IR 05000458/2014002

IR 05000458-14-002; on 01/01/2014 - 03/31/2014; River Bend Station; Integrated Inspection Report; Heat Sink Performance; Maintenance Risk Assessments and Emergent Work Control; Problem Identification and Resolution

ML14134A595
Person / Time
Site:	River Bend
Issue date:	05/14/2014
From:	Allen D NRC/RGN-IV/DRP/RPB-C
To:	Olson E Entergy Operations
References
IR-14-002
Download: ML14134A595 (42)

Text

May 14, 2014

SUBJECT:

RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT 05000458/2014002

Dear Mr. Olson:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the River Bend Station, Unit 1. On April 15, 2014, the NRC inspectors discussed the results of this inspection with you and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented four findings of very low safety significance (Green) in this report.

All of these findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violations or significance 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the River Bend Station.

If you disagree with a cross-cutting aspect in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the River Bend Station.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC s Agencywide Documents Access and Management 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/

Donald B. Allen, Branch Chief Project Branch C Division of Reactor Projects Docket Nos.: 50-458 License Nos: NPF-47 Enclosure:

Inspection Report 05000458/2014002 w/ Attachments:

1. Supplemental Information 2. Request for Information cc w/ encl: Electronic Distribution for River Bend Station

SUMMARY

IR 05000458/2014002; 01/01/2014 - 03/31/2014; River Bend Station; Integrated Inspection

Report; Heat Sink Performance; Maintenance Risk Assessments and Emergent Work Control;

Problem Identification and Resolution The inspection activities described in this report were performed between January 1 and March 31, 2014, by the resident inspectors at River Bend Station and inspectors from the NRCs Region IV office. Four findings of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red), which is determined using Inspection Manual Chapter 0609, Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, Components Within the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with the NRC Enforcement Policy. The NRC s program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.

Cornerstone: Mitigating Systems

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, for failing to verify acceptable performance of the control building chillers. Specifically, station personnel failed to evaluate the increase in instrument uncertainty and increase in design basis accident heat loads in a calculation used to determine the thermal performance for control building chillers. The stations corrective actions included reanalyzing the performance calculation to account for the increased chiller loads and instrument uncertainty; revising the acceptance criteria used in the surveillance test procedures; and revising the surveillance test procedures to use instruments of similar or better accuracy than the instruments used in the performance calculation. The licensee entered this issue into their corrective action program as Condition Reports CR-RBS-2013-07133 and CR-RBS-2013-7105.

The failure to evaluate the decrease in temperature accuracy in measuring chilled water and service water temperatures, and evaluate the increase in control building heat loads in the performance calculation to ensure that the chiller capacity acceptance criteria stated in the surveillance test procedures was acceptable, was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, station personnel used incorrect assumptions in the performance calculation that created a reasonable doubt of the operability of the Divisions 1 and 2 control building chillers. In addition, the potential existed that in future testing the as-left instrument uncertainty plus the design basis load could exceed the chillers load capacity. The inspectors determined the finding to be of very low safety significance (Green) in accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. Using Exhibit 2, which contains the screening questions for the Mitigating Systems Cornerstone, the inspectors determined that the finding screened as Green because it was not a deficiency affecting the design or qualification deficiency; it did not represent a loss of system or function; it did not represent the loss of function for any technical specification system, train, or component beyond the allowed technical specification outage time; it did not represent an actual loss of function of any non-technical specification trains of equipment designated as high safety-

significant; and it did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. These performance deficiencies occurred in 2003 and 2009 and therefore are not indicative of current licensee performance (Section 1R07).

Green.

The inspectors identified a non-cited violation of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specifically, on February 12, 2014, the licensee failed to correctly assess and manage the increase in risk associated with work in the stations Fancy Point electrical switchyard. Corrective actions included reevaluating risk for the time period and issuing interim guidance on planning and evaluating the risk of switchyard work. The station planned to revise the OSP-0048 procedure to include the interim guidance. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2014-01221.

The failure to perform an adequate risk assessment and implement appropriate risk management actions was a performance deficiency. The inspectors used Inspection Manual Chapter 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, to determine that the performance deficiency was more than minor, and therefore a finding, because it was associated with the Mitigating Systems Cornerstone attribute of protection against external factors and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

Manual Chapter 0609, Attachment 4, directs the inspectors to Appendix K for Maintenance Risk Assessment issues. The inspector used NRC Inspection Manual Chapter 0609,

Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005. The licensee provided Risk Assessment Related to CR-RBS-2014-1220/-1221 Switchyard Work, dated March 31, 2014. The exposure period was 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />. The licensee identified the risk deficit as 2.6E-8/year. Since the risk deficit was less than 1E-6, the finding was of very low safety significance (Green).

This finding was not significant to the large early release frequency. The apparent cause of the finding involved the failure to fill a position to act as a point of contact for switchyard work management for a period of four months due to the stations staffing reorganization.

Therefore, this finding has a cross-cutting aspect in the area of human performance associated with change in management because the licensee failed to effectively transition the switchyard point-of-contact position through the staff reorganization [H.3](Section 1R13).

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, involving the licensees failure to correctly translate the design basis for the diesel fuel oil transfer system into specifications, drawings, procedures, and instructions. Specifically, the station confirmed through calculations that the emergency diesel generator fuel oil transfer system could not perform its seven day mission time to provide filtered fuel oil to emergency diesel generators at the Technical Specification maximum allowable value for fuel oil particulates, with the number of filters available on site.

In response to this issue, the licensee verified that the diesel fuel oil particulate level had never approached the technical specification limit; therefore, operability of the emergency diesel generators was never challenged. This finding was entered into the licensees corrective action program as Condition Report CR-RBS-2013-04780.

The failure to translate into specifications, drawings, procedures, and instructions, the diesel fuel oil transfer system limitations to perform its seven day mission time associated with the number of filters available on site was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with

Mitigating Events Cornerstone attribute of Design Control, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In accordance with Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the finding screened as having very low safety significance (Green)because it was not a design or qualification deficiency that represented a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk-significant due to seismic, flooding, or severe weather. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance (Section 4OA2).

