IR 05000458/2012002

IR 05000458-12-002; 01/01/2012 - 03/31/2012; River Bend Station; Integrated Resident and Regional Report; Maintenance Effectiveness; Maintenance Risk Assessments and Emergent Work Control; Evaluations of Changes, Tests, or Experiments and P

ML12135A462
Person / Time
Site:	River Bend
Issue date:	05/14/2012
From:	Vincent Gaddy NRC/RGN-IV/DRP/RPB-C
To:	Olson E Entergy Operations
Gaddy V
References
IR-12-002
Preceding documents:	ML113360553 (2 December 2011)
Download: ML12135A462 (74)

Text

May 14, 2012

SUBJECT:

RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT 05000458/2012002

Dear Mr. Olson:

On March 31, 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 April 12, 2012, with Mr. Eric W. Olson, and other members of your staff.

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

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

Three NRC-identified and six self-revealing findings of very low safety significance (Green) were identified during this inspection.

Seven of these findings were determined to involve violations of NRC requirements. Further, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as a non-cited violation (NCV) 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, Region IV, and the NRC Resident Inspector at River Bend Station.

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION IV

1600 EAST LAMAR BLVD ARLINGTON, 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 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/

Vincent G. Gaddy, Branch Chief Project Branch C Division of Reactor Projects

Docket No.: 05000458 License No: NPF-47

Enclosure: Inspection Report 05000458/2012002 w/ Attachments:

1. Supplemental Information 2. Information Request for Inspection Activities Documented in 2RS02, 2RS04, and 4OA5

cc w/ encl: Electronic Distribution

SUMMARY OF FINDINGS

IR 05000458/2012002; 01/01/2012 - 03/31/2012; RIVER BEND STATION; Integrated Resident and Regional Report; Maintenance Effectiveness; Maintenance Risk Assessments and Emergent Work Control; Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications; Post-Maintenance Testing; Occupational ALARA Planning and Controls; Followup of Events and Notices of Enforcement Discretion

The report covered a 3-month period of inspection by resident inspectors and announced baseline inspections by region-based inspectors. Seven Green non-cited violations and two Green findings of significance 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 reviewed a self-revealing finding regarding the improper fabrication of a turbine shaft grounding brush that resulted in turbine trip and subsequent reactor scram. The licensee identified the improper fabrication of a turbine shaft grounding brush as the cause of a spurious main turbine over-speed trip signal from an electrical discharge from the turbine shaft. This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2012-9053.

Failure to fabricate the turbine shaft grounding brush in accordance with vendor instructions is a performance deficiency. The finding was more than minor because it was associated with the equipment performance 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 during shutdown as well as power operations. Specifically, the improperly fabricated grounding brush resulted in a turbine trip and subsequent reactor scram. The inspectors reviewed the finding using IMC 0609, Appendix A,

Significance Determination of Reactor Inspection Findings for At-Power Situations. Based on the Phase 1 screening of the finding, the inspectors determined that the finding was of very low safety significance (Green) because it did not affect loss of coolant accident initiators, did not contribute to increasing the likelihood of both an initiating event and affecting mitigating equipment, and did not increase the likelihood of a fire or flood. The apparent cause of the performance deficiency was the failure in 2004 to appropriately perform a post maintenance test for the turbine shaft grounding brush modification. Therefore the inspectors did not identify a cross-cutting aspect because the performance deficiency is not reflective of the licensees current performance (Section 4OA3).

Green.

The inspectors identified a self-revealing finding for failing to maintain configuration control of the gland seal header relief valves bonnet vent port. The configuration control failure lead to a subsequent decrease in condenser vacuum requiring an unplanned power reduction to maintain adequate condenser vacuum margin. This finding has been entered into the licensees corrective action program as Condition Report CR-RBS-2012-00736.

The failure to maintain configuration control of the glad seal header relief valve was a performance deficiency. The finding was determined to be more than minor because it was associated with the configuration control 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. Specifically, the failure to maintain configuration control resulted in an unplanned down power. Using Inspection Manual Chapter IMC 0609,

Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available. The inspectors determined that the apparent cause of this finding was that when the licensee prepared work orders that directed installation of the gland seal header relief valves, they did not comply with procedural requirements to provide plant configuration controls. Therefore, this finding has a cross-cutting aspect in the human performance area associated with the work practice component because the licensee did not define and effectively communicate expectations regarding procedural compliance H.4(b) (Section 1R19).

Cornerstone: Mitigating Systems

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, due to the failure of work control and operations personnel to adequately assess the increase in risk associated with internal flooding events. This issue has been entered into the licensees corrective action program as Condition Reports CR-RBS-2012-00641.

The failure of work control and operations personnel to adequately assess the risk associated with internal flooding is a performance deficiency. The performance deficiency resulted in the overall elevated plant risk placing the plant into the higher licensee-established risk category (Green to Yellow). The performance deficiency is more than minor, because it is associated with the configuration control attribute of the Mitigating Systems Cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609,

Appendix K, Maintenance Risk Assessment and Risk Management Significance

Determination Process, Flowcharts 1 and 2, the finding was determined to have very low safety significance (Green) because the incremental core damage probability deficit was less than 1E-6 and the incremental large early release probability deficit was less than 1E-7. The inspectors determined that the apparent cause of the finding was that station personnel routinely failed to review the qualitative risk checklist required by the stations risk management procedure.

Therefore, this finding has a cross-cutting aspect in the human performance area associated with the work practice component because the licensee did not define and effectively communicate expectations regarding procedural compliance. H.4(b)

(Section 1R13)

Green.

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

Appendix B, Criterion III, Design Control, because, prior to February 7, 2012, the licensee did not verify that assumptions used in confirming that the safety-related battery inverter rooms would remain below their design basis temperature limits during a design basis event agreed with the as-built condition of the plant.

This finding was entered into the licensees corrective action program as Condition Report CR-RBS-2012-01046.

The inspectors determined that the failure to verify that design documents match the actual configuration of the plant is a performance deficiency. The finding was more than minor because it adversely affects the Mitigating Systems Cornerstone objective of equipment performance to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the licensee had not verified assumptions that ensure the standby switchgear room air conditioning system would reliably maintain the standby equipment rooms below the design temperature limits. Using Inspection Manual Chapter 0609, Attachment 4, "Initial Screening and Characterization of Findings," the finding was determined to be of very low safety significance (Green) because it did not represent a loss of system safety function, nor actual loss of safety function of a single train, and it did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined that this issue has a cross-cutting aspect in the area of human performance decision-making regarding nonconservative assumptions. When the licensee conducted the flow balance test, they assumed that measuring air inflow alone was sufficient, but did not check that the doors gaps were allowing a sufficient amount of warm air to exit standby equipment rooms and be circulated back to the general areas H.1(b)

(Section 1R17).

Green.

The inspectors identified a self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Procedures, when the reactor core isolation cooling turbine tripped on mechanical over speed. Troubleshooting determined the cause was an improperly tuned flow controller. This issue has been entered into the licensees corrective action program as Condition Reports CR-RBS-2012-01188 and CR-RBS-2012-01262

The failure to provide specific flow controller tuning instructions for the reactor core isolation cooling turbine flow controller was a performance deficiency. The finding was more than minor in accordance with Appendix B, "Issue Screening," of Inspection Manual Chapter IMC 0612, "Power Reactor Inspection Reports," because the finding was 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, improper tuning of the reactor core isolation cooling controller impacted operability and availability of the reactor core isolation cooling system. The inspectors performed a Phase 1 significance determination process review of this finding per Inspection Manual Chapter IMC 0609, Attachment 4, "Initial Screening and Characterization of Findings." In accordance with Table 4a, "Characterization Worksheet for IE, MS, and BI Cornerstones," the finding represented a loss of system safety function. Therefore, a Region IV senior reactor analyst used Inspection Manual Chapter IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations," to review the finding using the Standardized Plant Analysis Risk (SPAR) model for River Bend Station. The Phase 3 analysis determined the Delta-CDF was 4.68E-7/yr. For a 7-month exposure, the incremental conditional core damage probability is 2.73E-7. The majority of the risk came from sequences involving a loss of feedwater (48 percent) and a loss of offsite power (33 percent). Consequently, the analyst determined that the risk associated with the performance deficiency was very low (green). The inspectors determined the apparent cause of this finding was the failure to perform a post maintenance test to identify that the high output limit was not properly set by the maintenance work instruction. Therefore, this finding has cross-cutting aspect in the area of human performance associated with the resources component due to less than adequate work package testing instruction. H.2(c) (Section 1R19).

Cornerstone: Barrier Integrity

Green.

The inspectors identified a Green, self-revealing non-cited violation of Technical Specification 5.4.1.a, Procedures, for inadequate maintenance procedures to properly assemble containment isolation valves on the suppression pool cooling system. This resulted in a failure of the suppression pool cooling systems outboard containment isolation valve marriage coupling that ensures the valve stem is connected to the valve actuator. This issue has been entered into the licensees corrective action program as Condition Reports CR-RBS-2011-09171.

The failure to establish adequate work instructions to assemble the suppression pool cleanup system isolation valves is a performance deficiency. The inspectors determined that the finding was more than minor because it is associated with the Barrier Integrity Cornerstone attribute of Systems, Structures, and Components and Barrier Performance, and affected the cornerstone objective of providing reasonable assurance that the physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations. Using the Phase 1 SDP worksheet for the barrier integrity cornerstone, the inspectors answered no to all four screening questions under the containment barrier column. Specifically, the affected penetration did not represent an actual open pathway in the physical integrity of reactor containment due to an operable and functionally redundant containment isolation valve in the suppression pool cooling piping penetration. The apparent cause of the finding was the failure of the planning department to recognize and develop design documentation to identify the set screw size and starting material necessary to determine the appropriate set screw torque for work affecting safety related equipment. The inspectors determined the finding had a cross cutting aspect in the human performance, area associated with the resources component because of the lack of complete accurate and up to date design documentation associated with the work package development. H.2(c) (Section 1R22).

Cornerstone: Public Radiation Safety

Green.

