IR 05000458/2011004

IR 05000458-11-004; on 07/01/2011 – 09/30/2011; River Bend Station; Integrated Resident and Regional Report; Postmaintenance Testing

ML113140169
Person / Time
Site:	River Bend
Issue date:	11/09/2011
From:	Vincent Gaddy NRC/RGN-IV/DRP/RPB-C
To:	Olson E Entergy Operations
References
IR-11-004
Download: ML113140169 (49)

Text

November 9, 2011

Eric Site Vice President Entergy Operations, Inc.

River Bend Station 5485 US Highway 61 St. Francisville, LA 70775

Subject: RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT NUMBER 05000458/2011004

Dear Mr. Olson:

On September 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your River Bend Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on October 12, 2011, with you and other members of your staff.

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

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

Based on the results of this inspection, the NRC has identified two issues that were evaluated under the risk significance determination process as having very low safety significance (Green). The NRC has determined that a violation was associated with one of these issues.

However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a noncited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy. Additionally, five licensee-identified violations, which were determined to be of very low safety significance, are listed in this report.

If you contest the violations or the significance of the noncited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.

20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the River Bend Station facility. In addition, if you disagree with the crosscutting aspect assigned to any finding 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

612 EAST LAMAR BLVD, SUITE 400 ARLINGTON, TEXAS 76011-4125

Entergy Operations, Inc.

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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 you choose to provide one for cases where a response is not required, will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not include any personal privacy or proprietary information so that it can be made available to the public without redaction.

Sincerely, RC Hagar for V Gaddy Vincent G. Gaddy, Chief Project Branch C Division of Reactor Projects

Docket: 50-458 License: NPF-47

Enclosure:

NRC Inspection Report 05000458/2011004 w/Attachment: Supplemental Information

REGION IV==

Docket:

05000458 License:

NPF-47 Report:

05000458/2011004 Licensee:

Entergy Operations, Inc.

Facility:

River Bend Station Location:

5485 U.S. Highway 61 St. Francisville, LA Dates:

July 1 through September 30, 2011 Inspectors:

G. Larkin, Senior Resident Inspector, Project Branch C A. Barrett, Resident Inspector, Project Branch C R. Hagar, Senior Project Engineer, Project Branch C L. Ricketson, Senior Health Physicist, Plant Support Branch 2 B. Baca, Health Physicist, Technical Support Branch C. Alldredge, Health Physicist, Plant Support Branch 2 Approved By:

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

- 2 -

Enclosure

SUMMARY OF FINDINGS

IR 05000458/2011004; 07/01/2011 - 09/30/2011; River Bend Station; Integrated Resident and

Regional Report; Postmaintenance Testing

The report covered a 3-month period of inspection by resident inspectors and an announced baseline inspection by region-based inspectors. One Green noncited violations and one Green finding 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 crosscutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross Cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a self-revealing finding involving inadequate corrective actions in response to a failure in the main steam equalizing header drain bypass valve, resulting in a steam leak and an unplanned plant down power. Specifically, plant personnel failed to properly address the dual indication on the bypass valve and fluid flow through the valve caused water to flash to steam accelerating pipe wall erosion and piping failure. The licensees immediate corrective actions were to identify, secure, and temporarily repair the steam leak. The licensee entered this issue into the licensees corrective action program as Condition Report CR-RBS-2011-04592.

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 Inspection Manual Chapter 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 was not a loss of coolant accident initiator, did not contribute to both the likelihood of an initiating event and the likelihood that mitigating equipment or functions would not be available, nor increase the likelihood of an external event (seismic, flooding, or severe weather event). The apparent cause of the performance deficiency was that the control room and outage control center personnel presumed that the main control room dual indication for the valve was incorrect because previously valve operation successfully closed the valve. Consequently, this finding has a crosscutting aspect in the area of human performance associated with the decision-making component because station personnel did not use a systematic process to assess the condition of the bypass valve, and failed to verify the validity of the underlying assumptions that were used to justify operation with the valve having dual indications H.1(a)(Section 4OA2).

Cornerstone: Barrier Integrity

Green.

The inspectors identified a noncited violation of 10 CFR Part 50,

Appendix B, Criterion III Design Control, for an inadequate calculation methodology used in determining standby gas treatment system operability. The inspectors found that the calculation neither considered instrument uncertainty nor applied a proper voltage drop from the breaker to the standby gas treatment system filter train heater. The licensee entered this issue into the licensees corrective action program as Condition Report CR-RBS-2011-07332.

