ML062260238

IR 05000458/2006003; 04/01/2006 - 06/30/2006; River Bend Station; Operability Evaluations, Refueling and Other Outage Activities, Surveillance Testing, Occupational Radiation Safety

ML062260238
Person / Time
Site:	River Bend
Issue date:	08/14/2006
From:	Kennedy K M NRC/RGN-IV/DRP/RPB-C
To:	Hinnenkamp P D Entergy Operations
References
IR-06-003
Download: ML062260238 (45)

See also: IR 05000458/2006003

Text

August 14, 2006Paul D. HinnenkampVice President - Operations

Entergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA

70775SUBJECT:RIVER BEND STATION - NRC INTEGRATED INSPECTIONREPORT 05000458/2006003Dear Mr. Hinnenkamp:

On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection atyour River Bend Station. The enclosed integrated inspection report documents the inspectionresults, which were discussed on July 5, 2006, with you and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

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

personnel.The report documents three

NRC-identified findings and two self-revealing findings of very lowsafety significance (Green). The NRC has also determined that violations are associated withthese findings. However, because these violations were of very low safety significance and

were entered into your corrective action program, the NRC is treating these violations as

noncited violations, consistent with Section VI.A.1 of the NRC Enforcement Policy. If youcontest the violations or the significance of the violations, you should provide a response within30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear

Regulatory Commission, ATTN: document Control Desk, Washington, DC 20555-0001, withcopies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 611

Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement,U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resi dentInspector at the River Bend Station facility.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in theNRC Public Document Room or from the Publicly Available Records (PARS) com

ponent ofNRC's document system (ADAMS). ADAMS is accessible from the NRC Website at

http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Entergy Operations, Inc.-2-Should you have any questions concerning this inspection, we will be pleased to discuss themwith you.Sincerely,/RA/Kriss M. Kennedy, ChiefProject Branch C

Division of Reactor ProjectsDocket: 50-458License: NPF-47Enclosure:NRC Inspection Report 05000458/2006003 w/Attachment: Supplemental Informationcc w/enclosure:Senior Vice President and

Chief Operating Officer

Entergy Operations, Inc.

P.O. Box 31995

Jackson, MS 39286-1995Vice President Operations Support

Entergy Operations, Inc.

P.O. Box 31995

Jackson, MS 39286-1995General ManagerPlant Operations

Entergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA

70775Director - Nuclear SafetyEntergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA

70775Wise, Carter, Child & Caraway

P.O. Box 651

Jackson, MS 39205

Entergy Operations, Inc.-3-Winston & Strawn LLP1700 K Street, N.W.

Washington, DC 20006-3817Manager - LicensingEntergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA

70775The Honorable Charles C. Foti, Jr.Attorney General

Department of Justice

State of Louisiana

P.O. Box 94005

Baton Rouge, LA 70804-9005H. Anne Plettinger

3456 Villa Rose DriveBaton Rouge, LA 70806Bert Babers, PresidentWest Feliciana Parish Police Jury

P.O. Box 1921

St. Francisville, LA

70775Richard Penrod, Senior Environmental Scientist

Office of Environmental Services

Northwestern State University

Russell Hall, Room 201

Natchitoches, LA 71497Brian AlmonPublic Utility Commission

William B. Travis Building

P.O. Box 13326

1701 North Congress Avenue

Austin, TX 78711-3326

Entergy Operations, Inc.-4-ChairpersonDenton Field Office

Chemical and Nuclear Preparedness

and Protection Division

Office of Infrastructure Protection

Preparedness Directorate

Dept. of Homeland Security

800 North Loop 288

Federal Regional Center

Denton, TX 76201-3698

Entergy Operations, Inc.-5-Electronic distribution by RIV:Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Senior Resident Inspector (PJA)Branch Chief, DRP/C (KMK)Senior Project Engineer, DRP/C (WCW)Team Leader, DRP/TSS (RLN1)RITS Coordinator (KEG)DRS STA (DAP)J. Lamb, OEDO RIV Coordinator (JGL1)ROPreports

RBS Site Secretary (LGD)W. A. Maier, RSLO (WAM)SUNSI Review Completed: __wcw_ ADAMS: Yes G No Initials: __wcw___ Publicly Available

G Non-Publicly Available

G Sensitive Non-SensitiveR:\_REACTORS\_RB\2006\RB2006-03RP-PJA.wpdRIV:SRI:DRP/CRI:DRP/CC:DRS/OBC:DRS/EB1C:DRS/PSBPJAlterMOMillerATGodyJAClarkMPS

hannon T - WCWalker E - WCWalker /RA/ /RA/ /RA/8/10/068/10/068/11/068/10/068/10/06C:DRS/EB2SRA:DRSC:DRP/CLJSmithDPLovelessKMKennedy /RA/ /RA/ /RA/8/10/068/14/068/14/06OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

Enclosure-1-U.S. NUCLEAR REGULATORY COMMISSIONREGION IVDocket:50-458License:NPF-47

Report:05000458/2006003

Licensee:Entergy Operations, Inc.