The inspectors identified a non-cited violation of 10 CFR 50.65(a)(2)involving the failure to adequately monitor the performance of the digital radiation monitoring system. Specifically, the maintenance rule expert panel performed an inadequate analysis after the digital radiation monitoring system exceeded the condition monitoring criteria by failing to follow the procedural requirements of EN-DC-206 to have cause evaluations for system failures so that maintenance preventability could be properly evaluated. This issue has been entered into the licensees corrective action program as Condition Reports CR-RBS-2011-00485.

The inspectors determined that the failure to adequately monitor the performance of the digital radiation monitoring system is a performance deficiency. The inspectors reviewed Inspection Manual Chapter (IMC) 0612 and determined that the finding is more than minor because the finding is associated with the plant facilities/equipment and instrumentation attribute (reliability of process radiation monitors) of the radiation safety cornerstone (public radiation safety) and adversely affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian use. The finding was assessed using the IMC 0609, Appendix D, Public Radiation SDP, and because there was no failure to implement the effluent program, the finding was determined to be of very low safety significance (Green). The inspectors reviewed the apparent cause of this finding and found that the oversight of the maintenance rule program was adversely affected by personnel changes and lack of effective turnover. Therefore, the finding has a cross-cutting aspect in the human performance area and resources component because the licensee failed to ensure that maintenance rule program personnel were trained and sufficiently qualified to perform their duties in an effective manner H.2(b) (Section 1R12).

Cornerstone: Occupational Radiation Safety

Green.

Inspectors reviewed a self-revealing non-cited violation of 10 CFR 20.1501(a) for the failure to perform a radiation survey. A survey was not completed after two contaminated valves were transferred from the 98-foot elevation of the main steam tunnel to the radwaste area. During shift turnovers, workers responsible for transferring the valves did not understand that they needed to remove two buckets, and perform a survey after completing the valve transfer. Consequently, a bucket with highly contaminated water and residual was left in the tunnel causing radiation levels as high as 300 millirem per hour.

This resulted in an unposted high radiation area. The licensee entered the issue into the corrective actions program as Condition Report CR-RBS-2011-01552.

The failure to perform a radiation survey to evaluate the radiological conditions is a performance deficiency. The finding is more than minor because it negatively impacted the Occupational Radiation Safety cornerstones attribute of program and process, in that the lack of a post-work survey did not ensure exposure control for workers. Using NRC Manual Chapter 0609, Appendix C,

Occupational Radiation Safety Significance Determination Process, the finding was determined to be of very low safety significance because: (1) it was not associated with ALARA planning or work controls, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. The finding has a Human Performance cross-cutting component associated with the aspect of work practices because expectations regarding procedural compliance for post-job radiation surveys were ineffective H.4(b) (Section 2RS02).

Green

. Inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.7.1(c), resulting from the licensees failure to control access to a high radiation area. Specifically, a carpenter entered a high radiation area in the main steam tunnel near valve V112 without proper authorization before a health physics technician completed radiation surveys and received an unexpected alarming dosimeter reading of 110 millirem per hour. The carpenter had not been briefed that dose rates in the area measured 140 millirem per hour. He had been instructed not to perform any work before the health physics technician surveyed the area, but River Bend did not make it clear enough that he was to follow all health physics instructions. The licensee entered the issue into the corrective actions program as Condition Report CR-RBS-2011-01426 and the worker was counseled.

The failure to control access to a high radiation area was a performance deficiency. The finding was more than minor because it was associated with the occupational radiation safety attribute of exposure control and affected the cornerstone objective in that not controlling a high radiation area could increase personal exposure. In addition, this type of issue is addressed in Example 6.h of IMC 0612, Appendix E, Examples of Minor Issues. Using NRC Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination

Process, the inspector determined that the finding was of very low safety significance because it did not involve: (1) an as low as is reasonably achievable finding, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. The finding has a Human Performance cross-cutting component associated with the aspect of work practices because expectations regarding supervisory and management oversight of work activities, including contractors to ensure that safety is supported were not met

H.4(c) (Section 2RS02).

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

River Bend Station began the inspection period at 100 percent rated thermal power.

• On January 20, 2012, the plant reduced reactor power to 75 percent to perform partially withdrawn control rod surveillance, repack feedwater regulating valve A, and channel bow testing. The plant returned to full power on January 21, 2012.

• On January 29, 2012, operators reduced power to 90 percent after a partial loss of condenser vacuum occurred. Approximately two hours later, after condenser vacuum and condenser offgas flows had returned to normal, operators returned reactor power to 100 percent. The event cause was related to a faulty steam seal header pressure regulator and configuration control of the steam seal evaporator relief valves bonnet vent.

• On February 10, 2012, the plant reduced power to 98 percent to perform main turbine bypass valve testing and partially withdrawn control rod operability testing. The plant returned to 100 percent power on February 10, 2012.

• On March 9, 2012, the plant reduced power to 65 percent for control rod sequence exchange, partially withdrawn control rod testing, scram time testing, control rod stall flow testing, main turbine bypass valve testing, and turbine valve testing. The plant returned to full power on March 10, 2012.

• On March 15, 2012, the plant reduced power to 98 percent after the feedwater leading edge flow meter indicated a rise in thermal power without any observed changes in turbine load or reactor power.

• On March 16, 2012, the plant reduced power to 85 percent for rod pattern adjustment and returned to 98 percent power on March 17, 2012.

• On March 26, 2012, the plant restored full service to the feedwater leading edge flow meter and returned to full power. The plant remained at 100 percent reactor power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

Partial Walkdown a.

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

Inspection Scope

• Division 2 containment monitoring system

• Division 1 residual heat removal system

• Division 3 125 Vdc system

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 three partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b.

No findings were identified.

Findings

1R05 Fire Protection

Quarterly Fire Inspection Tours a.

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:

Inspection Scope

• January 17, 2012, turbine building

• February 2, 2012, control building, 136-foot elevation

• March 6, 2012, diesel generator building, 98-foot elevation

• March 13, 2012, control building, 116-foot elevation

• March 15, 2012, control building, 70-foot elevation

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 licensees fire plan.

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

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.

No findings were identified.

Findings

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Quarterly Review of Licensed Operator Requalification Program

a. Inspection Scope

On March 13, 2012, the inspectors observed a crew of licensed operators in the plants simulator during requalification testing. The inspectors assessed the following areas:

• Licensed operator performance

• The ability of the licensee to administer the evaluations and the quality of the training provided

• 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

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

b.

No findings were identified.

Findings

.2 Quarterly Observation of Licensed Operator Performance

a. Inspection Scope

On January 10, 2012, 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 a reactor core isolation cooling outage.

In addition, the inspectors assessed the operators adherence to plant procedures, including 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.

No findings were identified.

Findings

1R12 Maintenance Effectiveness

a.

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

Inspection Scope

• Standby gas treatment system

• Leak detection 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.

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR 50.65(a)(2)involving the failure to adequately monitor the performance of the digital radiation monitoring system.

Findings

Description.

On February 3, 2011, the digital radiation monitoring system exceeded its condition monitoring performance criteria, requiring an evaluation for the system to be placed in an a(1) status. The stations engineering personnel performed an evaluation which stated, in part, that two of the condition monitoring failures were not maintenance preventable, because the failures had been spurious trips for which no cause evaluations was required. The causes of those failures were therefore, unknown. The evaluation concluded that the system should remain in an a(2) status. The stations maintenance rule expert panel reviewed the engineering evaluation and system performance, and accepted the evaluations conclusion, allowing the digital radiation monitoring system to remain in a(2) status. However, the inspectors noted that procedure EN-DC-206, Maintenance Rule (a)(1) Process, Attachment 9.1, requires that failures must have cause evaluations to determine whether maintenance preventability applies. In addition, further review by the inspectors found additional equipment performance problems that indicated that preventive maintenance on the digital radiation monitoring system was had not been effective. The inspectors identified repetitive equipment failure trends including temperature switch failures, multiple recorder failures, failures due to grid transients and lightning strikes, sample pump failures, and process flow instrumentation failures. In addition, the inspectors sampled digital radiation monitoring system condition reports from the previous three years, and found seven condition reports that should have been added to the maintenance rule database for functional failure evaluation but were not. Station personnel evaluated these failures and concluded that two of the seven were maintenance preventable condition monitoring failures. In addition, the inspectors concluded that the condition monitoring period of three months was inadequate, in that there were several examples where radiation monitors had been out of service for greater than three months due to maintenance backlogs and work delays. The stations maintenance rule expert panel subsequently classified the system as a(1), because the performance problems had not substantiated that the digital radiation monitoring system had been effectively controlled through appropriate preventive maintenance as addressed in Condition Report CR-RBS-2012-00485. Subsequently, the station performed a focused assessment of the maintenance rule program and found deficiencies in training, qualification of personnel, and a high turnover rate of system engineers have lead to poor implementation of the program.

Analysis.

The failure to adequately monitor the performance of the digital radiation monitoring system is a performance deficiency. The inspectors used Inspection Manual Chapter (IMC) 0612, Appendix B and determined that the finding is more than minor because the finding is associated with the plant facilities/equipment and instrumentation attribute (reliability of process radiation monitors) of the radiation safety cornerstone (public radiation safety) and adversely affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive materials released into the public domain as a result of routine civilian use. The finding was assessed using the IMC 0609, Appendix D, Public Radiation SDP, and because there was no failure to implement the effluent program, the finding was determined to be of very low safety significance (Green). The inspectors reviewed the apparent cause of this finding and found that the oversight of the maintenance rule program was adversely affected by personnel changes and lack of effective turnover. Therefore, the finding has a cross-cutting aspect in the human performance area and resources component because the licensee failed to ensure that maintenance rule program personnel were trained and sufficiently qualified to perform their duties in an effective manner H.2(b).

Enforcement.

Title 10 CFR 50.65(a)(1) requires, in part, that each holder of an operating license for a nuclear power plant under this part shall monitor the performance or condition of structures, systems, or components, against licensee-established goals in a manner sufficient to provide reasonable assurance that these structures, systems, and components as described in paragraph

(b) of this section, are capable of fulfilling their intended functions. Title 10 CFR 50.65(a)(2) requires, in part, that monitoring as specified in paragraph (a)(1) of this section is not required where it has been demonstrated that the performance or condition of a structure, system, or component is being effectively controlled through the performance of appropriate preventative maintenance, such that the structure, system, or component remains capable of performing its intended function. Contrary to the above, from May 27, 2011 to March 8, 2012 the licensee failed to demonstrate that the performance of the digital radiation monitoring system was being effectively controlled through appropriate preventive maintenance. Specifically, after the digital radiation monitoring system exceeded its condition monitoring criteria, the licensee failed to monitor the performance or condition of that system against licensee-established goals in a manner sufficient to provide reasonable assurance that the system was capable of fulfilling its intended function.