The finding was more than minor because it was associated with the design control attribute of the Barrier Integrity Cornerstone to maintain radiological barrier functionality of standby gas treatment trains, and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Specifically, operating the standby gas system filter train heaters without sufficient output power is detrimental to the charcoal filters ability to retain radioactive iodine. This could result in a greater amount of radiation release to the environment in the event of an accident. In accordance with Inspection manual Chapter 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the Phase 1 significance determination process screening determined the finding to be only of very low safety significance (Green) because the finding only represented a degradation of the radiological barrier function provided for the standby gas treatment system.

The apparent cause of this finding was the decision to develop an engineering evaluation that did not include instrument uncertainly and did not validate the correct voltage drop between the filter train heater feeder breaker and the heater elements. The finding has a crosscutting aspect in the area of human performance associated with the decision-making component because station personnel failed to use conservative assumptions when developing the modified output power methodology for operation of the standby gas treatment system filter heaters with only 8 of 9 heater elements installed H.1(b)(1R19 b.2).

Licensee-Identified Violations

Five violations of very low safety significance, which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

River Bend Station began the inspection period at 100 percent rated thermal power. On July 8, 2011, the plant reduced reactor power to 66 percent to perform control rod insertion tests, perform turbine bypass valve testing, and complete a control rod sequence exchange.

The plant returned to full power on July 10, 2011. On September 23, 2011, the plant reduced reactor power to 61 percent to complete a control rod sequence exchange. The plant returned to full power on September 27, 2011, and remained at 100 percent reactor power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

Summer Readiness for Offsite and Alternate-ac Power a.

The inspectors performed a review of preparations for summer weather for selected systems, including conditions that could lead to loss-of-offsite power and conditions that could result from high temperatures. The inspectors reviewed the procedures affecting these areas and the communications protocols between the transmission system operator and the plant to verify that the appropriate information was being exchanged when issues arose that could affect the offsite power system. Examples of aspects considered in the inspectors review included:

Inspection Scope

• The coordination between the transmission system operator and the plants operations personnel during off-normal or emergency events

• The explanations for the events

• The estimates of when the offsite power system would be returned to a normal state

• The notifications from the transmission system operator to the plant when the offsite power system was returned to normal

During the inspection, the inspectors focused on plant-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Safety Analysis Report and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. Specific

documents reviewed during this inspection are listed in the attachment. The inspectors also reviewed corrective action program items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant systems:

• Emergency diesel generators

• Fancy Point switchyard

These activities constitute completion of one readiness for summer weather effect on offsite and alternate-ac power sample as defined in Inspection Procedure 71111.01-05.

b.

No findings were identified.

Findings

1R04 Equipment Alignments

Partial Walkdown a.

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

Inspection Scope

• Reactor core isolation cooling system following system maintenance

• Division 2 standby service water during Division 3 emergency core cooling system testing

• Standby gas treatment B during Division 1 surveillance

• Division 1 main steam positive leakage control system while Division 2 was out of service for unplanned maintenance and troubleshooting

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Safety Analysis Report, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The

inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

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

b.

No findings were identified.

Findings

1R05 Fire Protection

.1 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

• July 19, 2011, reactor core isolation cooling pump room, fire area AB-4/Z-1 and Z-2

• July 19, 2011, D-Tunnel, fire area AB-7

• July 29, 2011, radwaste building, 106-foot elevation, fire area RW-106

• August 14, 2011, auxiliary building, 141-foot elevation and 98-foot elevation

• August 16, 2011, normal switchgear building, 98-foot elevation and 123-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

1R07 Heat Sink Performance

a.

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the containment and auxiliary building unit coolers (both divisions). The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines; the licensee properly utilized biofouling controls; the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

These activities constitute completion of one heat sink inspection sample as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

a.

On August 31, 2011, the inspectors observed a crew of licensed operators in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

Inspection Scope

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely actions in the conservative direction

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications

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

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

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

1R12 Maintenance Effectiveness

a.

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

Inspection Scope

• Safety-related structures and the structural monitoring program

• Low pressure core spray system

In addition, the inspectors reviewed the biennial Maintenance Rule (a)(3) report per the inspection guidance document.

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 three quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b.