Facility:River Bend StationLocation:5485 U.S. Highway 61St. Francisville, LouisianaDates:April 1 to June 30, 2006

Inspectors:P. Alter, Senior Resident Inspector, Project Branch CM. Miller, Resident Inspector, Project Branch CG. Werner, Senior Project Engineer, Project Branch D

L. Ricketson, P.E., Senior Health Physicist, Plant Support Branch

W. Sifre, Senior Reactor Inspector, Engineering Branch 1Approved By:Kriss M. Kennedy, ChiefProject Branch C

Division of Reactor Projects

Enclosure-2-TABLE OF CONTENTSSUMMARY OF FINDINGS....................................................3REPORT DETAILS..........................................................6

REACTOR SAFETY.........................................................61R01Adverse Weather Protection

.......................................61R04Equipment Alignment

.............................................71R05Fire Protection

..................................................71R08Inservice Inspection Activities

......................................81R11Licensed Operator Requalification Program

...........................91R12Maintenance Effectiveness.......................................101R13Maintenance Risk Assessments and Emergent Work Control.............101R14Operator Performance During Nonroutine Evolutions and Events..........111R15Operability Evaluations..........................................121R19Postmaintenance Testing........................................171R20Refueling and Other Outage Activities...............................171R22Surveillance Testing............................................201R23Temporary Plant Modifications....................................231EP6Drill Evaluation.................................................23RADIATION SAFETY.......................................................242OS1Access Control to Radiologically Significant Areas.....................242OS2ALARA Planning and Controls.....................................27OTHER ACTIVITIES........................................................284OA1Performance Indicator (PI) Verification..............................284OA2Identification and Resolution of Problems............................294OA3Event Followup................................................314OA5Other Activities.................................................324OA6Meetings, Including Exit..........................................32SUPPLEMENTAL INFORMATION............................................A-1

KEY POINTS OF CONTACT................................................A-1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED...........................A-1LIST OF DOCUMENTS REVIEWED..........................................A-2

LIST OF ACRONYMS......................................................A-7

Enclosure-3-SUMMARY OF FINDINGSIR 05000458/2006003; 04/01/2006 - 06/30/2006; River Bend Station; Operability Evaluations,Refueling and Other Outage Activities, Surveillance Testing, Occupational Radiation Safety.The report covered a 3-month period of routine baseline inspections by resident inspectors andannounced baseline inspections by regional engineering and radiation protection inspectors.

Five Green noncited violations were identified. The significance of most findings is indicated by

their color (Green, White, Yellow, Red) using Inspection Manual Chapter 0609, "Significance

Determination Process." Findings for which the significance determination process does not

apply may be Green or be assigned a severity level after

NRC management review. TheNRC's program for overseeing the safe operation of commercial nuclear power reactors isdescribed in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.NRC-Identified and Self-Revealing FindingsCornerstone: Mitigating SystemsGreen. A self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI,"Corrective Action," was reviewed involving the failure of the licensee to identify that the

normal supply breaker to the Division III 4.16 kV engineered safety features bus was notproperly racked in for a period of 24 days following maintenance. This issue was

entered into the licensee's corrective action program as CR-RBS-2006-02402.The finding was more than minor because it was associated with the mitigating systemcornerstone attribute of configuration control and affected the associated cornerstone

objective to ensure the availability, reliability, and capability of systems that res

pond toinitiating events to prevent undesirable consequences. Utilizing Manual Chapter 0609,"Significance Determination Process," a Phase 3 analysis concluded that the finding

was of very low safety significance. The cause of the finding was related to the

crosscutting aspect of problem identification and resolution in that the licensee failed toproperly evaluate available indications to identify that the breaker was not properly

racked in. (Section 1R15).Green. An NRC identified noncited violation of 10 CFR 50.65 Maintenance RuleSection (a)(4) was identified for the failure of the licensee to provide prescribed

compensatory measures for two Orange shutdown risk conditions during Refueling

Outage 13. Specifically, the preoutage risk assessment recommended that two workorders be in place for maintenance electricians to provide power to one spent fuel pool

cooling pump in the event of problems with the running pump during periods of electrical

bus maintenance. The inspectors found that the work packages were not in place

before entering shutdown risk condition Orange on April 26, 2006, during the Division II

engineering safety features bus testing, and May 3, 2006, during the Division I

engineered safety features bus outage. This issue was entered into the licensee's

corrective action program as CR-RBS-2006-01937.The finding was more than minor because the licensee failed to implement a prescribedcompensatory measure during the highest risk condition of Refueling Outage 13. The