Because this finding is of very low safety significance and has been entered into the licensees corrective action program as Condition Report CR-RBS-2011-00485, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000458/2012002-01, Failure to Adequately Monitor the Performance of the Digital Radiation Monitoring System.

1R13 Maintenance Risk Assessments and Emergent Work Control

a.

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:

Inspection Scope

• Standby service water building ventilation fan out of service, January 23, 2012

• Sump pumps not evaluated for internal flooding risk, January 25, 2012

• Standby service water fan maintenance risk not communicated appropriately, January 25, 2012

• Reactor protection system Division 1 power swap from alternate to normal power supply, March 7, 2012

• Emergency diesel generator B out of service for post-run maintenance and reactor core isolation cooling inoperable for emergent maintenance, March 15, 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 five maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b.

Introduction.

The inspectors identified a Green, noncited violation of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the failure of work control and operations personnel to adequately assess the increase in risk associated with internal flooding events.

Findings

Description.

On January 24, 2012, the inspectors performed an inspection of the risk management associated with fuel building sump pumps being out of service. The inspectors reviewed the administrative procedure ADM-0096, Risk Management Program Implementation and On-line Maintenance Risk Assessment. During the review the inspectors noted that Attachment 4, Qualitative External Events and Level 2 SSC Considerations, which is a checklist required to be reviewed for all risk assessments, referred to Table 2 to determine the qualitative risks associated with maintenance and plant configurations that could leave the plant susceptible to internal floods. Table 2 requires that maintenance that degrades or removes flood equipment such as opening floor plugs, hindering floor drains, and hindering flood-sensing devices, will change the station risk level to a Yellow risk condition unless a more detailed probabilistic safety assessment is completed. Based on this information, the inspectors concluded and communicated to station management that the station was in a Yellow risk condition, although the station was currently in a Green risk condition. Station personnel changed the risk condition to Yellow and performed a probabilistic safety assessment for the fuel building sumps, and determined station risk to be minimally impacted with a total CDF contribution of 3.41E-08/year, which would be a Green risk condition. The inspectors were aware of previous instances where drain systems and sump pumps in the fuel building, auxiliary building, turbine building and radwaste building had been out of service for periods of up to several months while the station remained in a base Green risk condition. The inspectors interviewed planning personnel and found that during the periods where sumps were out of service, no probabilistic safety assessments were completed as required by the online risk assessment procedure to remain in a Green risk condition. Further interviews with the work week managers and operations staff found that the required review of the qualitative risk checklist was not being performed for all risk assessments, as required by ADM-0096.

Potential risk management actions detailed by ADM-0096, Attachment 4, Table 2 include establishing a flood watch, constructing temporary barriers, ensuring equipment capable of performing redundant functions are available and not subject to failure due to a common flood, delaying or rescheduling the activity, minimize time in condition, providing alternate barriers or closing doors to associated rooms, increasing plant awareness to the vulnerability, ensuring flood monitors are functioning, and suspending work with potential for initiating a flood event in associated area. Through interviews of station personnel, the inspectors determined that the station did not consider risk management actions for several of the sump pump outages. For corrective actions, the station is revising the internal flooding probabilistic risk assessment, and will revise the ADM-0096 procedure to include more detail on risk impacts from out of service flood protection equipment.

Analysis.

The failure of work control and operations personnel to adequately assess the risk associated with internal flooding is a performance deficiency. The performance deficiency resulted in the overall elevated plant risk placing the plant into the higher licensee-established risk category (Green to Yellow). The performance deficiency is more than minor, because it is associated with the configuration control attribute of the Mitigating Systems Cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609, Appendix K, Maintenance Risk Assessment and Risk Management Significance Determination Process, Flowcharts 1 and 2, the finding was determined to have very low safety significance (Green) because the incremental core damage probability deficit was less than 1E-6 and the incremental large early release probability deficit was less than 1E-7.

The inspectors determined that the apparent cause of the finding was that station personnel routinely failed to review the qualitative risk checklist required by the stations risk management procedure. Therefore, this finding has a cross-cutting aspect in the human performance area associated with the work practice component because the licensee did not define and effectively communicate expectations regarding procedural compliance H.4(b).

Enforcement.

Title 10 CFR 50.65(a)(4), Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants, requires, in part, that the licensee assess and manage the increase in risk that may be associated with performing maintenance activities prior to performing the maintenance. Contrary to the above, on January 24, 2012, work control and operations personnel failed to adequately assess the increase in risk associated with performing maintenance activities while flood protection equipment was non-functional. Because the finding is of very low safety significance and has been entered into the licensees corrective action program as CR-RBS-2012-00641, this violation is being treated as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000458/2012002-02, Failure to Appropriately Assess and Manage Risk for Internal Flooding Events.

1R15 Operability Evaluations and Functionality Assessments

a.

The inspectors reviewed the following assessments:

Inspection Scope

• CR-RBS-2012-00178, component cooling primary to residual heat removal pump A seal cooler outlet check valve failure, reviewed on January 10, 2012

• CR-RBS-2012-00218, degraded standby service water piping penetration radflex, reviewed on January 17, 2012

• CR-RBS-2012-00238, standby service water piping snubber missing tag, reviewed on January 17, 2012

• CR-RBS-2012-00272, reactor coolant system level indication out of specification, reviewed on February 2, 2012

• CR-RBS-2012-00078, Division 3 emergency diesel generator motor operated potentiometer switch failure, reviewed on February 7, 2012

• CR-RBS-2012-00178, residual heat removal pump A seal cooler outlet check valve failure, reviewed on January 10, 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 licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. 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 six operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05.

b.

No findings were identified.

Findings

1R17 Evaluations of Changes, Tests, or Experiments and Permanent Plant Modifications

.1 Evaluations of Changes, Tests, or Experiments

a. Inspection Scope

The inspectors reviewed nine evaluations to determine whether the changes to the facility or procedures, as described in the Updated Safety Analysis Report, had been reviewed and documented in accordance with 10 CFR 50.59 requirements. The inspectors verified that, when changes, tests, or experiments were made, evaluations were performed in accordance with 10 CFR 50.59 and licensee personnel had appropriately concluded that the change, test or experiment could be accomplished without obtaining a license amendment. The inspectors also verified that safety issues related to the changes, tests, or experiments were resolved. The team compared the safety evaluations and supporting documents to the guidance and methods provided in Nuclear Energy Institute (NEI) 96-07, "Guidelines for 10 CFR 50.59 Implementation," as endorsed by NRC Regulatory Guide 1.187, "Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments," to determine the adequacy of the safety evaluations.

The inspectors reviewed 28 samples of changes, tests, and experiments that licensee personnel determined did not require evaluations and verified that the licensee personnels conclusions were correct and consistent with 10 CFR 50.59.

The inspectors also verified that calculations, analyses, design change documentation, procedures, the Updated Final Safety Analysis Report, the Technical Specifications, and plant drawings used to support the changes were accurate after the changes had been made. Documents reviewed are listed in the attachment.

These activities constitute completion of nine samples of evaluations and 28 samples of changes, tests, and experiments that were screened out by licensee personnel as defined in Inspection Procedure 71111.17-04.

b. Findings

No findings were identified.

.2 Permanent Plant Modifications

a. Inspection Scope

The inspectors verified that calculations, analyses, design change documentation, procedures, the Updated Safety Analysis Report, the Technical Specifications, and plant drawings used to support the modifications were accurate after the modifications had been made. The inspectors verified that modifications were consistent with the plants licensing and design bases. The inspectors confirmed that revised calculations and analyses demonstrated that the modifications did not adversely impact plant safety.

Additionally, inspectors interviewed design and system engineers to assess the adequacy of the modifications. The inspectors reviewed eleven permanent plant modifications, and specific documents reviewed during this inspection are listed in the attachment.

.2.1 Provide an Alternate Power Source for E51-MOV063 during a Main Control Room Fire

The inspectors reviewed an engineering change, EC-0000001933, implemented to provide an alternate means to supply both 480 VAC power and 120 VAC control power to the valve operator for E51-MOVF063. Manual actions were developed, as allowed under Generic Letter 86-10, to align the alternate power source within ten minutes of the control room evacuation, should the Division II power be lost during a main control room fire. Calculation G13.18.14.0*029 and Procedure AOP-0031 assumes RCIC control is available at the remote shutdown panel ten minutes after control room evacuation due to a fire. A spare safety related starter and control power transformer in EHS-MCC2D (Division II) was installed and fed from Division I power from two spare breakers in series in EHS-MCC2L with a fused disconnect switch and in line fuse for divisional separation. This allows the valve to be operated from the Division I Remote Shutdown Panel controls if Division II power is not available. The remote shutdown transfer switches isolate the potentially fire damaged sections of the division II control circuit, allowing it to function from the remote shutdown panel. This circuit modification was analyzed to demonstrate the Class 1E circuits are not degraded below an acceptable level in accordance with IEEE-STD-384-1974, IEEE Standard Criteria for Independence of Class 1E Equipment and Circuits and Regulatory Guide 1.75, Physical Independence of Electrical Systems.

.2.2 Install a Jet Pump Clamp at Jet Pump Riser 19-20

The inspectors reviewed an engineering change, EC-0000002575-001, implemented to install a General Electric Hitachi (GEH) redesigned riser brace clamp on jet pump no.19/20 riser brace during Refueling Outage RF-15. The installation of the riser brace clamp was to replace the RS-8 and RS-9 welds. The replacement riser brace clamp provides the required lateral support of the riser pipe assembly, even if a complete failure of the RS-8 and RS-9 welds is assumed. The inspectors reviewed the modification and verified that it is Safety Related and Seismic Category I consistent with the existing design of the welds for jet pump application in the reactor vessel. The inspectors reviewed the design and justification for the replacement Riser Brace Clamp for jet pump welds RS-8 and RS-9 in GEH specification 26A7328R01 (RBS documents number 0221.120-000-399) and Stress Report 4221.120-000-011A.

