Engineering Programs & Components

F. Corley, Manager, Design Engineering

R. Creel, Superintendent, Plant Security

T. Evans, Manager, Operations

M. Feltner, Manager, Planning and Scheduling, Outages

C. Forpahl, Manager, System Engineering

J. Fralic, Superintendent, Training

A. Fredieu, Manager, Outage

R. Gadbois, General Manager, Plant Operations

T. Gates, Assistant Operations Manager - Shift

G. Hackett, Superintendent, Radiation Protection

K. Hallaran, Superintendent, Chemistry

K. Huffstatler, Senior Licensing Specialist

G. Krause, Assistant Operations Manager - Training

W. Mashburn, Director, Engineering

E. Olson, Site Vice President

W. Renz, Director, Emergency Planning

J. Roberts, Director, Nuclear Safety Assurance

T. Santy, Manager, Security

T. Shenk, Assistant Operations Manager - Support

M. Spustack, Supervisor, Engineering

D. Vines, Manager, Corrective Actions and Assessments

J. Vukovics, Supervisor, Reactor Engineering

D. Williamson, Senior Licensing Specialist

L. Woods, Manager, Quality Assurance

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000458/2012004-01 NCV Improper Hydrogen Igniter Breaker Trip Coil Setting

(1R15.b.1)

05000458/2012004-02 NCV Untimely Corrective Actions to Ensure Reliability of the 480 Vac Molded Case Circuit Breakers and Unitized Motor

Starters (1R04)

05000458/2012004-03 NCV Failure to Appropriately Tune the Reactor Core Isolation Cooling Turbine Speed Controller (1R15.b.2)

05000458/2012004-04 FIN Inadequate Verification of Leading Edge Flow Meter Functionality (1R19)