Enclosure-4-specific compensatory measures were called for in the preoutage risk assessment andthe shutdown operations protection plan. The finding affected the mitigati ng syst emcornerstone because of the increased risk of a sustained loss of spent fuel pool cooling

during core offloading operations. The finding could not be evaluated using the

significance determination process, therefore the finding was reviewed by regional

management and determined to be of very low safety significance. Factors that were

considered included: (1) electrical maintenance technicians had previously performed

the task of providing alternate power to a spent fuel pool cooling pump, (2) the

necessary equipment was staged as part of the abnormal operating procedure for loss

of decay heat removal, and (3) the relatively long "time to boil" of the spent fuel storage

pool at that time during the refueling outage. The cause of the finding was related to thecrosscutting aspect of human performance because the licensee's plannedmaintenance activities and the predetermined increase in outage risk was not effectively

managed by prescribed compensatory measures (Section 1R20).Green. An NRC identified noncited violation of Technical Specification 5.4.1.a wasidentified for the failure of the licensee to provide an adequate surveillance testprocedure to perform Technical Specification Surveillance Requirement 3.8.1.1. Specifically, STP-000-0102, "Power Distribution Alignment Check," Revision 4, did not

verify the required offsite power circuit breaker alignment and indicated power

availability for the Division III 4.16 kV engineered safety features bus as required inModes 1, 2, and 3. This issue was entered into the licensee's corrective action program

as CR-RBS-2006-02675 and -02402.The finding was more than minor because it was associated with the mitigating systemcornerstone attribute of configuration control and affected the associated cornerstone

objective to ensure the availability, reliability, and capability of systems that res

pond toinitiating events to prevent undesirable consequences. Utilizing Manual Chapter 0609,"Significance Determination Process," a Phase 3 analysis concluded that the finding

was of very low safety significance. (Section 1R22).Cornerstone: Occupational Radiation Safety

• Green. The inspector reviewed a self-revealing noncited violation of TechnicalSpecification 5.7.1, resulting from the licensee's failure to control access to a high

radiation area. While transferring reverse osmosis system filters in the radwaste

building, the licensee allowed two workers to inadvertently enter a high radiation area. This occurred after a guard prematurely left his post in front of the 123 foot elevation

elevator door. The highest dose rate recorded by an electronic alarming dosimeter was

164 millirem per hour. The guard returned and evacuated the workers before they accrued additional radiation dose. Planned corrective action was still being evaluated bythe licensee at the conclusion of the inspection.The finding was more than minor because it was associated with the occupationalradiation safety attribute of exposure control and affected the cornerstone objective in

that not controlling a high radiation area could increase personal exposure. Using theOccupational Radiation Safety Significance Determination Process, the inspector

determined that the finding was of very low safety significance because it did not

Enclosure-5-involve: (1) an as low as is reasonably achievable finding, (2) an overexposure, (3) asubstantial potential for overexposure, or (4) an impaired ability to assess dose.

Additionally, this finding had crosscutting aspects associated with human performancein that the failure of the individual to guard the elevator door directly contributed to theviolation. (Section 2OS1)*Green. The inspector identified a noncited violation of 10 CFR 20.1501(a) because thelicense failed to survey airborne radioactivity. During the removal of local power range

monitors, the licensee started collecting an air sample of the work area, but discarded

the sample before analyzing it. Successful passage through the portal monitors at the

exit of the controlled access area confirmed that no worker experienced an uptake of

radioactive material. Planned corrective action is still being evaluated.The finding was more than minor because it was associated with the occupationalradiation safety program attribute of exposure control and affected the cornerstone

objective in that the lack of knowledge of radiological conditions could increase

personnel dose. Using the 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. Additionally, this finding had crosscutti

ng aspects associated with humanperformance in that the failure to maintain the sample for analysis directly contributed to

the violation. (Section 2OS1)B.Licensee-Identified ViolationsNone.

Enclosure-6-REPORT DETAILSSummary of Plant Status: The reactor was operated at 100 percent power from April 1-15,2006, when the reactor scrammed due to a control circuit failure which caused both reactor

recirculation pumps to shift to slow speed. The reactor was restarted on April 17 and attained

100 percent power on April 18. On April 23, the reactor was shut down for Refueling Outage

(RFO) -13. On May 12, the reactor was restarted and attained 100 percent power on May 18.