.2.3 Modify the Division 1-2 Diesel Generator Controls, Remove Bypass Trips for a Loss of

Power Only Trip The inspectors reviewed an engineering change, EC-0000012204, implemented to revise the Division I Standby Diesel Generator circuitry at the River Bend Station such that, after a Loss of Off-site Power auto-start, both the Jacket Water and Lube Oil High Temperature trips will remain active. This modification was implemented in response to a review of the licensees Post-Fire Safe Shutdown

Analysis.

The Post-Fire Safe Shutdown Analysis has found that the Division I Standby Diesel Generator becomes unavailable if fire-related control room malfunctions deprive the diesel of Standby Service Water, because the trips to protect the engine against overheating are bypassed after a Loss of Offsite Power auto-start. Generic Letter 86-10 (fire protection program)required the licensee to assume that there is a Loss of Offsite Power and that the Standby Diesel Generator is running loaded in response to the Loss of Offsite Power.

Additionally, regulatory guidance RIS-2004-03 R/1 requires the Post-Fire Safe Shutdown Analysis must assume multiple concurrent, injurious, spurious actuations due to control room fire damage. These would include loss of standby service water and starting of large loads on the diesel generator as the controls for these functions go through the control room. The inspectors reviewed the design change and verified consistency with applicable codes and standards.

.2.4 Provide Alternate Feed for E12-MOVF009

The inspectors reviewed an engineering change, EC-0000021694, which involved the replacement of the breaker in motor control center, EHS-MCC2J-1CB, which was inappropriately removed during engineering change EC-0000001933. Although labeled as spare on the one-line drawings, the breaker in EHS-MCC2J-1CB is required in Abnormal Operating Procedures AOP-0031as part of a manual action to establish normal shutdown cooling. In AOP-0031, the circuit breaker and a jumper cable are used to supply temporary power to open valve E12-MOVF009 due to fire induced loss of the Division II power supply. This condition was identified by NRC inspectors during the NRCs Triennial Fire Protection inspection. Condition report CR-RBS-2010-01825 was initiated to address this issue. The inspectors evaluated the scope of this modification which installed a Molded Case Circuit Breaker at EHSMCC2J-1CB to support River Bend Station (RBS) 10CFR50 Appendix R criterion 240.201A, and Abnormal Operating Procedures AOP-0031, and AOP-0052 requirements. Circuit breaker EHS-MCC2J-1CB is utilized to provide power to valve, E12-MOVF009 during a postulated Main Control Room fire scenario. This engineering change was associated with restoring the original design configuration of EHS-MCC1J-1CB.

.2.5 Division II Emergency Diesel Generator Turbocharger Piping Upgrades in the Air and Oil

Piping The inspectors reviewed an engineering change, EC-0000004860, that replaced pipe and fittings on the division II standby diesel generator turbocharger discharge air piping and turbocharger oil drain piping. Heavier pipes and fittings were installed to resolve problems with cracks observed in the discharge air piping (CR-RBS-2007-04490) and oil drain piping (CR-RBS-2007-05394). Pipe stress analyses were performed on both the discharge air piping and oil drain piping and results indicated that both failures were due to high cycle fatigue. The only piping change is the replacement of fittings and flanges with heavier elements. The design conditions for standby diesel generator turbocharger discharge air and oil drain piping systems are not affected with replacement of piping.

No significant pressure drop change will result from this piping change, and the heavier elements will not adversely impact existing structural supports.

.2.6 Installation of Flow Elements on the Diesel Fuel Oil System

The inspectors reviewed an engineering change, EC-0000017392, that installed flow orifices, additional tubing, and instrumentation to permit accurate measurement of the division III emergency diesel generator. The emergency diesel generator fuel oil transfer pumps require surveillance testing in accordance with the ASME Section XI in-service testing program. Previously, testing was accomplished using the day tank level indicator and recording the time for the day tank level to change between two established levels.

Direct flow measurement using in-line flow elements is much less labor intensive. A flow element was installed in the fuel oil pump discharge line downstream of the strainer after the first isolation valve. The diesel fuel oil transfer system operation remains unchanged as the flow elements will not affect system actuation or flow rate.

.2.7 Revise Tap Settings of STX-XS5A & -XS5B to Nominal to Prevent Overvoltage

The inspectors reviewed an engineering change, EC-5000070729, that revised the tap settings of the following standby transformers, STX-XS5A and STX-XS5B, to prevent overvoltage on switchgears, NNS-SWG6A and NNS-SWG6B and NJS-LDC4A and NJS-LDC4A and NJS-LDC4B. STX-XS5A and STX-XS5B are three phase 13.2 kV delta to 4160 VAC wye transformers used to supply power to various Service Water Cooling components. The new tap settings will provide a lower voltage to the connected buses to prevent the overvoltage conditions during light loading with the normal transformers in service. The manual load tap setting was set to provide adequate voltage after a fast bus transfer of NPS-SWG1A or NPS-SWG1B back to the preferred transformers. The inspectors reviewed the voltage and load specifications for the transformers and associated circuits.

.2.8 Five Second Time Delay Addition to Division III Standby Service Water Actuation and

Battery Backed Power to Control Circuit The inspectors reviewed an engineering change, EC-000009510, that added a five second time delay to division III Standby Service Water actuation and provided battery backed power to the control circuit. The purpose of this modification was to provide uninterruptible power to the division III service water pressure transmitter circuit. This was to correct a failure of the SWP-P2C pump to start within its technical specification time limits during a loss of offsite power. This modification changed the power supply for division III pressure transmitter circuits and associated time delay relays to an uninterruptible DC power supply. This change allows the time delay relays to perform their function to prevent spurious initiations in the Standby Service Water System on low normal service water pressure.

The Standby Service Water System is designed to provide a reliable source of cooling water to plant system and components required for the safe shutdown and long term cooling of the plant following a design basis accident. The inspectors reviewed and evaluated the scope of this engineering change that covered disconnecting the Service Water Pump division III pressure transmitters and the associated trip units from AC/DC power supply BOP-PS1 and connecting them to DC power supply E22A-PS1. This modification resulted in improved equipment availability by enabling continuous operation of the initiation circuit for SWP-P2C on loss of offsite power and supports the ability to meet technical specification pump start time requirements.

.2.9 Evaluation of the Impact on Standby Switchgear Room HVAC System with Replacement

Inverters The inspectors reviewed an engineering change, EC-0000008168, that evaluated the performance of the standby switchgear room HVAC system due to replacement safety-related batter inverters. The standby switchgear room air conditioning system maintains a design ambient temperature of 104 ºF in switchgear rooms, general areas, standby equipment rooms. The electrical heat released from the replacement inverters is greater than the original design. With additional heat load from replacement inverters, the ambient temperature in standby equipment rooms will reach approximately 113 ºF during worst case conditions. In order to maintain a design ambient temperature of 104 ºF in standby equipment rooms, the licensee increased the supply airflow into the standby equipment rooms. The additional supply air for standby equipment rooms is transferred from general areas of the control building which have adequate design margin airflow. The warm air from the inverter rooms is transferred back in to the general areas through room exhaust fans, door under cuts, and gaps around door frame.

b.

Failure to Verify Assumptions used in Standby Equipment Room Temperature Analysis Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the failure to establish design control measures to verify the adequacy of the design of the standby switchgear room air conditioning system with replacement battery inverters. Specifically, the inspectors identified that assumptions used in confirming that the safety-related battery inverter rooms would remain below their design basis temperature limits during a design basis event did not agree with the as-built condition of the plant.

Description.

The inspectors reviewed Engineering Change EC-0000008168, which evaluated the ability of the standby switchgear room air conditioning system to provide adequate cooling to support installation of replacement battery inverters. Safety-related inverters ENB-INV01A, 01B and non safety-related inverter BYS-INV02 were replaced by EC-0000007239 with new units manufactured by Solid State Controls. The replacement safety-related inverters are located in standby equipment rooms on elevation 115-00 in the control building. The standby switchgear room air conditioning system is designed to maintain an ambient temperature of less than 104 ºF in switchgear rooms, general areas, and standby equipment rooms. However, the electrical heat released from the replacement inverters is greater than the original design. Design calculations G13.18.2.1*059, Revision 2, determined that with the additional heat load from the replacement inverters, the ambient temperature in the standby equipment rooms would reach approximately 113 ºF during worst case accident conditions.

Calculation G13.18.2.1*059, Revision 2, states that in order to maintain a design temperature of less than or equal to 104 ºF in standby equipment rooms, the supply airflow is increased from 900 cubic feet per minute to 1,250 cubic feet per minute. The basis for the acceptability of the 1,250 cubic feet per minute is provided in EC-0000008168. The additional supply airflow for standby equipment rooms is transferred from general areas of control building elevation 115-00 which have adequate design margin. The volume dampers provided in the supply ducts and supply registers can be adjusted to achieve the desired airflows. According to Calculation G13.18.2.1*059, Revision 2, the maximum calculated room temperatures with the increased 1,250 cubic feet per minute airflow were 101.7 ºF in standby equipment room A and 100.5 ºF in standby equipment room B.

The battery room exhaust fans normally exhaust nine hundred cubic feet per minute of warm air from the standby equipment rooms. The ambient temperature will remain less than or equal to 104 ºF only if all of that warm is allowed to exit the room. The plant is designed to transfer an additional 350 cubic feet per minute excess airflow from the standby equipment rooms back into the general areas of the control building through door under cuts and gaps around the door frames. EC-0000008168 stated that in order to maintain an exit air transfer velocity from the standby equipment rooms less than the supply air velocity, an air gap of 0.25 square feet is needed. A one inch gap beneath doors and CB-116-06 and CB-116-12 and an additional gap of one eighth of an inch around the door frame were calculated to provide a sufficient free area for warm air to exit the standby equipment rooms.

Air egress through the new one inch door gap is not explicitly modeled in Calculation G13.18.2.1*059. However, the battery room exhaust fans, which are credited for removing the original 900 cubic feet per minute, are also modeled. The calculation assumes that an adequate flow path exists for air to exit the switchgear rooms. The battery room exhaust fans are not credited for removal of any of the excess airflow beyond the original 900 cubic feet per minute. There would only be no adverse impact to the performance of the battery room exhaust fans if the increased supply airflow is removed through the credited door gaps.