Green.

The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Action, for failure to promptly correct a degraded voltage regulator in the Division 3 emergency diesel generator. Specifically, the station failed to use operating experience in a timely manner, which resulted in the lockout of the Division 3 emergency diesel generator output breaker. The station replaced the voltage regulator to correct this condition. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2013-06789.

The inspectors determined that the failure of the licensee to promptly correct the cause of erratic KVAR/voltage output from the Division 3 emergency diesel generator is a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it is associated with the Mitigating Systems Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors used the NRC Inspection Manual 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because it involved a potential loss of one train of safety-related equipment for longer than the technical specification allowed outage time.

The total exposure period was 20.3 days. The allowed outage time was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The analyst determined the change to the core damage frequency was 1.6E-7/year (Green).

The finding was of very low safety significance (Green). The dominant core damage sequences included loss of offsite power events leading to station blackout. Equipment that helped mitigate the risk included recovery of an emergency diesel generator or offsite power. The finding was not a significant contributor to the large early release frequency (LERF). The cause of the performance deficiency appeared to be the ineffective use of industry operating experience. Therefore, the finding had a cross-cutting aspect in the area of problem identification and resolution, associated with the operating experience component because the licensee failed to systematically and effectively collect, evaluate, and implement relevant internal and external operating experience in a timely manner [P.5]

(Section 4OA2).

PLANT STATUS

The River Bend Station began the inspection period at 100 percent reactor power. It departed from full power as follows:

• On January 31, 2014, operators reduced power to approximately 70 percent to perform a planned rod sequence exchange, turbine valve testing, a partially withdrawn rod operability test, and control rod scram time testing. The licensee returned the plant to full power on January 31.

The plant remained at 100 percent reactor power for the remainder of the inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On January 27, 2014, the inspectors completed an inspection of the stations readiness for impending adverse weather conditions. The inspectors reviewed plant design features, the licensees procedures to respond to an ice storm, and the licensees planned implementation of these procedures. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant.

These activities constituted one sample of readiness for impending adverse weather conditions, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

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

• February 3, 2014, reactor plant component cooling water system

• February 4, 2014, control building chilled water system

• February 11, 2014, high pressure core spray during reactor core isolation cooling outage The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the systems or divisions were correctly aligned for the existing plant configuration.

These activities constituted three partial system walk-down samples, as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on five plant areas important to safety:

• January 14, 2014, control building, 98-foot elevation, and emergency diesel generator A room

• January 15, 2014, turbine building, 67-foot elevation, and auxiliary building D tunnel

• January 22, 2014, control building, 116-foot elevation

• February 27, 2014, diesel generator building, 70-foot and 98-foot elevations

• March 12, 2014, normal switchgear building, 98-foot and 123-foot elevations For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.

These activities constituted five quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

On February 14, 2014, the inspectors completed an inspection of the stations ability to mitigate flooding due to internal causes. After reviewing the licensees flooding analysis, the inspectors chose one plant area containing risk-significant structures, systems, and components that was susceptible to flooding:

• D tunnel (Operating Experience Smart Sample 2007-02, Flooding Vulnerabilities Due to Inadequate Design and Conduit/Hydrostatic Seal Barrier Concerns)

The inspectors reviewed plant design features and licensee procedures for coping with internal flooding. The inspectors walked down the selected area to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether operator actions credited for flood mitigation could be successfully accomplished.

These activities constitute completion of one flood protection measures sample, as defined in Inspection Procedure 71111.06.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

On February 28, 2014, the inspectors completed an inspection of the readiness and availability of risk-significant heat exchangers. The inspectors reviewed the data from five performance tests for the control building chillers B and D evaporators and condensers and observed the licensees inspection and the material condition of other control building chiller heat exchanger internals. Additionally, the inspectors verified that the control building chillers were correctly categorized under the Maintenance Rule and were receiving the required maintenance.

These activities constitute completion of one heat sink performance annual review sample, as defined in Inspection Procedure 71111.07.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for failing to verify acceptable performance of the control building chillers. Specifically, station personnel failed to evaluate the increase in instrument uncertainty and the increase in the design basis accident heat load in a calculation used to determine the thermal performance for control building chillers.

Description.

Technical Specification surveillance requirement 3.7.3.1 requires station personnel verify that each control room air conditioning subsystem has the capability to remove the assumed heat load. To satisfy this requirement, in part, the station developed Calculation G13.18.2.1*078, Evaluation of Control Building Chillers Performance Test Data. Using the data from this performance calculation, station personnel established surveillance test Procedure STP-410-3601, Performance Monitoring Program for Control Building Chiller HVK-CHL1A, and a similar procedure for each of the remaining three control building chillers. The inspectors reviewed data from the past five surveillance tests for each chiller and identified a wide variation in the ratio of condenser tons to evaporator tons, evaporator to compressor horsepower, and condenser to compressor horsepower. These variations resulted primarily from the uncertainty in using thermocouples to measure service water and chill water temperatures entering and leaving the chillers condensers and evaporators.

In 2003, the River Bend Station revised STP-410-3601 to allow the use of thermocouples to measure the temperature of service water and chill water entering and leaving chiller 1A. The procedure change review form stated that the test data is collected using calibrated measurement and test equipment of sufficient accuracy to demonstrate acceptable chiller performance. The inspectors noted that the performance calculation (G13.18.2.1*078) used temperature data derived from resistance temperature devices (RTDs) that were more accurate than thermocouples.

Station personnel reviewed the manufacturers instrument tolerance values for the thermocouples and concluded the tolerances were greater than those of the RTDs, and were so large that the calculated accident loads plus instrument uncertainty could exceed the design capability of the control building chillers. To assess current operability of the control building chillers, the licensee used the smaller as-left instrument uncertainty values determined by the stations measurement and test program.