No findings were identified.

Findings

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

• Control rod drive pump failed postmaintenance testing, July 1, 2011

• Emergent work in Fancy Point switchyard, August 8, 2011

• Planned maintenance on the control room fresh air system, August 29, 2011

• Planned maintenance on a service water cooling fan and heat exchanger, September 12, 2011

• Elevated risk during RHR maintenance and switchyard work, September 13, 2011

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.

No findings were identified.

Findings

1R15 Operability Evaluations

a.

The inspectors reviewed the following issues:

Inspection Scope

• CR-RBS-2011-04859, reactor core isolation cooling suction pressure high following high pressure core spray runs, reviewed on July 18, 2011

• CR-RBS-2011-05439, reactor core isolation cooling turbine speed error during surveillance testing, reviewed on July 21, 2011

• CR-RBS-2011-05597, diesel generator thermostatic valve problem not identified promptly, reviewed on July 21, 2011

• CR-RBS-2011-06063, E12-F048B flexible electrical conduit jacket degraded, reviewed on August 22, 2011

• CR-RBS-2011-06387, main steam positive leakage compressor failures, reviewed on August 29, 2011

• CR-RBS-2011-05395, inadequate design of auxiliary building penetration, reviewed on August 30, 2011

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Updated Safety Analysis Report to the licensee personnels evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

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

These activities constitute completion of six operability evaluation inspection samples as defined in Inspection Procedure 71111.15-04

b.

No findings were identified.

Findings

1R18 Plant Modifications

a.

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

Inspection Scope

• Engineering Change EC-31398, LSV-AOV44B Outlet Restricting Orifice, Revision 0; Engineering Change EC-31483, Remove Level Control Function for SWP-SOV220B, Revision 0; and Engineering Change EC-31488, Revise References to LSV Separator Tank Levels in TMOD EC-31483, Revision 0

• Engineering Change EC-30850, GTS-FLT1B Operation with One Heater Element Out of Service, Revision 0

The inspectors reviewed the temporary modifications and the associated safety-evaluation screening against the system design bases documentation, including the Updated Safety Analysis Report and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel

evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

These activities constitute completion of two samples for temporary plant modifications as defined in Inspection Procedure 71111.18-05.

b.

No findings were identified.

Findings

1R19 Postmaintenance Testing

a.

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

Inspection Scope

• WO 00281193, EGT-TCV20B - Valve is Acting Irregularly (CR-11-4186),reviewed on July 5, 2011

• WO 52272756, SWP-AOV599 - Perform Functional Test of Standby Cooling Tower #1 Station, reviewed on July 6, 2011

• WO 00284943, GTS-FLT1B During Performance of STP-257-0202 Discovered Low, reviewed on August 18, 2011

• WO 00285929, LSV-C3B Water Leaking from LSV-STR10BB While in Service, reviewed on August 21, 2011

• WO 00275198, Replace Relays ENB-INV01B1, reviewed on September 21, 2011

• WO 52249845, 1ENB*CHGR1B Load Test, reviewed on September 27, 2011

• WO 00268148, HVK-TS71D Calibration of Low Chill Water Temperature Pretrip, reviewed on September 29, 2011 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 postmaintenance 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 seven postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b.

===.1

=

The inspectors identified a Green, noncited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for an inadequate calculation methodology used in determining standby gas treatment system operability.

Findings

Description.

On July 21, 2011, the standby gas treatment filter train B heater failed the monthly surveillance test procedure due to an open electrical connection between a heater element and the mounting stud used to secure the element to the bus bar.

The standby gas treatment systems filter train heaters have a total of nine heater elements, three elements per phase. Station engineering personnel developed engineering change EC-30850, GTS-FLT1B Operation with One Heater Element out of Service, to temporarily remove the failed filter train heater element, and revised the surveillance test calculation method for determining filter train power output with only 8 out of 9 heater elements functioning. Technical Specification 5.5.7e, Ventilation Filter Testing Program, requires that standby gas treatment system filter train B dissipate greater than or equal to 61 kW to maintain air relative humidity less than 70 percent passing through the filter. On July 23, 2011, the filter train B passed the revised test procedure with very small margin, producing 61.43 kW. Humidity greater than 70 percent is considered detrimental to the charcoal filters ability to retain radioactive iodine.