Engineering change EC-0000007239, which is the document that implemented the inverter replacement, also described the one inch gap beneath control building doors CB116-06 and CB116-13 and considered the fire barrier and civil engineering implications of removing a portion of the concrete floor to create that gap. Work Order 48234, dated November 26, 2008, ground down the concrete beneath the doors allow for this air flow. EC-0000008168 documents that a walkdown was performed by the licensee on June 5, 2008, to verify the undercut gaps for doors in the standby equipment rooms. However, the gaps beneath doors CR-116-13 and CR-116-06 was substantially less than the prescribed one inch when observed by an inspector and licensee engineer on February 7, 2012. No discernible gap around the sides or top of the door could be measured.

Airflow adjustment and measurement was performed under work order 156579 on May 26, 2009, prior to energizing the replacement battery inverters. The desired airflows, including the 900 cubic feet per minute exhaust fan flow and 350 cubic feet per minute door gap flow are described on piping and instrumentation diagram PID-022-09C.

Technicians took anemometer readings for the supply airflow to the two rooms, but took no readings of the air exiting the room through either the door gaps or exhaust fans.

Prior to questioning by the inspectors, the licensee had not verified that sufficient warm airflow was exiting the room to maintain an ambient temperature of less than 104 ºF.

Because the assumptions used to support Calculation G13.18.2.1*059 do not match the actual configuration of the plant, an adequate air outflow pathway had not been verified.

Without an adequate air outflow pathway, an increased load would be placed on the battery room exhaust fans or room temperatures would increase beyond what is predicted in the calculation, challenging the temperature limits of the battery inverter room.

This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2012-01046. Licensee engineers consulted fan vendor performance curves and confirmed that the battery room exhaust fans have sufficient capacity to exhaust the additional 350 cubic feet per minute. The additional exhaust flow would also cause additional horsepower to be required by the battery room exhaust fans. Licensee engineers consulted emergency diesel generator loading specifications and verified that the increase in horsepower demanded by the exhaust fans would not challenge the maximum diesel generator loading. On February 13, 2012, licensee engineers conducted follow-up measurements of the supply and exhaust flow to the standby switchgear and battery rooms. The measured air supply was adequate to prevent the room from exceeding the maximum temperature limits and the measured exhaust fan duct flow was within the credited fan capacity. However, air supply flow on February 13, 2012, was substantially less than that measured during the May 26, 2009, post-maintenance testing. The licensee has created a preventative maintenance task to perform regular air flow measurement and adjustments.

Analysis.

The failure to verify that design documents match the actual configuration of the plant is a performance deficiency. This finding is more than minor because it adversely affects the Mitigating Systems Cornerstone objective of equipment performance to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Inspection Manual Chapter 0609, Attachment 4, "Initial Screening and Characterization of Findings," the finding was determined to be of very low safety significance (Green)because it did not represent a loss of system safety function, nor actual loss of safety function of a single train, and it did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. This issue has a cross-cutting aspect in area of human performance associated with the decision-making component because of nonconservative assumptions. Specifically, the EC-0000008168 package described that the adjustment of airflows, measurements, and air balancing is required to provide design flow in standby equipment rooms. When the licensee conducted the flow balance test, they assumed that measuring air inflow alone was sufficient, but did not check that the doors gaps were allowing a sufficient amount of warm air to exit standby equipment rooms and be circulated back to the general areas

H.1(b) (Section 1R17).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, requires, in part, that 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 February 7, 2012, the licensee did not establish design control measures that verified the adequacy of the design of the standby switchgear room heating ventilation, and air conditioning system. Specifically, the licensee did not verify that assumptions used in confirming that the safety-related battery inverter rooms would remain below their design basis temperature limits during a design basis event agreed with the as-built condition of the plant. This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2012-01046. Because this finding was determined to be of very low safety significance and was entered into the licensees corrective action program, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy:

NCV 05000458/2012002-03, Failure to Verify Assumptions used in Standby Equipment Room Temperature

1R19 Post-Maintenance Testing

a.

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

Inspection Scope

• WO 00284020, E51-R600 Open and Closed Pushbuttons not Functioning, reviewed on March 5, 2012

• WO 00122440, Radiation Monitor Recorder Termination Short Causes ENB-INV01B1 to be Inoperable, reviewed on March 1, 2012

• WO 00308611, RCIC Governor Valve Tuning, reviewed on March 19, 2012

• WO 51796287, "TME-RVR1B - REMOVE RELIEF VALVE TME-RVR1B AND SHIP TO WYLE LABS," reviewed on March 7, 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 four post-maintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b.

===.1

=

The inspectors identified a Green self-revealing non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Procedures, for the failure to provide specific flow controller tuning instructions for the reactor core isolation cooling turbine flow controller, which caused the turbine to trip on mechanical over speed.

Findings

Description.

On February 14, 2012, while the licensee started reactor core isolation cooling to support residual heat removal B heat exchanger testing, pump discharge pressure and turbine speed went off-scale high and the turbine tripped on mechanical over speed. When maintenance technicians removed the reactor core isolation cooling pump flow controller, E51-FCR600, for diagnostic testing they found the flow controller high output limit was set at 6.63 Vdc rather than the expected 5 Vdc specified in GEK 83376, Operating & Maintenance Instructions for Reactor Core Isolation Cooling Systems, and EPRI Terry Turbine Maintenance Guide, RCIC Application: Replaces TR-105874 and TR-016909-R1. At 5 VDC, the high output limit prevents turbine speed from exceeding 4500 rpm to prevent a mechanical over speed trip. With the flow controller output set at 6.63 Vdc, the flow controller demanded 132 percent of rated turbine speed.

Operators started reactor core isolation cooling per the system operating procedure SOP-0059, Reactor Core Isolation Cooling System. The procedure aligns system flow through the pump minimum flow valve with the pump discharge valve closed. In this alignment, the pump discharge flow element sensed zero flow, because all system flow was through the minimum flow valve upstream of the flow element. With no flow sensed the flow controller output remained at 6.63 Vdc.

The licensee found that the flow controller had been replaced and last calibrated in July 2011. Neither the replacement procedure, WO 284020, E51-R600 Open and Closed Pushbuttons Not Functioning, nor the Loop Calibration Report LCR 1.ILICS.014, Reactor Core Isolation Cooling Pump Discharge Line Flow Loop, contained instructions to limit the controller high output limit to 5Vdc. Following corrective maintenance, the system satisfactorily performed its post-maintenance testing per surveillance test procedure STP-209-6310, RCIC Quarterly Pump and Valve Operability Test.

Procedure STP-209-6310 aligns pump flow past the flow element to the condensate storage tank with the flow controller in manual. STP-209-6310 did not test the flow controller high output limit maximum set point. If SOP-0059 had been specified as the post-maintenance test for WO 284020 instead of STP-209-6310, SOP-0059 would have identified the high output limit set point issue as the maintenance activity was completed.

Corrective actions to ensure future system and station performance include - (1)adusting the flow controller high output limit to 5 Vdc;

(2) briefing personnel who specify or approve post-maintenance testing that standard test procedures may not always provide the optimum re-test;

(3) revising the loop calibration record LCR 1.ILICS.014 to add a note to set the high output limit adjustment in accordance with vendor manual to 5.00 Vdc; and

(4) reviewing Bailey controllers used in standby systems which controls in automatic that may have HIGH or LOW Limits applicable.

Analysis.

The failure to provide specific flow controller tuning instruction for the reactor core isolation cooling turbine flow controller was a performance deficiencies. The inspectors concluded that the finding was more than minor in accordance with Appendix B, "Issue Screening," of Inspection Manual Chapter IMC 0612, "Power Reactor Inspection Reports," because the finding was 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, improper tuning of the reactor core isolation cooling controller impacted operability and availability of the reactor core isolation cooling system. The inspectors performed a Phase 1 significance determination process review of this finding per Inspection Manual Chapter IMC 0609, Attachment 4, "Initial Screening and Characterization of Findings."

In accordance with Table 4a, "Characterization Worksheet for IE, MS, and BI Cornerstones," the finding represented a loss of system safety function. Therefore, a Region IV senior reactor analyst used Inspection Manual Chapter IMC 0609, Appendix A, "Determining the Significance of Reactor Inspection Findings for At-Power Situations,"

to review the finding using the Standardized Plant Analysis Risk (SPAR) model for River Bend Station. The Phase 3 analysis determined the Delta-CDF was 4.68E-7/yr. For a 7-month exposure, the incremental conditional core damage probability is 2.73E-7. The majority of the risk came from sequences involving a loss of feedwater (48 percent) and a loss of offsite power (33 percent). Consequently, the analyst determined that the risk associated with the performance deficiency was very low (green). The inspectors determined the apparent cause of this finding was the failure to perform a post maintenance test to identify that the high output limit was not properly set by the maintenance work instruction. Therefore, this finding has cross-cutting aspect in the area of human performance associated with the resources component due to less than adequate work package testing instruction H.2(c).

Enforcement.

Title 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, on July 22, 2011, the stations procedures to setup the reactor core isolation cooling pump flow controller were not appropriate to the circumstances because they failed to ensure an appropriate limiting value for turbine speed high output was applied. Because this issue is of the very low safety significance and has been entered into the licensees corrective action program as Condition Reports CR-RBS-2012-01188 and CR-RBS-2012-01262, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy.

NCV 05000458/2012002-04, Failure to Appropriately Set Reactor Core Isolation Cooling Flow Controller High Output Limit.

===.2

=

The inspectors identified a Green self-revealing finding for failing to maintain configuration control of the gland seal header relief valves bonnet vent port.

The configuration control failure lead to a subsequent decrease in condenser vacuum requiring an unplanned power reduction to maintain adequate condenser vacuum margin.

Description.