While resolving the inspectors concerns about instrument uncertainty, station personnel discovered that the worst case control building heat load had increased in December 2009, from 144.1 tons to 158.98 tons as discussed in Calculation G13.18.2.1*059, Control Building Heat Load Evaluation during LOCA, Revision 3. However, in December 2009, station personnel did not update and evaluate the performance calculation to determine whether the increased loading could be met by the control building chillers. Instrument uncertainty and increased accident heat load together reduced the control building chillers operating margin to 0.16 tons. The inspectors concluded that the station personnel failed on two accounts to use commensurate design control measures to determine whether the capacity of the control building chillers was sufficient to remove the design basis heat loads. Specifically, the station did not evaluate the decrease in temperature accuracy in measuring chill water and service water temperatures, evaluate the increase in control building heat loads in the performance calculation, and whether the acceptance criteria in the surveillance test procedures was still acceptable. The stations corrective actions included: reanalyzing the performance calculation to account for the increased chiller loads and instrument uncertainty; revising the acceptance criteria used in the surveillance test procedures; and revising the surveillance test procedures to use instruments of similar or better accuracy than the instruments used in the performance calculation.

Analysis.

The failure to evaluate the decrease in temperature accuracy in measuring chill water and service water temperatures, and evaluate the increase in control building heat loads in the performance calculation to ensure that the chiller capacity acceptance criteria stated in the surveillance test procedures was acceptable, was a performance deficiency. The inspectors used Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, to determine that the performance deficiency was more than minor, and therefore a finding, because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, station personnel used incorrect assumptions in the performance calculation that created a reasonable doubt of the operability of the Divisions 1 and 2 control building chillers. In addition, the potential existed that in future testing the as-left instrument uncertainty plus the design basis load could exceed the chillers load capacity. The inspectors determined the finding to be of very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, dated June 19, 2012. Using Exhibit 2, which contains the screening questions for the Mitigating Systems Cornerstone, the inspectors determined that the finding screened as Green because: it was not a design or qualification deficiency; it did not represent a loss of system or function; it did not represent the loss of function for any technical specification system, train, or component beyond the allowed technical specification outage time; and it did not represent an actual loss of function of any non-technical specification trains of equipment designated as high safety-significant and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The cause of the performance deficiency was station personnel failure to follow the process for design control and design input verification. However, these performance deficiencies occurred in 2003 and 2009, and therefore, are not indicative of current licensee performance.

Enforcement.

Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criteria III, Design Control, requires the license to establish measures to assure that applicable regulatory requirements and design bases be correctly translated into specifications and that design control measures be provided for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program. Contrary to the above, from June 10, 2003, until November 14, 2013, the licensee did not establish measures to assure that the applicable regulatory requirements were verified correctly and translated into the thermal performance design basis of the control building chillers. Because of the very low safety significance, and because the issue is documented in the stations corrective action program as Condition Report CR-RBS-2013-07133, this violation is being treated as a non-cited violation in accordance with Section 2.3.2.a of the Enforcement Policy:

NCV 05000485/2014002-01, Failure to Maintain Design Control for Performance Testing of the Control Building Chillers.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On February 25, 2014, the inspectors observed an evaluated simulator scenario performed by an operating crew. The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors also assessed the modeling and performance of the simulator during the requalification activities.

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 Review of Licensed Operator Performance

a. Inspection Scope

On March 18, 2014, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened risk due to planned station blackout diesel testing and auxiliary building damper repairs.

In addition, the inspectors assessed the operators adherence to plant procedures, including the conduct of operations procedure 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.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed two instances of degraded performance or condition of safety-related structures, systems, and components:

• February 26, 2014, normal service water system

• March 13, 2014, component cooling water primary system The inspectors reviewed the extent of condition of possible common cause structure, system, and component failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the structures, systems, and components. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.

These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed three risk assessments performed by the licensee prior to changes in plant configuration and the risk management actions taken by the licensee in response to elevated risk:

• March 18, 2014, Division 2 residual heat removal out-of-service during surveillances

• March 20, 2014, swap of reactor protection system power from normal to alternate with ongoing maintenance on main transformer number 1

• March 21, 2014, replacement of circulating water system pump P1A and excavation in the Fancy Point switchyard The inspectors verified that these risk assessments were performed timely and in accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant procedures. The inspectors reviewed the accuracy and completeness of the licensees risk assessments and verified that the licensee implemented appropriate risk management actions based on the result of the assessments.

The inspectors also observed portions of two emergent work activities that had the potential to cause an initiating event:

• February 13, 2014, emergent switchyard work - 500kV auto-transformer inspections and maintenance

• March 11, 2014, emergent switchyard work - makeup water system power line poles erected in switchyard The inspectors verified that the licensee appropriately developed and followed a work plan for these activities. The inspectors verified that the licensee took precautions to minimize the impact of the work activities on unaffected structures, systems, and components.

These activities constitute completion of five maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

Failure to Assess and Manage Risk for Electrical Switchyard Impacting Maintenance

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specifically, on February 12, 2014, the licensee failed to correctly assess and manage the increase in risk associated with work in the stations Fancy Point electrical switchyard.

Description.

On February 10, 2014, Entergy transmission requested permission to perform preventative maintenance work and transformer repairs in the Fancy Point switchyard. On the following day, electrical maintenance personnel submitted an online emergent work addition impact statement to add the work to the schedule per operations Procedure OSP-0048, Switchyard, Transformer Yard, and Sensitive Equipment Controls. The impact statement described the work as testing and inspection of four 230kV breakers and nitrogen leak repairs on the 230/500kV Auto Transformer. The impact statement detailed that the 230/500kV Auto Transformer would be removed from service and the 500kV yard would be de-energized. The impact statement also stated that a man lift would be required for the Auto Transformer repairs and that the man lift will not enter the 230kV yard. On February 12, 2014, work management added the emergent work to the schedule and performed a risk evaluation using the breaker work only designator in the equipment out of service (EOOS) risk software. The subsequent quantitative EOOS risk for the day was Green. As a result, station operations personnel authorized Entergy Transmission to work in the switchyard.