On August 17, 2011, the standby gas treatment filter train B heater failed the monthly surveillance test due to only producing 60.28 kW. Operations declared the system inoperable and actions were taken to repair the defective heater element. The system was returned to full qualification with nine heater elements installed, and passed the monthly surveillance.

The inspectors reviewed the modified calculation methodology for standby gas treatment system heater operability. Neither the surveillance test nor engineering change EC-30850 calculation method accounted for instrument uncertainty when determining the kW output. The inspectors concluded that to have reasonable assurance of operability the calculation should have accounted for instrument uncertainty. The margin between the satisfactory test on July 23, 2011, and the

unsatisfactory test on August 17, 2011, was within the instrument tolerances of the different amp and voltmeters used to measure the filter train heater current and voltage use. In addition, questioning by the inspectors revealed that the calculation had used a nonconservative value for the voltage drop from the heater breaker to the heater.

Analysis.

The failure to have an adequate calculation methodology for the standby gas treatment heater output power is a performance deficiency. The inspectors determined that the performance deficiency was similar to the not minor if statement contained in example 3j of Inspection Manual Chapter 0612, Appendix E, Examples of Minor Issues, because reasonable doubt of system operability existed. Using Inspection Manual Chapter 0612, Appendix B, Issue Screening, the inspectors determined that this finding was more than minor because it was associated with the design control attribute of the Barrier Integrity Cornerstone to maintain radiological barrier functionality of standby gas treatment trains, and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, operating the standby gas system filter train heaters without sufficient output power is detrimental to the ability of the charcoal filters to retain radioactive iodine. This could result in a greater amount of radiation release to the environment in the event of an accident. In accordance with Inspection manual Chapter 0609, Appendix A, Significance Determination of Reactor Inspection Findings for At-Power Situations, the Phase 1 significance determination process screening determined the finding to be only of very low safety significance (Green) because the finding only represented a degradation of the radiological barrier function provided for the standby gas treatment system. The apparent cause of this finding was the decision to develop an engineering evaluation that did not include instrument uncertainly and did not validate the correct voltage drop between the filter train heater feeder breaker and the heater elements. The cause of this finding has a crosscutting aspect in the area of human performance associated with the decision-making component because station personnel failed to use conservative assumptions when developing the modified output power methodology for operation of the standby gas treatment system filter heaters with only 8 of 9 heater elements installed H.1(b).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control requires, in part, that design control measures 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 suitable testing program.

Contrary to this, on July 23, 2011, the licensees design control measures did not provide for verifying the adequacy of design, in that those measures failed to verify satisfactory performance of the standby gas treatment system due to the failure of station personnel to account for instrument uncertainty in the modified heater output calculation. Because this finding was of very low safety significance and has been entered into the licensees corrective action program as Condition Report CR-RBS-2100-07332, this violation is being treated as a noncited violation consistent with NRC Enforcement Policy: NCV 05000458/2011004-01, Inadequate Standby Gas Treatment Electric Heater Power Output Calculation.

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:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• 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.

• STP-204-6301, DIV I LPCI (RHR) Pump and Valve Operability Test, performed inservice test sample on July 7, 2011

• STP-257-4501, RMS Primary Containment Purge Isolation Radiation High Activity Monitor Channel Functional Test (RMS-RE21A), on July 10, 2011

• STP-309-0603, Division III ECCS Test, performed on July 26, 2011

• REP-0007, Spent Fuel Pool Coupon Surveillance Program, performed on August 22, 2011

• STP-204-4510, LPCI Pump C Discharge Flow - Low, Channel Functional Test (E12-N652C), performed on September 13, 2011 Specific documents reviewed during this inspection are listed in the attachment.

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

b.

No findings were identified.

Findings

1EP6 Drill Evaluation

Emergency Preparedness Drill Observation a.

The inspectors evaluated the conduct of routine licensee emergency drills on July 14, 2011, and August 2, 2011, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities.

The inspectors observed emergency response operations in the simulator, emergency operations facility, and technical support center 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 two samples as defined in Inspection Procedure 71114.06-05.

b.

No findings were identified.