In January, 2011, and as required by their preventive-maintenance program, the licensee removed gland seal header air-operated relief valves TME-RVR1A and TME-RVR1B from service and shipped them to Wyle Laboratories for as-found testing, rework, and as-left testing. (The gland seal header supplies steam to the main turbines gland seal. TME-RVR1A and TME-RVR1B are balanced relief valves which rely on a vented bonnet to maintain their proper set pressure.) The Wyle staff completed testing that included installing a device into each valves bonnet vent to pressurize the bellows and test for bellows leakage. This testing revealed that the TME-RVR1B bellows had a leak rate characterized as 7 bubbles per minute, and that the TME-RVR1A did not have a measurable leak. Following the tests, the Wyle staff told the licensee about the test results, the licensee accepted the test results, the Wyle staff shipped the valves, and the licensee re-installed both valves. However, somehow in the handling of the valves, a threaded metal plug was installed into each valves bonnet vent, and the licensee installed the valves into the plant without repairing the leak and without removing the subject plugs. The licensee has not determined when and how the metal plugs were installed. The licensee also has not located an evaluation that accepted these valves for installation with the identified bellows leakage.

EN-DC-105, Configuration Management, requires that maintenance procedures provide plant configuration controls. Work order 51796287-03 was the maintenance procedure that directed the re-installation of TME-RVR1B, and work order 52255083-03 was the maintenance procedure that directed the re-installation of TME-RVR1A. Both work orders required workers to verify that they were re-installing the correct valves, but neither work order required workers to verify that the valves they were installing were in the correct configuration. So, because the work orders did not require workers to verify that the bonnet vent was not plugged, the workers who installed the valves did not identify the threaded plugs in both valves bonnet vents, and both valves were installed with threaded plugs in their bonnet vents. Because each valve relied on a vented bonnet to maintain its proper set pressure, the effect of plugging the bonnet vent was to lower the valves set pressure.

On January 28, 2012, with the reactor plant operating at 100 percent power, the gland seal steam header pressure control valve malfunctioned and caused pressure fluctuations in the gland seal header. During those fluctuations and at a header pressure well below the pressure at which TME-RVR1A and TME-RVR1B were intended to lift, both valves lifted and began passing gland seal steam into the condenser, which ultimately resulted in a decrease in condenser vacuum. When operators noted the rate at which vacuum was decreasing, they entered the abnormal operation procedure for loss of main condenser vacuum and reduced reactor power to 90 percent to stop the decrease in condenser vacuum. As steam seal evaporator water temperature, pressure and water level recovered to normal, the gland seal system performance stabilized and main condenser off-gas flow rate and condenser vacuum recovered to normal.

Therefore, the station concluded that the initial loss of steam seal evaporator level and operators attempts to manually recover evaporator tank water level had caused the unexpected loss of vacuum.

Following the downpower event, an investigation completed by station personnel and documented in CR-RBS-2012-00863 discovered the plugs installed in each valves bonnet vent contrary to plant design drawing 0231.020-000-020, Outline Relief Valve and realized that those plugs, coupled with bellows leakage, had effectively changed the relief valves set point from 20 psig to approximately 6 psig. The combination of leaking bellows and plugged bonnet vents had allowed condenser vacuum to communicate through the bellows to the valve disc, thereby removing atmosphere pressure as a closing force on the valve disc and resulting in a reduced relief set pressure.

Station corrective actions include revising the job plan for sending balanced relief valves off site for testing, to verify during reinstallation that the bonnet vent valves are open.

Those corrective actions also include repairing the bellows leakage during the next refueling outage.

Analysis.

The licensees failure to provide plant configuration controls in maintenance procedures that directed installation of the gland seal header relief valves is a performance deficiency. This performance deficiency was determined to be more-than-minor and therefore a finding because it was associated with the configuration-control 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. Specifically, this finding resulted in a reactor down power. Using Inspection Manual Chapter IMC 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, the finding was determined to have very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating systems will not be available.

The inspectors determined that the apparent cause of this finding was that when the licensee prepared work orders 51796287-03 and 52255083-03, they did not define and effectively communicate an expectation for those work orders to comply with EN-DC-105. Therefore, this finding has a cross-cutting aspect in the work practices component of the human performance area because the licensee did not define and effectively communicate expectations regarding procedural compliance H.4(b).

Enforcement.

Enforcement action does not apply because the performance deficiency did not involve a violation of regulatory requirements. Because this finding does not involve enforcement action, has been entered into the licensees corrective action program as Condition Report CR-RBS-2012-00736, and has very low safety significance, it is identified as FIN 05000458/2012002-05, Failure to Provide Plant

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

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• 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.

• OSP-0061, Control Rod Settling and Insertion Test, Revision 4, performed on January 23, 2012

• STP-000-0001, Daily Operating Logs, Revision 68, performed on March 12, 2012

• STP-402-0202, Main Control Room A/C Train B Operability Test, Revision 15, performed on March 13, 2012

• STP-204-6602, Main Control Room A/C Train B Operability Test, Revision 302, performed on May 15, 2011

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

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

b.

Introduction.

The inspectors identified a Green, self-revealing non-cited violation of Technical Specification 5.4.1.a, Procedures, for inadequate maintenance procedures to properly assemble containment isolation valves in the suppression pool cooling system.

This resulted in a failure of the outboard containment isolation valve marriage coupling that ensures the valve stem is connected to the valve actuator.

Findings

Description.

On December 29, 2011, operations began work to isolate a portion of the suppression pool cleanup system to remove a relief valve for scheduled maintenance and testing. During venting of the isolated portion of the system, water did not stop flowing from the valve, indicating that the isolation had failed. The operators found that the suppression pool cleanup outboard isolation valve, RHS-AOV62, remained in the open position after the control room had remotely placed the valve in the closed position.

Further investigation found that the valve marriage coupling failed, with the coupling being detached and at the bottom of the valve stem. The safety function of the valve is to close in order to isolate the non-safety related suppression pool cooling system from the safety related residual heat removal system upon a loss of coolant accident. Valve RHS-AOV62, the SPC suction isolation valve, is a 10 inch Crane butterfly valve with a Bettis pneumatic rotary actuator. The actuator connects to the valve stem through the marriage coupling, which is secured with two set screws.

The licensee determined the failure was due to inadequate torque applied to the set screws that secure the marriage coupling to the valve stem and the actuator. Actuator maintenance was performed on the valve on September 30, 2009, and the work instructions failed to identify an appropriate torque for the marriage coupling set screws.

The documentation that detailed the design of the marriage block did not include set screw torque values, material or size. The inspectors reviewed the in-service testing history of the valve and found that the valve had been visually identified as functioning as of May 15, 2011, during 18 month in-service testing. Quarterly in-service testing requires that the valve be stroke time tested from the main control room, and no local visual confirmation is required.

The apparent cause detailed two potential causes,

(1) maintenance failed to tighten the set screw to the minimum required torque, or

(2) the set screws were damaged by either improper threading or degrading material. On March 26, 2012, the inspectors determined that no actions had been taken by engineering to determine if the set screws had been damaged, and operations had failed to evaluate the extent of condition of the deficiencies that could impact the similarly designed and functionally redundant inboard isolation valve, RHS-AOV63. The inspectors brought their concerns to operations management, and valve RHS-AOV62 was declared inoperable and the penetration was isolated. Maintenance personnel performed inspections on RHS-AOV62 and RHS-AOV63 and determined that the condition of the set screws for both containment isolation valves were satisfactory, therefore the inspectors determined that the failure to identify and correct the potentially damaged set screws was a performance deficiency of minor significance.

Analysis.

The failure to establish adequate work instructions to assemble the suppression pool cleanup system isolation valves is a performance deficiency. The inspectors determined that the finding was more than minor because it is associated with the Barrier Integrity Cornerstone attribute of Systems, Structures, and Components and Barrier Performance, and affected the cornerstone objective of providing reasonable assurance that the physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations. Using the Phase 1 SDP worksheet for the barrier integrity cornerstone, the inspectors answered no to all four screening questions under the containment barrier column. Specifically, the affected penetration did not represent an actual open pathway in the physical integrity of reactor containment due to an operable and functionally redundant containment isolation valve in the suppression pool cooling piping penetration. The apparent cause of the finding was the failure of the planning department to recognize and develop design documentation to identify the set screw size and starting material necessary to determine the appropriate set screw torque for work affecting safety related equipment. The inspectors determined the finding had a cross cutting aspect in the human performance, area associated with the resources component because of the lack of complete accurate and up to date design documentation associated with the work package development H.2(c).

Enforcement.

Technical Specification 5.4.1.a requires that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Revision 2, appendix A, Section 9, requires, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures appropriate to the circumstances. Contrary to the above, on September 30, 2009, the licensee performed maintenance that affected the performance of safety-related equipment with written instructions that were not appropriate to the circumstances. Specifically, the work orders did not include set screw torque values for proper assembly of the marriage coupling that secures the valve stem to the valve actuator. Because this finding is of very low safety significance (Green) and has been entered into the stations corrective action program as Condition Report CR-RBS-2011-09171, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy:

NCV 05000458/2012002-06, Inadequate Maintenance Instructions used for Suppression Pool Cooling Isolation Valve Maintenance.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a.

The inspectors evaluated the conduct of a routine licensee emergency drill on March 13, 2012, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator 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.

Inspection Scope

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

b.

No findings were identified.

Findings

.2 Training Observations

a.

The inspectors observed a simulator training evolution for licensed operators on March 13, 2012, which required emergency plan implementation by a licensee operations crew.

This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-Inspection Scope evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the corrective action program.

As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the attachment.

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

b.

No findings were identified.

Findings

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

This area was inspected to assess performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed licensee personnel and reviewed the following items:

• 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/post-job 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

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

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.02-05.

b. Findings

===.1

=

Inspectors reviewed a self-revealing Green non-cited violation of 10 CFR 20.1501(a) for the failure to perform a radiation survey. Specifically, a survey was not completed after two contaminated valves were transferred from the main 98-foot elevation of the steam tunnel to the radwaste area. The absence of the radiation survey resulted in an unposted high radiation area that led to four workers receiving unexpected dosimeter alarms and unplanned dose.

Description.