The inspectors took note of the emergent work activity during the daily plant status brief and requested further information on the risk impact evaluation. The inspectors reviewed the impact statement and concluded that the risk impact did not clearly indicate the details of the work being performed. The inspectors also reviewed the control room logs and found that the operators failed to document that switchyard work was authorized; although, work had already begun. An independent EOOS evaluation of the work impact, based on the limited description on the impact statement, showed that the risk category for the work should be Yellow. The inspectors requested permission to enter the switchyard and upon arrival noted heavy man-lift cranes and three bucket trucks in the 230kV switchyard. Station Administrative Procedure ADM-0096, Risk Management Program Implementation and On-Line Maintenance Risk Assessment, defined a switchyard work impact designator of Heavy Equipment, when there is work involving the use of heavy equipment, including boom or bucket trucks, in the vicinity of the switchyard. In addition, the procedure required that the OSP-0048 Impact Statement must provide details of the specific activity with adequate details to ensure a low level risk for loss of offsite power. The procedure also required that flagging for acceptable work areas needed to be established to ensure work activities were confined to approved areas. The inspectors determined that the impact statement did not adequately detail the activities performed in the switchyard and that the risk evaluation performed failed to identify the work as Heavy Equipment, which would change the EOOS impact to a Yellow risk condition. Station procedures referred to the station point-of-contact as an individual responsible for coordination of switchyard activities with the transmission organization. The inspectors interviewed station personnel and found that the station had been without a switchyard point-of-contact for a period of approximately four months. The station failed to fill the position due to changes occurring within the stations staffing reorganization effort, referred to as Entergy Human Capital Management. Station corrective actions included reevaluating risk for the time period and issuing interim guidance on planning and evaluating the risk of switchyard work.

The station planned to revise the OSP-0048 procedure to include the interim guidance.

Analysis.

The failure to perform an adequate risk assessment and implement appropriate risk management actions was a performance deficiency. The inspectors used IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, to determine that the performance deficiency was more than minor, and therefore a finding, because it was associated with the Mitigating Systems Cornerstone attribute of protection against external factors and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

Manual Chapter 0609, Attachment 4, directs the inspector to Appendix K for Maintenance Risk Assessment issues. The inspectors used NRC IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, dated May 19, 2005. The licensee provided Risk Assessment Related to CR-RBS-2014-1220/-1221 Switchyard Work, dated March 31, 2014. The exposure period was 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />. The licensee identified the risk deficit as 2.6E-8/year.

Since the risk deficit was less than 1E-6, the finding was of very low safety significance (Green). This finding was not significant to the large early release frequency. The apparent cause of the finding involved the failure to fill a position to act as a point of contact for switchyard work management for a period of four months due to the stations staffing reorganization. Therefore, this finding has a cross-cutting aspect in the area of human performance associated with change management because the licensee failed to effectively transition the switchyard point-of-contact position through the staff reorganization [H.3].

Enforcement.

Title 10 CFR 50.65(a)(4), states in part, that before performing maintenance activities (including, but not limited to surveillance, postmaintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

Contrary to the above, on February 12, 2014, operations and work control personnel failed to adequately assess and manage the increase in risk associated with maintenance activities in the Fancy Point electrical switchyard. Since this violation is of very low safety significance and has been entered into the licensees corrective action program as Condition Report CR-RBS-2014-01221, it is being treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000458/2014002-02, Failure to Assess and Manage Risk for Electrical Switchyard Impacting Maintenance.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed four operability determinations that the licensee performed for degraded or nonconforming structures, systems, and components:

• February 20, 2014, operability determination of safety-related standby service water valves wetted during an inadvertent actuation of sprinkler in the fire suppression system (CR-RBS-2014-00798)

• March 21, 2014, operability determination evaluating the failure of the Division 3 diesel to start (CR-RBS-2013-06131)

• March 21, 2014, operability determination evaluating the fluctuations in the Division 2 emergency diesel generator voltage during the manipulation of the emergency diesel generator KVAR switch (CR-RBS-2013-07199)

• March 21, 2014, operability determination for low bypass electro-hydraulic control pressure (CR-RBS-2013-06992)

The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded structures, systems, and components to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded structures, systems, and components.

These activities constitute completion of four operability and functionality review samples, as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed four post-maintenance testing activities that affected risk-significant structures, systems, and components:

• February 21, 2014, WO-00372105, HVK-CHL1C Failed Its Motor Current Calibration PM Task

• March 5, 2014, WO-00376113, APRM D Troubleshooting and Retest

• March 6, 2014, WO-00366214, Perform Troubleshooting of Diesel Trip

• March 17, 2014, WO-52341955, SWP-FN1B - Inspect, Lubricate, SWP-FN1B, 1D, 1F, 1H, 1K The inspectors reviewed licensing- and design-basis documents for the structures, systems, and components, and the maintenance and post-maintenance test procedures.

The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected structures, systems, and components.

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed six risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the structures, systems, and components were capable of performing their safety functions:

In-service test:

• January 23, 2014, STP-256-6322, Revision 028, Division II Service Water Recirculation Pump and Valve Operability Test Reactor coolant system leak detection test:

• March 21, 2014, STP-207-4250, Revision 16, RCS-Identified and Unidentified Leakage Detection System Other surveillance tests:

• February 12, 2014, STP-251-3205, Revision 16, Diesel Fire Pump Operational Test

• February 26, 2014, STP-309-0203, Revision 320, Division 3 Diesel Generator Operability Test

• March 12, 2014, STP-051-4267, Revision 15, ECCS-Drywell Pressure-High Channel Calibration and Logic System Functional Test (B21-N094B:

B21N694B)

• March 17, 2014, STP-309-0202, Revision 324, Diesel Generator Division 2 Operability The inspectors verified that these tests met technical specification requirements, that the licensee performed these tests in accordance with their procedures, and that the results of these tests satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected structures, systems, and components following testing.