Findings

2RS0 6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

This area was inspected to:

(1) ensure the gaseous and liquid effluent processing systems are maintained so radiological discharges are properly mitigated, monitored, and evaluated with respect to public exposure;

(2) ensure abnormal radioactive gaseous or liquid discharges and conditions, when effluent radiation monitors are out-of-service, are controlled in accordance with the applicable regulatory requirements and licensee procedures;

(3) verify the licensee=s quality control program ensures the radioactive effluent sampling and analysis requirements are satisfied so discharges of radioactive materials are adequately quantified and evaluated; and

(4) verify the adequacy of public dose projections resulting from radioactive effluent discharges. The inspectors used the requirements in 10 CFR Part 20; 10 CFR Part 50, Appendices A and I; 40 CFR Part 190; the Offsite Dose Calculation Manual, and licensee procedures required by the Technical Specifications as criteria for determining compliance. The inspectors interviewed licensee personnel and reviewed and/or observed the following items:

• Radiological effluent release reports since the previous inspection and reports related to the effluent program issued since the previous inspection, if any

• Effluent program implementing procedures, including sampling, monitor setpoint determinations and dose calculations

• Equipment configuration and flow paths of selected gaseous and liquid discharge system components, filtered ventilation system material condition, and significant changes to their effluent release points, if any, and associated 10 CFR 50.59 reviews

• Selected portions of the routine processing and discharge of radioactive gaseous and liquid effluents (including sample collection and analysis)

• Controls used to ensure representative sampling and appropriate compensatory sampling

• Results of the inter-laboratory comparison program

• Effluent stack flow rates

• Surveillance test results of technical specification-required ventilation effluent discharge systems since the previous inspection

• Significant changes in reported dose values, if any

• A selection of radioactive liquid and gaseous waste discharge permits

• Part 61 analyses and methods used to determine which isotopes are included in the source term

• Offsite dose calculation manual changes, if any

• Meteorological dispersion and deposition factors

• Latest land use census

• Records of abnormal gaseous or liquid tank discharges, if any

• Groundwater monitoring results

• Changes to the licensees written program for indentifying and controlling contaminated spills/leaks to groundwater, if any

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

• Offsite notifications and reports of events associated with spills, leaks, or groundwater monitoring results, if any

• Audits, self-assessments, reports, and corrective action documents related to radioactive gaseous and liquid effluent treatment 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 71124.06-05.

b. Findings

No findings were identified.

2RS0 7 Radiological Environmental Monitoring Program

a. Inspection Scope

This area was inspected to:

(1) ensure that the radiological environmental monitoring program verifies the impact of radioactive effluent releases to the environment and sufficiently validates the integrity of the radioactive gaseous and liquid effluent release program;

(2) verify that the radiological environmental monitoring program is implemented consistent with the licensees technical specifications and/or offsite dose

calculation manual, and to validate that the radioactive effluent release program meets the design objective contained in Appendix I to 10 CFR Part 50; and

(3) ensure that the radiological environmental monitoring program monitors non-effluent exposure pathways, is based on sound principles and assumptions, and validates that doses to members of the public are within the dose limits of 10 CFR Part 20 and 40 CFR Part 190, as applicable. The inspectors reviewed and/or observed the following items:

• Annual environmental monitoring reports and offsite dose calculation manual

• Selected air sampling and thermoluminescence dosimeter monitoring stations

• Collection and preparation of environmental samples

• Operability, calibration, and maintenance of meteorological instruments

• Selected events documented in the annual environmental monitoring report which involved a missed sample, inoperable sampler, lost thermoluminescence dosimeter, or anomalous measurement

• Selected structures, systems, or components that may contain licensed material and has a credible mechanism for licensed material to reach ground water

• Records required by 10 CFR 50.75(g)

• Significant changes made by the licensee to the offsite dose calculation manual as the result of changes to the land census or sampler station modifications since the last inspection

• Calibration and maintenance records for selected air samplers, composite water samplers, and environmental sample radiation measurement instrumentation

• Interlaboratory comparison program results

• Audits, self-assessments, reports, and corrective action documents related to the radiological environmental monitoring program 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 71124.07-05.

b. Findings

No findings were identified.