On June 15, reactor power was reduced to 23 percent because of a problem with the main

turbine bypass valves. The reactor was returned to 100 percent power on June 18. The

reactor remained at 100 percent power for the remainder of the inspection period, with the

exception of regularly scheduled power reductions for control rod pattern adjustments and

turbine testing.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, EmergencyPreparedness1R01Adverse Weather Protection a.Inspection ScopeHurricane Season PreparationsDuring the week of June 12, 2006, the inspectors completed a review of the licensee'sreadiness for seasonal susceptibilities involving high winds at the beginning of hurricaneseason. The inspectors reviewed Procedure ENS-EP-302, "Severe Weather

Response," Revision 4. The inspectors: (1) reviewed plant procedures, the Updated

Safety Analysis Report (USAR), and Technical Specifications (TS) to verify that operator

actions defined in adverse weather procedures maintained the readiness of essential

systems; (2) walked down portions of the protected area to verify that hurri

cane seasonpreparations were sufficient to support operability of essential systems, including theability to perform safe shutdown functions; (3) evaluated operator staffing levels to verifythe licensee could maintain the readiness of essential systems required by plantprocedures; and (4) reviewed the corrective action program (CAP) to determine if the

licensee identified and corrected problems related to adverse weather conditions.The inspectors completed one inspection sample. b.FindingsNo findings of significance were identified.

Enclosure-7-1R04Equipment Alignment Partial System Walkdowns a.Inspection ScopeThe inspectors: (1) walked down portions of the three risk important systems listedbelow and review

ed system operating procedures (SOPs), piping and instrumentdiagrams, and other documents to verify that critical portions of the selected systemswere correctly aligned; and (2) compared deficiencies identified during the walkdown to

the licensee's USAR and CAP to verify problems were being identified and corrected. *Alternate decay heat removal system, which was the backup to the inserviceshutdown cooling system during refueling operations, on May 2, 2006*Reactor core isolation cooling system, while the high pressure core spray dieselwas out of service for maintenance, on June 12, 2006*Division I emergency diesel generator (EDG), while Division II EDG was out ofservice for planned maintenance, on June 21, 2006 Documents reviewed by the inspectors included:

• SOP-0140, "Suppression Pool Cleanup and Alternate Decay Heat Removal,"Revision 16*SOP-0035, "Reactor Core Isolation Cooling System," Revision 8A

• SOP-0053, "Standby Diesel Generator and Auxiliaries," Revision 44AThe inspectors completed three inspection samples. h.FindingsNo findings of significance were identified.1R05Fire Protection b.Inspection ScopeThe inspectors walked down the six plant areas listed below to assess the materialcondition of active and passive fire protection features and their operational lineup and

readiness. The inspectors: (1) verified that transient combustibles were controlled in

accordance with plant procedures; (2) observed the condition of fire detection devices to

verify they remained functional; (3) observed fire suppression systems to verify theyremained functional and that access to manual actuators was unobstructed; (4) verified

that fire extinguishers and hose stations were provided at their designated locations and

Enclosure-8-that they were in a satisfactory condition; (5) verified that passive fire protection features(electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration

seals, and oil collection systems) were in a satisfactory material condition; (6) verifiedthat adequate compensatory measures were established for degraded or inoperable fire

protection features and that the compensatory measures were commensurate with thesignificance of the deficiency; and (7) reviewed the CAP to determine if the licensee

identified and corrected fire protection problems. *Auxiliary building piping Tunnel D, Fire Area AB-7, on May 9, 2006*Low pressure core spray pump room, Fire Area AB-6/Z-1, on May 9, 2006

• High pressure core spray pump room, Fire Area AB-2/Z-1, on May 9, 2006

• Control building standby switchgear Room 1A, Fire Area C-15, on June 22, 2006

• Control building safety related cable tray area and stairway Number 3, Fire AreaC-16 and C-29, on June 22, 2006*Division I EDG control and diesel engine rooms, Fire Area DG-6/Z-1, on June 22, 2006Documents reviewed by the inspectors included:

• Pre-Fire Plan/Strategy Book*USAR Section 9A.2, "Fire Hazards Analysis," Revision 10

• River Bend Station postfire safe shutdown analysis

• RBNP-038, "Site Fire Protection Program," Revision 6BThe inspectors completed six inspection samples. b.FindingsNo findings of significance were identified.1R08Inservice Inspection Activities a.Inspection ScopeThe inspector witnessed the performance of 12 volumetric (ultrasonic) and four surface(liquid penetrant) examinations. The sample of nondestructive examination (NDE)

activities is listed in the attachment. For each of the NDE activities reviewed, the inspector verified that the examinationswere performed in accordance with American Society of Mechanical Engineers (ASME)

Code requirements.