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

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors observed an emergency preparedness drill on March 6, 2014, to verify the adequacy and capability of the licensees assessment of drill performance. The inspectors reviewed the drill scenario, observed the drill from the simulator and the off-site command post, and attended the post-drill critique. The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the licensee in the post-drill critique and entered into the corrective action program for resolution.

These activities constitute completion of one emergency preparedness drill observation sample, as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed licensee performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). During the inspection, the inspectors interviewed licensee personnel and reviewed licensee performance in the following areas:

• Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements

• ALARA work activity evaluations/postjob reviews, exposure estimates, and exposure mitigation requirements

• The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies

• Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas

• Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection These activities constitute completion of one sample of occupational ALARA planning and controls, as defined in Inspection Procedure 71124.02.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

The inspectors verified the accuracy and operability of the licensees personnel monitoring equipment, verified the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent, and verified that the licensee was appropriately monitoring occupational dose. The inspectors interviewed licensee personnel, walked down various portions of the plant, and reviewed licensee performance in the following areas:

• External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters

• The technical competency and adequacy of the licensees internal dosimetry program

• Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment

• Audits, self-assessments, and corrective action documents related to dose assessment since the last inspection These activities constitute completion of one sample of occupational dose assessment, as defined in Inspection Procedure 71124.04.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

The inspectors evaluated whether the licensee maintained gaseous and liquid effluent processing systems and properly mitigated, monitored, and evaluated radiological discharges with respect to public exposure. The inspectors verified that abnormal radioactive gaseous or liquid discharges and conditions, when effluent radiation monitors were out-of-service, were controlled in accordance with the applicable regulatory requirements and licensee procedures. The inspectors verified that the licensees quality control program ensured radioactive effluent sampling and analysis adequately quantified and evaluated discharges of radioactive materials. The inspectors interviewed licensee personnel and reviewed or observed the following items:

• Identified leakage or spill events and entries made into 10 CFR 50.75(g) records, if any, and associated evaluations of the extent of the contamination and the radiological source term

• Offsite notifications and reports of events associated with spills, leaks, and groundwater monitoring results These activities do not constitute completion of one sample of radioactive gaseous and liquid effluent treatment, as defined in Inspection Procedure 71124.06.

b. Findings

No findings were identified. However, the inspectors reviewed the details of an event notification made to the NRC. On January 7, 2014, licensee representatives identified a leak at a rate of approximately 5 gallons per minute from the circulating water blowdown line. They determined that the leak occurred when the bonnet of a blowdown line gate valve (RWS-0339-V8) ruptured due to sub-freezing temperatures at the site. This caused a circulating water/radwaste discharge mixture to leak onto the ground. The radioactive water leak was approximated to have been ongoing for about 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. Thus, licensee representatives estimated the spill was between 100 and 1200 gallons. The radioactive water was sampled and a maximum tritium (H-3) level of 4584 pCi/L was identified. Licensee representatives stated the leak did not reach any storm drain and they were able to isolate the leaking water by securing the circulating water system blowdown. Licensee representatives confirmed they will continue to monitor the issue with their current monitoring wells, which are included in their groundwater program.

In accordance with 10 CFR 50.72(b)(2)(xi), licensee representatives made a report to the NRC on January 8, 2014, per NEI 07-07 guidance, because they determined the leakage exceeded the 100 gallon threshold for voluntary reporting. This was documented as Event Notification 49701. Licensee representative also made notifications to state (i.e., the Louisiana Department of Environmental Quality). The RWS-0339-V8 valve has been repaired and the circulating water blowdown has been returned to service. This issue was documented in the licensees corrective action program as CR-RBS-2014-00115.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours (IE01)

a. Inspection Scope

The inspectors reviewed licensee event reports for the period of January 2013 through December 2013 to determine the number of scrams that occurred. The inspectors compared the number of scrams reported in these licensee event reports to the number reported for the performance indicator. Additionally, the inspectors sampled monthly operating logs to verify the number of critical hours during the period. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.

These activities constituted verification of the unplanned scrams per 7000 critical hours performance indicator for Unit 1, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Unplanned Power Changes per 7000 Critical Hours (IE03)

a. Inspection Scope

The inspectors reviewed operating logs and corrective action program records for the period of January 2013 through December 2013 to determine the number of unplanned power changes that occurred. The inspectors compared the number of unplanned power changes documented to the number reported for the performance indicator. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.

These activities constituted verification of the unplanned power changes per 7000 critical hours performance indicator for Unit 1, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.3 Unplanned Scrams with Complications (IE04)

a. Inspection Scope

The inspectors reviewed the licensees basis for including or excluding in this performance indicator each scram that occurred between January 2013 and December 2013. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.

These activities constituted verification of the unplanned scrams with complications performance indicator for Unit 1, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.

One such review was one that the inspectors had previously observed and reviewed, portions of Surveillance Test Procedure STP-309-6301, Division 1 EDG Fuel Oil Transfer Pump and Valve Operability Test, Revision 17.

Specific documents reviewed during this inspection are listed in the Attachment 1 of this report.

b. Findings

Failure to Adequately Control Design Basis Documents for the Emergency Diesel Generators

Introduction.

The inspectors identified a Green, non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, involving the licensees failure to correctly translate the design basis for the diesel fuel oil transfer system into specifications, drawings, procedures, and instructions. Specifically, the station confirmed through calculations that the emergency diesel generator fuel oil transfer system could not perform its seven day mission time to provided filtered fuel oil to emergency diesel generators at the Technical Specification maximum allowable value for fuel oil particulates, with the number of filters available on site.

Description.