2RS08 Radioactive Solid Waste Processing, and Radioactive Material Handling, Storage, and Transportation (71124.08)

a. Inspection Scope

This area was inspected to verify the effectiveness of the licensee=s programs for processing, handling, storage, and transportation of radioactive material. The inspectors used the requirements of 10 CFR Parts 20, 61, and 71 and Department of Transportation regulations contained in 49 CFR Parts 171-180 for determining compliance. The inspectors interviewed licensee personnel and reviewed the following items:

• The solid radioactive waste system description, process control program, and the scope of the licensee=s audit program

• Control of radioactive waste storage areas including container labeling/marking and monitoring containers for deformation or signs of waste decomposition

• Changes to the liquid and solid waste processing system configuration including a review of waste processing equipment that is not operational or abandoned in place

• Radio-chemical sample analysis results for radioactive waste streams and use of scaling factors and calculations to account for difficult-to-measure radionuclides

• Processes for waste classification including use of scaling factors and 10 CFR Part 61 analysis

• Shipment packaging, surveying, labeling, marking, placarding, vehicle checking, driver instructing, and preparation of the disposal manifest

• Audits, self-assessments, reports, and corrective action reports radioactive solid waste processing, and radioactive material handling, storage, and transportation performed 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 71124.08-05.

b. Findings

No findings were identified.

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 second 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 Mitigating Systems Performance Index - Heat Removal System (MS08)

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - heat removal system performance indicator for the period from the third quarter 2010 through the second 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, mitigating systems performance index derivation reports, and NRC integrated inspection reports for the period of July 2010 through June 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index - heat removal system sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.3 Mitigating Systems Performance Index - Residual Heat Removal System (MS09)

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - residual heat removal system performance indicator for the period from the third quarter 2010 through the second 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, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of July 2010 through June 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index - residual heat removal system sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.4 Mitigating Systems Performance Index - Cooling Water Systems (MS10)

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the third quarter 2010 through the second 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, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of July 2010 through June 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. 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 mitigating systems performance index - cooling water system sample as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

4OA2 Identification and Resolution of Problems

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

.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 Inspection Scope

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

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

b.

No findings were identified.

Findings

.3 Selected Issue Follow-up Inspection

a.

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting an event involving a downpower due to a steam leak on a main steam equalizing header drain. The inspectors discussed the event with licensee management, engineering, operations, and maintenance personnel to understand the event and the scope of the corrective actions taken by the licensee.

Inspection Scope

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

b.

Introduction.

The inspectors identified a self-revealing, Green finding involving inadequate corrective actions in response to a failure in the main steam equalizing header drain bypass valve, resulting in a steam leak and an unplanned plant down power.

Findings

Description.

On February 12, 2011, during plant start-up from refuel outage 16, plant operators discovered that the main steam equalizing header drain bypass valve had dual position indication instead of closed. This information was reported to the outage control center. Based on previous maintenance during the outage and operation of the valve earlier in the plant start-up, the outage control center and main control room personnel presumed the dual position indication was an indication only issue and the actual valve position was closed as intended. Station management failed to take adequate follow-up actions to ensure the valve was in the closed position, and also failed to address the potential consequences of normal power operations with the valve partially open.

On June 19, 2011, plant operators in the turbine building identified a large steam leak near the condenser. Operators reduced station power to approximately 40 percent in order to facilitate identification of the leak. During the investigation, station personnel found that the main steam equalizing header drain piping developed a through wall leak beyond the bypass valve. The valve had not been in the closed position and was partially open. Consequently, fluid flow through the valve increased, causing water to

flash to steam due to the large pressure drop near the condenser resulting in accelerated pipe wall erosion and piping failure. Station personnel isolated the damaged steam drain piping and returned the plant to full power.

Corrective actions included plans to develop and implement a comprehensive program that establishes nuclear safety culture as the overriding station priority; perform a needs analysis to determine training requirements related to the importance of aggressively pursuing the satisfactory resolution of abnormal conditions (e.g., this condition where a valve dual position indication was not verified by other means as correct); troubleshoot the valve during refueling outage 17 to determine why the valve failed to close; evaluate the piping failure mechanism to incorporate the findings into flow accelerated corrosion program as needed; and replace any damage piping during refueling outage 17.

Analysis.

The failure to ensure that the corrective action process properly addressed the dual indication on the bypass valve during plant start-up was a performance deficiency.