Enclosure-9-During the review of each examination, the inspector verified that appropriate NDEprocedures were used, that examinations and conditions were as specified in the

procedure, and that test instrumentation or equipment was properly calibrated and withinthe allowable calibration period. The inspector also reviewed documentation to verify

that indications revealed by the examinations were dispositioned in accordance with the

ASME Code specified acceptance standards. The inspector verified the certifications of the NDE personnel observed performingexaminations or identified during review of completed examination packages.The inspection procedure requires review of one or two examinations from the previousoutage with recordable indications that were accepted for continued service to ensure

that the disposition was done in accordance with the ASME Code. There were no

recordable indications that required evaluation during the last outage. If the licensee completed welding on the pressure boundary for Class 1 or

2 systemssince the beginning of the previous outage, the procedure requires verification thatacceptance and preservice examinations were done in accordance with the ASME Code

for one to three welds. There were no welds available for review.The procedure also requires verification that one or two ASME Code Section XI repairsor replacements meet code requirements. There were no code repairs or replacements

available at the time of this inspection.The inspectors completed 16 inspection samples. b.FindingsNo findings of significance were identified.1R11Licensed Operator Requalification Program a.Inspection ScopeOn June 13, 2006, the inspectors observed testing and training of senior reactoroperators and reactor operators to verify the adequacy of training, to assess operator

performance, and to assess the evaluators' critique. The training evaluation scenario

observed was RSMS-OPS-422, "Loss of Circ Water Pump, Failure of Steam Flow

Transmitter and Instrument Air System Leak," Revision 4.The inspectors completed one inspection sample. b.FindingsNo findings of significance were identified.

Enclosure-10-1R12Maintenance Effectiveness a.Inspection ScopeThe inspectors reviewed the condition reports (CR) listed below which documentedequipment problems to: (1) verify the appropriate handling of structure, system , andcomponent (SSC) performance or condition problems; (2) verify the appropriate

handling of degraded SSC functional performance; (3) evaluate the role of work

practices and common cause problems; and (4) evaluate the handling of SSC issues

reviewed under the requirements of the maintenance rule; 10 CFR Part 50, Appendix B;

and TS. *CR-RBS-2006-1898, main steam stop Valve B21-MOVF098C leakage, reviewedon June 2, 2006, and CR-RBS-2004-4338, main steam stop Valve B21-

MOVF098C high leakage during RFO-11 and -12, reviewed on June 26, 2006.*CR-RBS-2006-2302, primary containment integrity maintenance rule repetitivefunctional failure, reviewed on June 26, 2006.Documents reviewed by the inspectors included:

• NUMARC 93-01, Nuclear Energy Institute Industry (NEI) Guideline for Monitoringthe Effectiveness of Maintenance at Nuclear Power Plants, Revision 2*Maintenance rule function list

• Maintenance rule performance criteria list

• Main steam stop valve maintenance rule performance evaluations

The inspectors completed two inspection samples. b.FindingsNo findings of significance were identified.1R13Maintenance Risk Assessments and Emergent Work Control a.Inspection Scope .1Risk Assessment and Management of RiskThe inspectors reviewed the planned work weeks listed below to verify: (1) that thelicensee performed risk assessments when required by 10 CFR 50.65 (a)(4) and

administrative Procedure ADM-096, "Risk Management Program Implementation and

On-Line Maintenance Risk Assessment," Revision 4B, prior to changes in plant

configuration for maintenance activities and plant operations; (2) the accuracy,

adequacy, and completeness of the information considered in the risk assessment;

Enclosure-11-(3) that the licensee recognized, and entered as applicable, the appropriate licenseeestablished risk category according to the risk assessment results and Procedure ADM-

096; and (4) that the licensee identified and corrected problems related to maintenancerisk assessments. Specific work activities evaluated included planned and emergent

work for the weeks of:*June 5, 2006, Division I work week and preferred station service TransformerRTX-ESR1F cooling oil dehydration*June 19, 2006, planned Division II EDG outage week