On January 29, 2011, in a locked high radiation area on the 114-foot elevation of the main steam tunnel, workers cut out two highly contaminated valves which contained significant hot spots. The valves were surveyed prior to removal, and read between 86 rem per hour and 112 rem per hour on contact, and between 1.27 rem per hour and 6.7 rem per hour at 30 centimeters. After removal from the pipe, the valves were placed into separate buckets of water for shielding, but later, both valves were placed in the same bucket. The two buckets were transferred to an adjacent area on 98-foot elevation of the main steam tunnel because there was more space to prepare for the transfer of the valves to the radwaste bay. During the nightshift on January 29, 2011, the bucket containing the valves was transferred to the radwaste bay in a shielded transfer drum. However, the night shift did not recognize the need to dispose of both buckets. Also, a radiation survey was not completed in the 98-foot elevation of the main steam tunnel after the valves were removed. So, the presence of the second bucket was not known, and the room remained posted as a radiation area. On the morning of January 30, 2011, three pipefitters and a firewatch entered the 98-foot elevation of the main steam tunnel to perform unrelated work, and all four received dosimeter alarms.

A health physics technician subsequently performed a radiation survey of the area and discovered the bucket, which contained rusty water and had a contact reading of 2.5 rem per hour and 300 millirem per hour at 30 centimeters. Further investigation determined that the bucket originally contained one of the contaminated valves and the bucket should have been removed with the valves. If radiation protection personnel had surveyed the area after the valves were transferred, then the bucket would likely have been noticed, and the area properly posted as a high radiation area.

Analysis.

The failure to perform a radiation survey to evaluate the radiological conditions is a performance deficiency. The finding is more than minor because it negatively impacted the Occupational Radiation Safety cornerstones attribute of program and process, in that the lack of a post-work survey did not ensure exposure control for workers. Using NRC Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the finding was determined to be of very low safety significance because:

(1) it was not associated with ALARA planning or work controls,

(2) there was no overexposure,

(3) there was no substantial potential for an overexposure, and

(4) the ability to assess dose was not compromised. The finding has a Human Performance cross-cutting component associated with the aspect of work practices because expectations regarding procedural compliance for post-job radiation surveys were ineffective H.4(b).

Enforcement.

Title 10 CFR 20.1501(a) requires that each licensee make or cause to be made surveys that may be necessary for the licensee to comply with the regulations in Part 20 and that are reasonable under the circumstances to evaluate the extent of radiation levels, concentrations or quantities of radioactive materials, and the potential radiological hazards that could be present. Contrary to the above, on January 29, 2011, radiation protection personnel did not perform a radiation survey of the 98-foot elevation of the main steam tunnel after the removal of two valves from the area in order to evaluate the extent of radiation levels, concentrations or quantities of radioactive materials and potential radiological hazards present. Consequently, the absence of a survey caused personnel to not realize that the contaminated bucket with radioactive water caused a high radiation area and four workers received unplanned dose. Since this violation was of very low safety significance and was documented in Condition Report CR-RBS-2011-01552, it is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000458/2012002-07, Failure to Perform a Radiation Survey.

===.2

=

Inspectors reviewed a self-revealing non-cited violation of Technical Specification 5.7.1(c), resulting from the licensees failure to control access to a high radiation area. Specifically, an individual entered an unposted high radiation area without proper authorization before radiation protection staff completed radiation surveys, and received an unexpected electronic dosimeter dose rate alarm.

Description.

On January 29, 2011, a health physics technician escorted a group of carpenters to the main steam tunnel to build scaffolding near valve V112. The carpenters were signed on a radiation work permit that only authorized entry into a radiation area. The technician left the carpenters at the main steam tunnel entrance while he went to get a radiation survey meter and direct other workers in the area.

When the technician entered the 123-foot elevation of the main steam tunnel platform to perform his radiation survey, one of the carpenters was already there examining the work area near valve V112. The carpenter got too close to valve V112 and received an unexpected alarming dosimeter dose rate of 110 millirem per hour. This exceeded the alarm setpoint of 80 millirem per hour. The carpenter promptly informed radiation protection that he alarmed his dosimeter. When the health physics technician performed a radiation survey, the highest dose rate detected was 140 millirem per hour at 30 centimeters. Therefore, the carpenter had made an entry into a high radiation area that was not authorized by the radiation protection technician because the health physics technician did not make it clear enough that the contractors needed to wait outside the main steam tunnel. The licensee entered the issue into the corrective actions program as Condition Report CR-RBS-2011-01426 and counseled the carpenters on the importance of adhering to the stated instructions of a health physics technician and radiation work permits.

Analysis.

The failure to control access to a high radiation area was a performance deficiency. The finding was more than minor because it was associated with the occupational radiation safety attribute of exposure control and affected the cornerstone objective in that not controlling a high radiation area could increase personal exposure.

In addition, this type of issue is addressed in Example 6.h of IMC 0612, Appendix E, Examples of Minor Issues. Using NRC Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the inspector determined that the finding was of very low safety significance because it did not involve:

(1) an as low as is reasonably achievable finding,

(2) an overexposure,

(3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose. The finding has a Human Performance cross-cutting component associated with the aspect of work practices because expectations regarding supervisory and management oversight of work activities, including contractors to ensure that safety is supported were not met

H.4(c).

Enforcement.

Technical Specification 5.7.1(c) requires that each high radiation area, as defined in 10 CFR Part 20, in which the intensity of radiation is greater than 100 millirem per hour but less than 1000 millirem per hour, be conspicuously posted as a high radiation area and entrance the area be controlled by requiring issuance of a radiation work permit. Any individual or group of individuals permitted to enter such areas shall be provided with or accompanied by one of the following:

(a) a radiation monitoring device that continuously indicates the radiation dose rate in the area,

(b) a radiation monitoring device that continuously integrates the radiation dose rate in the area and alarms when a preset integrated dose is received (Entry into such areas with this monitoring dose may be made after the dose rate levels in the area have been established and personnel are aware of them.), or

(c) an individual qualified in radiation protection procedures with a radiation dose rate monitoring device, who is responsible for providing positive control over activities within the area and shall perform radiation surveillances at the frequency specified by health physics supervision in the radiation work permit. Contrary to the above, on January 29, 2011, an individual entered a high radiation area in the main steam tunnel without an appropriate radiation work permit and either

(a) a radiation monitoring device that continuously indicates the radiation dose rate in the area, or

(b) being aware of the dose rate levels in the area, or

(c) an individual qualified in radiation protection procedures with a radiation dose rate monitoring device, who is responsible for providing positive control over activities within the area. Because, this failure to control a high radiation area was of very low safety significance and has been entered into the licensees corrective action program as Condition Report CR-RBS-2011-01426, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000458/2012002-08, Failure to Control Access to a High Radiation Area.

2RS4 Occupational Dose Assessment

a. Inspection Scope

This area was inspected to:

(1) determine the accuracy and operability of personal monitoring equipment;

(2) determine the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent; and

(3) ensure occupational dose is appropriately monitored. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:

• 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

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

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.04-05.

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.

The inspectors performed a review of the performance indicator data submitted by the licensee for the fourth quarter 2011 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

Inspection Scope

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

b.

No findings were identified.

Findings

.2 Unplanned Scrams per 7000 Critical Hours (IE01)

a.

The inspectors sampled licensee submittals for the unplanned scrams per 7000 critical hours performance indicator for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 2011 through December 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one unplanned scrams per 7000 critical hours sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

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

a.

The inspectors sampled licensee submittals for the unplanned power changes per 7000 critical hours performance indicator for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC integrated inspection reports for the period of January 2011 through December 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one unplanned transients per 7000 critical hours sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.4 Unplanned Scrams with Complications (IE04)

a.

The inspectors sampled licensee submittals for the unplanned scrams with complications performance indicator for the period from the first quarter 2011 through the fourth quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 2011 through December 2011 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of one unplanned scrams with complications sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a.

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 licensees 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 licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

Inspection Scope 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.

No findings were identified.

Findings

.2 Daily Corrective Action Program Reviews

a.

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 licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

Inspection Scope

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.

No findings were identified.

Findings

.3 Selected Issue Follow-up Inspection

a. Inspection Scope

Focused Baseline Inspection for Reactor Scram FO-2011-01 The inspectors reviewed the circumstances associated with the reactor scram that had occurred on December 23, 2011, and the licensees December 24, 2011, decision to restart the plant, to verify that the plant had responded to the reactor scram as designed, and to verify that the decision to restart the plant had been made in accordance with applicable licensee procedures. Specifically, the inspectors reviewed the licensees determination of the apparent cause of the reactor scram, the equipment issues that had been identified on the Post Trip Checklist required by procedure GP-0003, Scram Recovery, and the licensees responses to those issues. The inspectors also reviewed records associated with the licensees decision to restart the unit, including the records compiled and reviewed in accordance with procedure GP-0003 and the information reviewed during various meetings of the Operations Support Review Committee. In addition, the inspectors interviewed various plant personnel who had been involved in the equipment issues and/or the restart decision. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of one event follow-up inspection sample as defined in Inspection Procedure 71153.

b.

No findings were identified.

Findings

.4 Selected Issue Follow-up Inspection

The inspectors reviewed the corrective action programs effectiveness in regards to the corrective actions associated with improper lubrication of bearings in the standby service water system. The inspectors found that the extent of condition review was inadequate in that the scope was limited to safety-related applications. The inspectors performed walk downs of high risk non-safety related equipment and found excess grease in the condensate pump lower motor bearings. Following this, further inspections performed by the licensee found excessive grease in the Division 3 standby diesel generator shaft bearings. The licensee documented the observations in CR-RBS-2012-01366.

Motor Bearing Greasing Extent of Condition

Tritium Detected in Groundwater During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting tritium found in groundwater sampling well located on station property. The licensees observations are documented in CR-RBS-2011-08993.Tritium concentration was reported as 48,244 picocuries per liter. The stations voluntary reporting limit is 30, 000 picocuries per liter. No other radionuclide was detected. The tritium was found in the Upland Terrace Aquifer which is hydrologically connected to the Mississippi River Alluvial Aquifer. The inspectors are following the stations actions to identify the source of the tritium through scheduled inspection of underground piping and tanks, sampling of storm drains and surface water, and recently drilled well monitoring sites.