The River Bend Station is equipped with three safety-related, alternating current (AC) electrical distribution systems, Divisions 1, 2, and 3, and three divisional emergency diesel generators. Any two of the three emergency diesel generators have the capability to safety shut down and cool down the reactor. Diesel fuel oil is pumped from the main fuel oil storage tank, using a fuel oil transfer pump, through inline filters, and then to the fuel oil day tank. The fuel oil transfer pump automatically refills the fuel oil day tank as needed. The fuel oil transfer system filters perform an initial cleaning of the fuel, including particulate, as it is pumped from the storage tank to the day tank.

These filters are arranged in a duplex pair, so that the fuel oil flow path can be switched from one filter to the other filter while the pump is in operation. Fuel oil from the day tank is gravity fed to the diesel engine inlet connection, where is passes through a strainer and fine filter prior to the fuel injection equipment.

Technical Specification 5.5.9, Diesel Fuel Oil Testing Program, requires sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish, in part, that the total particulate concentration of the fuel oil in the storage tanks is less than 10 milligrams per liter when tested every 31 days in accordance with ASTM D-2276, Method A-2 or A-3.

Updated Safety Analysis Report Section 7.3.1.1.11, Standby Power Support Systems, states that the purpose of the diesel generator fuel oil storage and transfer system is to provide an adequate fuel oil supply for seven days of continuous operation of each diesel generator at its rated capacity.

On April 10, 2013, during the performance of Surveillance Test Procedure STP-309-6301, Division I EDG Fuel Oil Transfer Pump and Valve Operability Test, Revision 17, the test was aborted because the in-service diesel fuel oil transfer system filter, EGF-STRD, exceeded the procedure limitation of 10 pounds per square inch discharge pressure, and the other filter on the Division I emergency diesel generator duplex pair, EGF-STRA, had been previously tagged out of service due to being partially clogged. The filters were changed and the surveillance test was completed satisfactory.

After this test was completed, the inspectors questioned the licensee about the design basis requirements associated with the number of filters needed to support the emergency diesel generator mission time of seven days of continuous operation of each diesel generator at its rated capacity. The licensee was unable to produce any design basis documents to address this question. At that time the site maintained one to three filters on site for the three emergency diesel generators.

On July 19, 2013, the licensee approved Engineering Change EC-45627, Engine Run Time to Load a Diesel Fuel Transfer Pump Filter. This evaluation identified that the maximum design loaded condition of the fuel oil filters is 25 pounds per square inch differential pressure at a flow rate of 20 gallons per minute. Also, the vendor recommended that the particulate loading of the filters should not exceed 240 grams of particulate. Using the technical specification limit of 10 milligrams per liter of particulate, the licensee calculated that a fuel oil filter would reach design loaded conditions within 25.15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />. The licensee generated Condition Report CR-RBS-2013-04780 which identified that to support the seven day fuel oil mission time of the emergency diesel generators at the technical specification fuel oil particulate limit, six or more spare filters per diesel generator would be required.

Analysis.

The failure to translate into specifications, drawings, procedures, and instructions, the diesel fuel oil transfer system limitations to perform its seven day mission time associated with the number of filters on site was a performance deficiency.

Specifically, the station confirmed through calculations that at the Technical Specification maximum value for fuel oil particulates the available supply of fuel oil transfer system duplex filters could not maintain the operation of any one emergency diesel generator for the fuel oil transfer system mission time of seven days. The finding was more than minor, because it was associated with Mitigating Events Cornerstone attribute of Design Control, and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, prior to July 19, 2013, the licensee did not procedurally specify or require to have available the number of filters required to support operability of the emergency diesel generators. In accordance with IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating Systems Screening Questions, the issue screened as having very low safety significance (Green) because it was not a design or qualification deficiency that represented a loss of operability or functionality; did not represent an actual loss of safety function of the system or train; did not result in the loss of one or more trains of non-technical specification equipment; and did not screen as potentially risk significant due to seismic, flooding, or severe weather. The inspectors determined that this finding did not have a cross-cutting aspect because the most significant contributor did not reflect current licensee performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, Measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. The design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, prior to July 19, 2013, the licensee failed to establish measures to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions and failed to check the adequacy of the design. Specifically the licensee failed to adequately verify by analysis the number of emergency diesel generator fuel oil transfer system filters required to be onsite to meet the diesel fuel oil mission time of 7-days. In response to this issue, the licensee verified that the diesel fuel oil particulate level had never approached the technical specification limit; therefore, operability of the emergency diesel generators was never challenged. This finding was entered into the licensees corrective action program as Condition Report CR-RBS-2013-04780. Because this finding is of very low safety significance and has been entered into the licensees corrective action program, this violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy:

NCV 05000458/2014002-03, Failure to Adequately Control Design Basis Documents for the Emergency Diesel Generators.

.2 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected one issue for an in-depth follow-up related to the October 2013 KVAR swings on Division 3 emergency diesel generator, CR-RBS-2013-06832. The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors assessed whether the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.

These activities constitute completion of one annual follow-up sample, as defined in Inspection Procedure 71152.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for failure to promptly correct a degraded voltage regulator in the Division 3 emergency diesel generator. Specifically, the station failed to use operating experience in a timely manner, which resulted in the lockout of the Division 3 emergency diesel generator output breaker.

Description.

The Division 3 emergency diesel generator provides dedicated safety-related power to electrical loads that are necessary for operation of Division 3 equipment including the high pressure core spray pump. On October 28, 2013, operators lowered Division 3 diesel generator kilovolt-amperes reactive (KVAR) to zero, to unload the diesel generator when, without operator action, generator output increased to 200 KVARs. Operators readjusted KVARs back to zero, but generator amperage to the Division 3, 4160 VAC bus immediately started to rise. At approximately 350 amps output, the generator output breaker tripped from the loss of generator excitation and generator phase overcurrent. Troubleshooting found the R4 stability potentiometer in the voltage regulator stability circuitry had failed.

On March 6, the inspectors reviewed the voltage and reactive loads changes associated with operating the Division 3 emergency diesel generator. The inspectors reviewed the apparent cause and contributing causes identified by the licensee for the voltage regulator failure in October 2013. That cause evaluation identified that the Division 3 voltage regulator had exceeded its life expectancy in 2008 and that the conduct of work planning and preparation had not identified or provided long lead time parts in time so that the parts were available when the preventive maintenance was planned to begin.