Specifically, EN-LI-102, "Corrective Action Process," states that individuals are required to take immediate actions to resolve adverse conditions to minimize the consequence of the condition. Contrary to this, during refuelling outage 16, the outage control center and main control room personnel failed to adequately investigate the dual indications identified on the main steam equalizing header drain bypass valve. 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 Inspection Manual Chapter 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 was not a loss of coolant accident initiator, did not contribute to both the likelihood of an initiating event and the likelihood that mitigating equipment or functions would not be available, nor increase the likelihood of an external event (seismic, flooding, or severe weather event). The apparent cause of the performance deficiency was that the control room and outage control center personnel presumed that the main control room dual indication for the valve was incorrect because previously valve operation successfully closed the valve. Consequently, this finding has a crosscutting aspect in the area of human performance associated with the decision-making component because station personnel failed to use a systematic process to assess the condition of the bypass valve, and failed to verify the validity of the underlying assumptions that were used to justify operation with the valve having dual indication

H.1(a).

Enforcement.

Enforcement action does not apply because the performance deficiency did not violate regulatory requirements. Because this finding does not involve a violation of regulatory requirements and has very low safety significance, it is characterized as a finding and is designated as FIN 05000458/2011004-02, Ineffective Corrective Actions on the Main Steam Equalizing Header Drain Bypass Valve Results in an Unplanned Down Power.

.4 Selected Issue Follow-up Inspection

a.

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting a human performance error involving an operator performing maintenance on the emergency diesel generator without a work order. The inspectors discussed the event with licensee management, engineering, and operations to understand the human performance error and the scope of the corrective actions taken by the licensee. The inspectors determined that the error was a minor violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for performing maintenance on the emergency diesel generator lube oil strainer without appropriate work instructions.

Inspection Scope

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

b.

No findings were identified.

Findings

.5 Selected Issue Follow-up Inspection

a.

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting multiple human performance errors involving a misalignment of the reactor water cleanup system. The inspectors discussed the event with licensee management and operations to understand the human performance errors and the scope of the corrective actions taken by the licensee. The inspectors determined that the error was a minor violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for failure to follow procedure.

Inspection Scope

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

b.

No findings were identified.

Findings

4OA6 Meetings

Exit Meeting Summary

On September 16, 2011, the inspectors presented the results of the radiation safety inspections to Mr. 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 October 12, 2011, the inspectors presented the integrated inspection results to Mr. E. Olson, Site Vice President, and other members of the licensee staff. The licensee acknowledged the issues presented. The 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 violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy for being dispositioned as noncited violations:

.1 Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that

measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to these requirements, the licensee took incomplete measures to ensure the completion of slow turbine rolls to remediate the air voiding in the lube oil system of the reactor core isolation cooling turbine. On April 17, 2010, operations reported a low oil level in both sight glasses of the reactor core isolation cooling turbine. The investigation attributed the cause of the low oil level as a failure to perform a slow roll on the reactor core isolation cooling turbine following system maintenance. On February 10, 2011, during the plant start-up from refueling outage 17, station management canceled the work order to perform the slow roll of the reactor core isolation cooling turbine following lube oil system maintenance, resulting in air accumulating in the lube oil system. The finding was 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-2010-03854.

.2 Technical Specification 5.4.1 requires that written procedures shall be established,

implemented, and maintained covering, in part, the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. In RG 1.33, section 9 of Appendix A says, in part, that maintenance that can affect the performance of safety-related equipment should be performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, between February 4, 2011, and February 7, 2011 the licensee performed maintenance that could affect the performance of safety-related equipment in accordance with documented instructions that were not appropriate to the circumstances, in that:

• Removing temporary filter media installed in safety-related unit coolers was maintenance that could affect the performance of safety-related equipment.

• Removal of filter media was performed in accordance with task 02 of work order 230363.

• Although task 02 of work order 230363 identified the unit coolers from which filter media were to be removed, task 02 of work order 230363 did not include details that described behind which unit cooler door the media were located. It also did not include criteria for determining that the media had been successfully removed.

As a result, on March 3, 2011, a worker assigned to verify that filter media had been removed from safety-related unit coolers via task 02 of work order 230363 failed to locate the installed filter media and signed off on the work order to indicate that the media had been removed. This issue is addressed in the licensees corrective action program in Condition Report CR-RBS-2010-04331.

.3 Technical Specification 5.4.1 requires that written procedures shall be established,

implemented, and maintained covering, in part, the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. In RG 1.33, section 9 of Appendix A says, in part, that maintenance that can affect the performance of safety-related equipment should be performed in accordance with written procedures appropriate to the circumstances. EN-WM-102, Work Implementation and Closeout, constituted documented instructions that were appropriate to the circumstances of performing maintenance that could affect the performance of safety-related equipment.