• June 26, 2006, nondivisional work week and potential labor work stoppage .2Emergent Work ControlFor the two emergent work activities listed below, the inspectors: (1) verified that thelicensee performed actions to minimize the probability of initiating events andmaintained the functional capability of mitigating systems and barrier integrity systems;(2) verified that emergent work related activities such as troubleshooting, work

planning/scheduling, establishing plant conditions, aligning equipment, tagging,

temporary modifications, and equipment restoration did not place the plant in an

unacceptable configuration; and (3) reviewed the CAP to determine if the licenseeidentified and corrected risk assessment and emergent work control problems. *Preferred station service Transformer RTX-ESR1F sudden pressure relay failureon May 30, 2006*Main turbine bypass valves inoperable due to hydraulic oil leak on June 2, 2006

The inspectors completed five inspection samples. c.FindingsNo findings of significance were identified.1R14Operator Performance During Nonroutine Evolutions and Events a.Inspection Scope 1.April 4, 2006, Automatic Initiation of Standby Service WaterThe inspectors: (1) reviewed operator logs, plant computer data, and strip charts for theApril 4, 2006, unexpected initiation of Division II standby service water that occurred

while swapping the running normal service water pumps to evaluate operator

performance in coping with the event; (2) verified that operator actions were in

accordance with the response required by plant procedures and training; and (3) verified

that the licensee identified and implemented appropriate corrective actions associatedwith personnel performance problems that occurred during the transient. In addition, the

Enclosure-12-inspectors reviewed CR-RBS-2006-01257, which documented the procedural problemsthat led to the event and reviewed the following procedures used by the operators:*AOP-53, "Initiation of Standby Service Water With Normal Service WaterRunning," Revision 8*SOP-42, "Standby Service Water System," Revision 25

• SOP-66, "Control Building HVAC Chilled Water System," Revision 33B 2.April 15, 2006, Reactor ScramThe inspectors: (1) reviewed operator logs, plant computer data, and strip charts for theApril 15, 2006, unexpected reactor recirculation pump downshift and subsequent reactor

scram to evaluate operator performance in coping with the event; (2) verified that

operator actions were in accordance with the response required by plant procedures

and training; and (3) verified that the licensee identified and implemented appropriatecorrective actions associated with personnel performance problems that occurred during

the transient. In addition the inspectors reviewed the postscram report documented in

Procedure GOP-003, "Scram Recovery," Revision 16A, and observed the onsite safety

review committee review of the postscram report.The inspectors completed two inspection samples. e.FindingsNo findings of significance were identified.1R15Operability Evaluations a.Inspection ScopeFor the operability evaluations associated with the documents listed below, theinspectors: (1) reviewed plants status documents such as operator shift logs, emergent

work documentation, deferred modifications, and standing orders, to determine if an

operability evaluation was warranted for degraded components; (2) referred to theUSAR and design basis documents to review the technical adequacy of licensee

operability evaluations; (3) evaluated compensatory measures associated withoperability evaluations; (4) determined degraded component impact on any TS; (5) usedthe significance determination process to evaluate the risk significance of degraded or

inoperable equipment; and (6) verified that the licensee identified and implemented

appropriate corrective actions associated with degraded components. *CR-RBS-2006-01207 and -01215, Primary containment purge exhaust line failsto meet leak rate acceptance criteria, reviewed during the week of April 3, 2006

Enclosure-13-*CR-RBS-2005-02805, Inserted control Rod 24-29 control blade lifetimecalculation revised for extended operating cycle, reviewed during the week ofApril 17, 2006*Work Request (WR) 76625, NNS-ACB23 "control power" light out, suspect badsocket, reviewed during the week of May 29, 2006*TS-LCO-06-0711, Division II EDG Generator Output Breaker charging springsdid not charge during tagout restoration, reviewed on June 23, 2006*CR-RBS-2006-01257, Division II standby service water start on low service waterpressure, reviewed on June 28, 2006*CR-RBS-2006-02632, turbine bypass valves hydraulic oil leak, reviewed onJune 28, 2006Other documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six inspection samples. b.FindingsIntroduction: The inspectors reviewed a self-revealing noncited violation (NCV) of10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," involving the failure of

the licensee to identify that the normal supply breaker to the Division III 4.16 kVengineered safety features (ESF) bus was not properly racked in following maintenance. Description: Following the completion of planned maintenance on Switchgear NNS-SWG1A on April 29, 2006, operators were assigned to clear equipment tags and restore

the system alignment. As part of this task, operators racked in Breaker NNS-ACB23,the normal supply breaker to 4.16 kV Switchgear NNS-SWG1C. No actions, such as

cycling the breaker, were required to verify that the breaker was properly racked in.On May 9, 2006, after noting that the control power light associated with Breaker NNS-ACB23 was not lit, operators wrote WR 76625 to repair the light. The WR stated that

the white control power light on Control Room Panel H13-P808 was out with the breakerracked in and the control power fuses installed. The WR also indicated that the