Therefore, the preventive maintenance was not performed prior to failure of the voltage regulator.

The inspectors noted that the apparent cause evaluation did not identify: 1) that troubleshooting activities in a two-year period had failed to correct a degraded condition associated with varied generator output voltage and reactive load conditions and 2) that the station did not perform periodic maintenance on the voltage regulator as recommended by industry operating experience. The inspectors concluded that the station had missed a learning opportunity to prevent recurrence of degraded generator output voltage and reactive loads.

From December 2009 through October 2013, nine condition reports documented unexpected or erratic KVAR/voltage output while loading or unloading the Division 3 emergency diesel generator. To control KVARs and generator voltage, maintenance replaced the R1 potentiometer in the generators voltage regulator on December 22, 2009, December 22, 2011, and June 20, 2012. Seven condition reports documented KVAR voltage changes following the R1 replacement in December 2011. Not until October 30, 2013, when maintenance identified a failed R4 potentiometer, did the station perform maintenance, test, or troubleshoot the R4 potentiometer. The station did not identify any other component that would eliminate or reduce the noted KVAR swings.

The Division 3 emergency diesel generator voltage regulator, Basler model SR8A, is designed to maintain a constant generator terminal voltage for emergency operation.

The voltage regulator also controls KVAR output from the generator when it is in parallel with the grid. The Electric Power Research Institute (EPRI) Technical Report 1011109, Basler SR8A Voltage Regulators for Emergency Diesel Generators, contains information to help utilities address emergency diesel generator voltage regulator issues.

Chapter 8 of this technical report is titled, Failures and Problems. The key technical point of Chapter 8 states, One of the most common problems with the SR8A voltage regulator is erratic performance of the R1, R3, or R4 potentiometers. R1, R3, and R4 have been problematic at a number of plants. The problem is typically a case of having a dirty potentiometer which can be caused by oxidation of the resistive element or fouling with foreign material (dust or dirt, for example). Problems with these potentiometers are indicated by voltage or VAR swings. Chapter 11, Preventive Maintenance, states that, It is also advisable to check the condition of the R1, R3, and R4 potentiometers every two years by measuring resistance with an analog meter. For the R1 voltage adjust potentiometer, resistance should be checked while it is run end-to-end, verifying a smooth resistance change. R3 and R4 should be checked once the emergency diesel generator is shut down by measuring resistance with an analog meter while tapping on the potentiometers. On October 30, 2013, the Division 3 voltage regulator was approximately 35 years old.

During discussions with plant personnel, the inspectors determined that the station did not:

1. Perform periodic maintenance on the voltage regulator 2. Effectively use EPRI Technical Report 1011109 to identify or correct unexpected/unwanted Division 3 emergency diesel generator KVAR/voltage changes 3. Correct the degraded voltage regulator after December 2011 by replacing the R1 potentiometer Erratic KVAR output is significant because the KVAR changes in the synchronous mode would become voltage changes in the isochronous mode which would occur during a design basis accident. The magnitude of the KVAR swings reported in October 2013 (CR-RBS-2013-06832) indicated that the installed voltage regulator could not provide reliable, regulated voltage within suitable operating limits for the generator or the Division 3 motors on the safety bus. The stations corrective actions included replacing the voltage regulator.

Analysis.

The inspectors determined that the failure of the licensee to promptly correct the cause of erratic KVAR/voltage output from the Division 3 emergency diesel generator was a performance deficiency. The performance deficiency was more than minor, and therefore a finding, because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

Specifically, the magnitude of the KVAR swings reported in October 2013 (CR-RBS-2013-06832) indicate that the installed voltage regulator could not provide reliable regulated voltage within suitable operating limits for the generator or the Division 3 motors on the safety bus. The inspectors used the NRC IMC 0609, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Appendix A, Exhibit 2, Mitigating Systems Screening Questions. The finding required a detailed risk evaluation because it involved a potential loss of one train of safety-related equipment for longer than the technical specification allowed outage time.

The total exposure period was 20.3 days. The analyst determined the exposure period as follows:

The diesel generator failed during surveillance testing on October 28, 2013.

The prior surveillance (where the emergency diesel generator maintained its safety function) was September 22, 2013. The time between surveillances was 36 days. Since the exact time of the failure was not known, the analyst assumed a T/2 exposure period, consistent with the NRCs Risk Assessment of Operational Events Handbook, Revision 2, Section 4.0, Mission Time Modeling. The T/2 portion of the exposure period was 18 days.

Following the failure, the licensee performed troubleshooting and repairs. This period lasted 56 hours6.481481e-4 days <br />0.0156 hours <br />9.259259e-5 weeks <br />2.1308e-5 months <br />.

The total exposure period was the T/2 duration plus the repair time = 20.3 days.

The analysts performed simplified calculations to determine the change to the core damage frequency (delta-CDF) for the failure. The analyst used the River Bend Station Standardized Plant Analysis Risk (SPAR) model, Revision 8.20, with a truncation limit of 1E-11. The incremental conditional core damage probability (ICCDP) for a failure of the Division III diesel generator was 6.4E-6 for an entire year of exposure. Considering the exposure time, the delta-CDF was:

Delta-CDF (internal events) = 20.3/365

• 6.4E-6 = 1.5E-7/year External Events: To identify the external event loss of offsite power initiators, the analyst reviewed the River Bend Station Individual Plant Examination of External Events (IPEEE), dated June 30, 1995. The IPEEE specified that the 1975 standard review plan criteria were met for high winds, floods, transportation accidents, and nearby facility accidents, so those events were not considered further. The weather-related loss of offsite power initiator was already included in the SPAR model. The remaining accident initiators included seismic and fire.

Fires: The fire events of interest included those that could initiate a loss of offsite power.