Removing temporary filter media from various unit coolers as described in task 02 of work order 230363 was maintenance that could affect the performance of safety-related equipment. Contrary to the above, on February 7, 2011, before workers had completed task 02 of work order 230363, a Supervisor/Lead Worker set the status of that task to FINISHED within the work-control database without reviewing the associated task paperwork for signoffs/signatures. As a result, task 02 of work order 230363 was not completed, and temporary filter media remained in several unit coolers as the licensee started up the plant and returned it to full power. This issue is addressed in the licensees corrective action program in Condition Report CR-RBS-2010-04331.

.4 Technical Specification 5.4.1 requires that written procedures shall be established,

implemented, and maintained covering, in part, the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. In RG 1.33, section 9 of Appendix A says, in part, that maintenance that can affect the performance of safety-related equipment should be performed in accordance with written procedures appropriate to the circumstances. Procedure EN-MA-101, Fundamentals of Maintenance, Rev. 9, in part, requires workers to place the equipment being worked on in a safe condition and contact their supervisor if any unexpected condition, event or results occur during the performance of the job. It also requires the worker to initiate a corresponding Condition Report. Contrary to the above, on March 3, 2011, after the licensee had discovered that not all signatures had been entered into task 02 of work order 230363 and a Mechanical Maintenance worker had been assigned to verify that the filter media installed under task 01 of work order 230363 had been removed, an unexpected condition occurred, in that although task 02 of work order 230363 indicated that some filter media were still installed, the worker found no filter media where he looked. When this occurred, that worker did not contact his supervisor and did not

initiate a condition report. Instead, the worker signed task 02 of work order 230363 to indicate that the media had been removed. As a result, temporary filter media that should have been but were not removed via that task at the end of the refueling outage remained in several unit coolers as the plant operated at full power. This issue is addressed in the licensees corrective action program in Condition Report CR-RBS-2010-04331.

.5 Title 10 CFR 50 Appendix B, Criterion XVI, Corrective Action, states, in part, that

measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to these requirements, plant personnel failed to properly evaluate and correct a damaged temperature control valve on the Division II emergency diesel generator jacket water system. During maintenance on the valve, the valve bonnet assembly fell approximately three feet from the top of the work table to the concrete floor causing a bend in the valve crank frame, which is a non-pressure retaining part. A condition report documented the damage, but station management failed to perform a formal assessment or a use as-is evaluation before installing the damaged pressure control valve bonnet assembly back into the valve body on the Division II emergency diesel generator. 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-2010-04785.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

D. Burnett, Manager, Emergency Preparedness

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

M. Chase, Manager, Training

W. Chatterton, Sr. Lead Technical Specialist, Program & Components Engineering

H. Choate, Engineer, System Engineering

J. Clark, Manager, Licensing

L. Coats, Senior Health Physicist/Chemistry Specialist

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

W. Fountain, Senior Licensing Specialist

R. Gadbois, General Manager, Plant Operations

T. Gates, Assistant Operations Manager - Shift

H. Goodman, Director, Engineering

D. Heath, Supervisor, Radiation Protection

R. Heath, Manager, Chemistry

K. Huffstatler, Senior Licensing Specialist

L. Kitchen, Manager, Maintenance

G. Krause, Assistant Operations Manager - Support

E. Olson, Site Vice President

R. Persons, Superintendent, Training

G. Pierce, Manager, Radiation Protection

J. Roberts, Director, Nuclear Safety Assurance

J. Schlesinger, Senior Engineer, Design Engineering

T. Shenk, Assistant Operations Manager - Training

W. Spell, Senior Health Physicist/Chemistry Specialist

M. Spustack, Supervisor, Engineering

J. Standridge, Planner, Emergency Preparedness

N. Tison, Planner, Emergency Preparedness

D. Vines, Manager, Corrective Actions and Assessments

J. Vukovics, Supervisor, Reactor Engineering

J. Wilson, Supervisor, System Engineering

L. Woods, Manager, Quality Assurance

S. Zabaski, Senior Health Physicist/Chemistry Specialist

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000458/2011004-01 NCV Inadequate Standby Gas Treatment Electric Heater Power Output Calculation

05000458/2011004-02 FIN Ineffective Corrective Actions on the Main Steam Equalizing Header Drain Bypass Valve Results in an Unplanned Down Power