suspected cause was a bad socket and that position Switch 52H had failed in the past to

make up during closure. A work control center senior reactor operator determined that

an operability evaluation was not required for the condition described in WR 76625. TheWR was classified "4D," which indicated that it should be scheduled as resources

allowed within the normal 16-week work planning schedule. The inspectors noted the

licensee did not write a CR. The white control power light provides indication that the

breaker is functional, specifically, that: (1) there is no electrical fault on the line or load

side of the breaker, (2) the breaker "Lockout" button is not depressed on Panel 808, and(3) the breaker is fully racked into the switchgear. On May 9, 2006, there were no

electrical faults on Breaker NNS-ACB23 and the "Lockout" was reset on Panel 808.

Enclosure-14-On May 22, 2006, while aligning Switchgear NNS-SWG1C and the Division III 4.16 kVESF bus to the Transformer RSS1 offsite power supply, Breaker NNS-ACB23 failed to

close. Operators racked the breaker out and in, but the breaker failed to close on thesecond attempt. Subsequent troubleshooting identified that the breaker had not beenfully racked in as electricians were able to rotate the racking device one additional turn.

The white light on Panel 808 came on and the breaker was successfully closed. The

operators and electricians determined that Breaker NNS-ACB23 had not been not

properly racked in, wrote CR-RBS-2006-02325 and -02337 and initiated WR 77478 to

investigate the problem with racking in Breaker NNS-ACB23. On May 25, 2006, the inspectors questioned the impact that the failure of the breaker toclose had on the licensee's compliance with TS. Specifically, TS 3.8.1.a requires two

qualified circuits between the offsite transmission network and the onsite Class 1E ac

electrical power distribution system when the plant is in Modes 1, 2, and 3. On May 12,the plant was taken from Mode 4 to Mode 2 without two qualified offsite power sources

available to the Division III 4.16 kV ESF bus. The licensee wrote CR-RBS-2006-2402and determined that they did not comply with TS 3.8.1.a when they changed modes onMay 12. In addition, the Division III 4.16 kV ESF bus was inoperable for a period of10 days (May 12-22), which exceeded the allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> specified in

TS Condition 3.8.1.A. The licensee also discovered that, on May 14 during the conduct

of maintenance on the Division I EDG, with Breaker NNS-ACB23 unable to be closed,

they unknowingly entered TS Condition 3.8.1.d. TS Condition 3.8.1.d states that with"One required offsite circuit inoperable AND on required [E]DG inoperable," restore the

EDG or the offsite power supply to an operable status in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or place the plant in

Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The Division I EDG was inoperable for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> and

15 minutes.The inspectors found that the licensee's procedures did not require Breaker NNS-ACB23 to be cycled to verify proper operation after it was racked in on April 29. Procedure OSP-0022, "Operations General Administrative Guidelines," Revision 01,

step 4.5.5, required that breakers be functionally tested "following any activity involving

safety related equipment which requires the breaker to be racked out." Because

Breaker NNS-ACB23 is not classified as a safety-related breaker, it was not required to

be functionally tested after it was racked in on April 29. Analysis: The performance deficiency associated with this finding involved the failure ofoperators to identify that Breaker NNS-ACB23 was not functional on April 29, 2006. Thefinding was more than minor because it was associated with the mitigating systemcornerstone attribute of configuration control and affected the associated cornerstone

objective to ensure the availability, reliability, and capability of systems that res

pond toinitiating events to prevent undesirable consequences. The Phase 1 worksheets in

Manual Chapter (MC) 0609, "Significance Determination Process," were used to

conclude that a Phase 2 analysis was required because both the mitigating systems andthe containment barrier cornerstones were affected. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, Attachment 1,"User Guidance for Determining the Significance of Reactor Inspection Findings for

At-Power Situations," the inspectors estimated the risk of the subject finding using the

Enclosure-15-Risk-Informed Inspection Notebook for River Bend Station, Revision 2. The inspectorsassumed that Division III power was available, but degraded, while Breaker NNS-ACB23was not properly installed for the 10 days that the plant was in Mode 3 or above, fromMay 12-22, 2006. Therefore, the exposure window used was 3-30 days. No operator

recovery was credited because on two occasions, operators had proven incapable of

properly positioning the breaker, ultimately requiring maintenance technicians to

properly install the breaker. Using Manual Chapter 0609, Appendix A, Attachment 2,