These activities constitute completion of four in-depth problem identification and resolution samples as defined in Inspection Procedure 71152-05.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000458/2011-003-00:

Automatic Reactor Scram Due to a Main Turbine Trip On December 23, 2011, the main turbine tripped unexpectedly, resulting in a reactor scram. The cause of the turbine trip was a spurious backup over-speed trip resulting from an electrical discharge from the turbine shaft in the vicinity of the electro-hydraulic control turbine speed pickup probe. There were two root causes of the electrical discharge. First was the failure of the shaft grounding system. Specifically, the support bracket for the mid standard grounding brush was not fabricated such that the brush contacts the shaft per the manufacturers directions. The second root cause is indeterminate. Electrical motive force occurred on the shaft or inside the front standard affecting the speed signals causing a false indication of an overspeed condition in the electro-hydraulic controls speed control system. The exact cause of the electromotive force could not be determined based on inspections and testing with the turbine on turning gear during the last forced outage (FO-11-01). This licensee event report is closed.

b.

Introduction.

The inspectors reviewed a self-revealing finding regarding the improper fabrication of a turbine shaft grounding brush that resulted in turbine trip and subsequent reactor scram. The licensee identified the improper fabrication of a turbine shaft grounding brush as the cause of as a spurious main turbine over-speed trip signal from an electrical discharge from the turbine shaft.

Findings

Description.

On December 23, 2011, a main turbine control valve fast closure signal caused a main turbine trip and an automatic reactor scram. The licensee identified the cause of the turbine control valve fast closure signal was a spurious backup over-speed trip signal resulting from an electrical discharge from the turbine shaft in the vicinity of the electro-hydraulic control system turbine speed pickup probe. The cause of the electrical discharge was due to a failure of the shaft grounding system.

The turbine shaft grounding system has four turbine shaft brushes, three of which provide ground protection. This system was modified in 2004 to add a new brush at the mid-standard location. To maintain shaft contact, this brush was designed to pivot as the brush wore. The troubleshooting team removed the mid-standard brush and found it had very little wear relative to the time the brush was in service, indicating that that the brush was not in constant contact with the turbine shaft to provide ground protection.

The licensee concluded that the mid-standard brush wore until the brush reached its maximum useful pivot range, afterwards the brush lost contact with the shaft. The investigation found that the angle between the brush head and the shaft was incorrect because the mounting bracket for the brush was not fabricated per the manufacturers in accordance with technical manual Sohre Turbomachinery VTD S966-0100, Type 15/LW-STD Shaft-Riding Brush Specifications. The work order instructions were accurate but the field implementation did not meet the criteria. A post maintenance test to verify grounding brush installation was signed satisfactory though the acceptance criteria for the brush wear indicator was not met. If the grounding brush had been functioning properly to prevent shaft voltage build up and subsequent discharge, the turbine trip would not have occurred.

Analysis.

The licensee fabricated the mid-standard turbine shaft brush contrary to vendor technical instructions and is a performance deficiency. The resulting installation failed to ground stray electrical currents that caused a spurious turbine speed control trip signal, subsequent turbine trip and reactor scram. The finding was more than minor because it was associated with the equipment performance 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 during shutdown as well as power operations. The inspectors reviewed the finding using IMC 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations. Based on the Phase 1 screening of the finding, the inspectors determined that the finding was of very low safety significance (Green) because it did not affect loss of coolant accident initiators, did not contribute to increasing the likelihood of both an initiating event and affecting mitigating equipment, and did not increase the likelihood of a fire or flood. The apparent cause of the performance deficiency was the failure in 2004 to appropriately perform a post maintenance test for the turbine shaft grounding brush modification. Therefore the inspectors did not identify a cross-cutting aspect because the performance deficiency is not indicative of the licensees current performance.

Enforcement.

The inspectors determined that the failure to properly fabricate and install the mid-standard turbine shaft brush was a finding. However, no violation of regulatory requirements occurred. This issue was entered into the licensees corrective action program as Condition Report CR-RBS-2012-9053 and is designated as FIN 05000458/2012002-9), Failure to Properly Fabricate and Install the mid-Standard Turbine Shaft Brush.

4OA5 Other Activities

.1 (Closed) Temporary Instruction 2515/185 Follow-up on the Industrys Ground Water

Protection Initiative

a. Inspection Scope

An NRC assessment of the licensees groundwater protection program was performed the week of February 27, 2012, to determine whether the licensee implemented the program elements in this ground water protection program that were identified as incomplete in the Summary of Results from the Completion of NRCs Temporary Instruction on Groundwater Protection, TI-2515/173, Industry Groundwater Protection Initiative (ML11088A047). Descriptions of the program elements can be found in NEI 07-07, Industry Ground Water Protection Initiative - Final Guidance Document, August 2007 (ML072610036). Inspectors interviewed personnel, performed walk-downs of selected areas, and reviewed the implementation of the following program elements.

• Element 1.1a - perform hydrogeologic studies to determine predominant ground water flow characteristics and gradients

• Element 1.1d - Establish the frequency for periodic reviews of site hydrogeologic studies.

• Element 1.2a - Identify each system, structure, and component and work practice that involves or could reasonably be expected to involve licensed material and for which there is a credible mechanism to reach ground water.

• Element 1.2b - Identify existing leak detection methods for each system, structure, and component and work practice that involves or could involve licensed material and for which there is a credible potential for inadvertent releases to ground water.

• Element 1.2c - Identify potential enhancements to leak detection systems or programs.

• Element 1.2d - Identify potential enhancements to prevent spills or leaks from reaching ground water.

• Element 1.2f - Establish long-term programs to perform preventative maintenance or surveillance activities to minimize the potential for inadvertent releases of licensed materials due to equipment failure.

• Element 1.2g - Establish the frequency for periodic reviews of systems, structures, and components and work practices.

• Element 1.3d - Establish a formal, written program for long-term ground water monitoring. For those ground water monitoring locations that are included in the REMP, revise the sites Offsite Dose Calculation Manual.

• Element 1.3f - Establish a long-term program for preventative maintenance of ground water wells.

• Element 1.3g - Establish the frequency for periodic review of the ground water monitoring program.

• Element 1.4a - Establish written procedures outlining the decision making process for remediation of leaks and spills or other instances of inadvertent releases.

• Element 2.4a - The appropriate changes to the Offsite Dose Calculation Manual or to the appropriate procedures were expected to be completed in a timeframe to support the 2007 report of 2006 performance for plants that were operating or decommissioning when the groundwater protection initiative was adopted.

• Element 3.1c - The self-assessment, at a minimum, shall include evaluating the implementation of all objectives identified in NEI 07-07.

All elements were verified as complete.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On February 9, 2012, the inspectors presented the preliminary permanent plant modifications inspection results to Mr. Eric Olson, Site Vice President, and other members of the licensees staff. The licensee acknowledged the results as presented. While some proprietary information was reviewed during this inspection, no proprietary information was included in this report.

On March 1, 2012, the inspectors presented the results of the radiation safety inspections to E. Olson, Site Vice President, and other members of the licensee staff. 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.

On April 12, 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.

4OA7 Licensee-Identified Violations

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

.1 The licensee identified two examples of violations of Technical Specification 5.4.1.

Technical Specification 5.4.1 requires, in part, that written procedures shall be implemented covering the procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Section 9, says, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, on November 17, 2011 and November 26, 2011, the licensee completed maintenance that affected the performance of safety-related equipment, was not preplanned, and was not performed in accordance with any written procedure, documented instruction, or drawing. On November 17, 2011, a worker tightened packing on standby service water pump motor 2A to reduce system leakage and on November 26, 2011, a worker added oil to the control building chillers D to address low system oil. In both of these examples, workers performed work on safety-related equipment under "tool-pouch" maintenance without work orders which is contrary to the requirements of Entergy Nuclear Management Manual WM-100, "Work Request Generation, Screening and Classification." The finding is considered to be of very low safety significance (Green),because it was not a design or qualification deficiency; did not represent either a loss of system safety function, an actual loss of safety function of a single train, or an actual loss of safety function; and did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The issue has been entered into the licensees corrective action program as Condition Report CR-RBS-2011-08647.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

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

M. Feltner, Manager, Planning and Scheduling, Outages

C. Forpahl, Manager, System Engineering

A. Fredieu, Manager, Outage

R. Gadbois, General Manager, Plant Operations

T. Gates, Assistant Operations Manager - Shift

H. Goodman, Director, Engineering

G. Hackett, Manager, Radiation Protection

R. Heath, Assistant Manager, Maintenance

K. Huffstatler, Senior Licensing Specialist

L. Kitchen, Manager, Maintenance

G. Krause, Assistant Operations Manager - Support

L. Meyer, Senior Health Physicist/Chemistry Specialist

E. Neal, Supervisor, Radiation Protection

E. Olson, Site Vice President

R. Persons, Superintendent, Training

J. Roberts, Director, Nuclear Safety Assurance

T. Santy, Manager, Security

T. Shenk, Assistant Operations Manager - Training

W. Spell, Senior Health Physicist/Chemistry Specialist

M. Spustack, Supervisor, Engineering

D. Vines, Manager, Corrective Actions and Assessments

J. Volmer, Senior Health Physicist/Chemistry Specialist

J. Vukovics, Supervisor, Reactor Engineering

N. Wood, Engineering

L. Woods, Manager, Quality Assurance

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000458/2012002-01 NCV Failure to Adequately Monitor the Performance of the Digital Radiation Monitoring System (1R12)

05000458/2012002-02 NCV Failure to Appropriately Assess and Manage Risk for Internal Flooding Events (1R13)

05000458/2012002-03 NCV Failure to Verify Assumptions used in Standby Equipment Room Temperature Analysis (1R17)

05000458/2012002-04 NCV Failure to Appropriately Set Reactor Core Isolation Cooling Flow Controller High Output Limit (1R19)

05000458/2012002-05 FIN Inadequate Relief Valve Configuration Control Results in a Reactor Downpower (1R19)

05000458/2012002-06 NCV Inadequate Maintenance Instructions for the Suppression Pool Cooling Isolation Valves (1R22)

05000458/2012002-07 NCV Failure to Perform a Radiation Survey (2RS02)

05000458/2012002-08 NCV Failure to Control Access to a High Radiation Area (2RS02)

05000458/2012002-09 FIN Failure to Properly Fabricate and Install the mid-Standard Turbine Shaft Brush (4OA3)

Closed

05000458/2011-003-00 LER Automatic Reactor Scram Due to a Main Turbine Trip