The licensees IPEEE screened out most fire areas as being non-risk-significant. The IPEEE identified one risk important area where a fire could result in a loss of offsite power - Fire Area C-25, the main control room.

The IPEEE assumed that fires in non-divisional cabinets could result in a loss of offsite power. The overall control room fire frequency was 9.5E-3/year and the non-divisional fire fraction was 0.455. Therefore, the control room fire loss of offsite power frequency was 9.5E-3

• 0.455 = 4.3E-3/year. The analyst substituted this frequency in the SPAR model as a surrogate for the plant centered loss of offsite power initiating event frequency. The analyst ran the model, as before, to determine the fire induced delta-CDF associated with the Division III diesel failure. The analyst solved only the plant-centered loss of offsite power sequences. The change to the core damage frequency from fires was:

Delta-CDF (fires) = 1.7E-7

• 20.3/365 = 9.5E-9/year Seismic: The analyst performed a simplified bounding analysis to address seismic contributors. The analyst referenced the NRCs Risk Assessment of Operational Events Handbook, Revision 1.03, to determine the seismic loss of offsite power initiating event frequency, which was 1.5E-5/year. Seismic-initiated loss of offsite power events are not considered recoverable.

The analyst determined the conditional core damage probability for a seismically induced non-recoverable loss of offsite power coincident with the failure of the Division 3 emergency diesel generator. The CCDP was 7.9E-3. The bounding delta-CDF for a 20.3-day exposure period was:

Delta-CDF (seismic) = 1.5E-5

• 7.9E-3

• 20.3/365 = 6.6E-9/year Total Delta-CDF = 1.5E-7/year + 9.5E-9/year + 6.6E-9/year = 1.6E-7/year The dominant core damage sequences included loss of offsite power events, leading to station blackout. Equipment that helped mitigate the risk included recovery of an emergency diesel generator or offsite power.

LERF: To address the contribution to the LERF, the analyst used NRC IMC 0609, Appendix H, Containment Integrity Significance Determination Process, dated May 6, 2004. For boiling water reactors (BWR-6 with a Mark 3 containment), the failure of the Division III emergency diesel generator was a potential LERF contributor. For the LERF analysis, the analyst used the Risk-Informed Inspection Notebook for River Bend Station (RBS) Unit 1, Revision 2.1a. The analyst identified the LERF factors for the applicable loss of offsite power sequences. In a few instances, the LERF factor was 0, but in most cases the LERF factor was 0.2. The analyst conservatively used the 0.2 factor for all sequences. The change to the LERF was therefore:

Delta-LERF = 0.2

• Delta-CDF = 0.2

• 1.6E-7/year = 3.2E-8/year Since the change to the LERF was less than 1E-7/year, the finding was of very low safety significance for LERF.

The cause of the performance deficiency appeared to be the ineffective use of industry operating experience. Therefore, the finding had a cross-cutting aspect in the area of problem identification and resolution associated with operating experience because the licensee failed to systematically and effectively collect, evaluate, and implement relevant internal and external operating experience in a timely manner [P.5].

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Actions, requires, in part, measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, between December 22, 2011, and October 30, 2013, the licensee failed to promptly correct a degraded voltage regulator associated with Division 3 emergency diesel generator ability to provide reliable regulated voltage to the Division 3 safety bus.

Since this violation was of very low safety significance and was documented in the licensees corrective action program as Condition Report CR-RBS-2013-06789, it is being treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 05000458/2014002-04, Failure to Promptly Correct a Degraded Emergency Diesel Generator Voltage Regulator.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On January 16, 2014, the inspectors presented the radiation safety inspection results to Mr. R. Gadbois, General Manager, Plant Operations, and other members of the licensee staff.

The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

On April 15, 2014, the inspectors presented the integrated inspection results to Mr. E. Olson, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Blankenship, Supervisor, Radiation Protection

D. Burnett, Manager, Emergency Preparedness

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

M. Chase, Manager, Training

J. Clark, Manager, Licensing

C. Coleman, Manager, Engineering Programs & Components

F. Corley, Manager, Design Engineering

R. Creel, Superintendent, Plant Security

L. Dautel, ALARA/Technical Support Supervisor, Radiation Protection

T. Evans, Director, Nuclear Safety Assurance

M. Feltner, Manager, Production

M. Ferrentelli, Manager, Maintenance

A. Fredieu, Manager, Outage

R. Gadbois, General Manager, Plant Operations

T. Gates, Assistant Operations Manager - Shift

K. Hallaran, Manager, Chemistry

J. Hogan, Operations Superintendent, Radiation Protection

K. Huffstatler, Senior Licensing Engineer, Licensing

G. Krause, Assistant Operations Manager - Training

P. Lucky, Manager, Corrective Actions and Assessments

J. Maher, Manager, System Engineering

W. Mashburn, Director, Engineering

L. Meyer, ALARA Specialist, Radiation Protection

J. Morgan, Support Specialist, Radiation Protection

E. Neal, Acting Manager, Radiation Protection

E. Olson, Site Vice President

S. Patterson, Technician, Radiation Protection

W. Renz, Director, Emergency Planning

J. Reynolds, Assistant Operations Manager - Support

T. Santy, Manager, Security

T. Shenk, Manager, Operations

R. Thomas, ALARA Specialist, Radiation Protection

J. Vukovics, Supervisor, Reactor Engineering

J. Wieging, Manager, Planning and Scheduling, Outages

L. Woods, Manager, Quality Assurance

Attachment 1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000458/2014002-01 NCV Failure to Maintain Design Control for Performance Testing of the Control Building Chillers (Section 1R07)

05000458/2014002-02 NCV Failure to Assess and Manage Risk for Electrical Switchyard Impacting Maintenance (Section 1R13)

05000458/2014002-03 NCV Failure to Adequately Control Design Basis Documents for the Emergency Diesel Generators (Section 4OA2)

05000458/2014002-04 NCV Failure to Promptly Correct a Degraded Emergency Diesel Generator Voltage Regulator (Section 4OA2)