Rule 2.1, "Inspection Finding that Degrades Mitigation Capability and Does Not ReduceRemaining Mitigation Capability Credit to a Value Less Than Full Mitigation Credit," theinspectors determined that all sequences containing the functions that would be affectedby a loss of Division III power, including the Division I standby service water loop(HPCS, LPI, CHR, HPCS/LC, and REC/SSW), should be quantified, giving full mitigationcapability credit to each of these functions. Because the performance deficiencyaffected the electric power system, Table 2 of the risk-informed notebook required thatall worksheets be evaluated. The resulting dominant sequences are provided in Table 1

below:Table 1Phase 2 Worksheet ResultsInitiatorSequenceIELMitigating FunctionsResultTNSW53SSW - REC/SSW7*43RCIC - HPCS - DEP9*LOOP13CHR - LDEP823CHR - SPCFAN8

43RCIC - HPCS - DEP9*63EAC1&2 - HPCS - REC6 - FPW 9*83EAC1&2 - HPCS - SBODG - REC4 9*

93EAC1&2 - REC1 - HPCS -RCIC9*SORV13CHR-LDEP823CHR - SPCFAN943RCIC - HPCS - DEP9*LOIA24CHR - SPCFAN814CHR-LDEP9TPCS42RCIC - HPCS - DEP8ATWS16CHR9 * Denotes sequences indicated as LERF contributors in the Phase 2 notebook.By application of the counting rule, the internal event risk contribution of this finding tothe change in core damage frequency (CDF) was determined to be of low to moderaterisk significance (WHITE).A senior reactor analyst performed further evaluation of the risk associated with thisissue (Phase 3/Modified Phase 2). Because the assumptions made during the Phase 2

estimation process were overly conservative and did not completely represent the actual

exposure time nor the actual affect the performance deficiency had on the availability ofpower to the Division III diesel generator, the senior reactor analyst modified these

Enclosure-16-assumptions to more precisely quantify the change in risk. Specifically, the exposuretime was 10 days as opposed to the 30 days used in the risk-informed notebook.

Additionally, the Phase 2 evaluation included loss of offsite power initiating events that

were not affected by the performance deficiency because offsite power to Division III

would in all likelihood be lost during a design basis loss of offsite power. The senior

reactor analyst performed a modified Phase 2 estimation and determined that the

internal event risk contribution of the subject finding to the CDF was of very low risksignificance (Green). The best estimate value of this probability (CDFINTERNAL) wascalculated by the senior reactor analyst to be 1.2 x 10

-7. The analyst evaluated thecontribution of external initiating events to the risk and calculated a bounding risk

estimate of 2.9 x 10

-7 as the CDF for internal fire events.Using Manual Chapter 0609, Appendix H, "Containment Integrity SignificanceDetermination Process," the analyst estimated that the potential risk contribution fromlarge early release frequency was 6.6 x 10

-8.Given the independence of each initiating event, the analyst determined that the bestestimate of the total risk related to the subject performance deficiency was the

summation of the CDF calculated for both internal and external initiators. Therefore,the best estimate was 4.1 x 10

-7. The change in risk related to large early releasefrequency was determined to be below 6.6 x 10

-8, corroborating that the finding was ofvery low risk significance. The performance deficiency resulted in a finding that was of

very low risk significance (Green). The cause of the finding was related to the

crosscutting aspect of problem identification and resolution in that operators failed toidentify that Breaker NNS-ACB23 was not properly racked in. Enforcement: 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, inpart, that measures be established to assure that conditions adverse to quality are

promptly identified and corrected. Contrary to this, from April 29 to May 22, 2006, the

licensee failed to identify that Breaker NNS-ACB23, which supplied one of the two

required offsite power supplies to the Division III 4.16 kV ESF bus, was not properlyracked in to Switchgear NNS-SWGIC. The root cause involved the licensee's lack of

understanding that Breaker NNS-ACB23 was required to be functional to meet

TS 3.8.1.a requirements for two offsite power circuits to the Division III 4.16 kV ESFbus. The corrective actions to restore compliance included: (1) changes to operations

section procedures to verify the white control power light, when applicable, after a circuit

breaker is racked in, (2) expansion of the requirement to functionally test safety-related

breakers to the nonsafety-related breakers in the TS required offsite power circuits, and

(3) operator lessons learned training on the event and all of its ramifications. Because

the finding was of very low safety significance and has been entered into the licensee's

CAP as CR-RBS-2006-02402, this violation is being treated as an NCV consistent with

Section VI.A of the Enforcement Policy: NCV 05000458/2006003-01, "Failure to identify

Division III ESF bus supply breaker not racked in."

Enclosure-17-1R19Postmaintenance Testing a.Inspection ScopeFor the five postmaintenance test activities of risk significant systems or componentslisted below, the inspectors: (1) reviewed the applicable licensing basis and/or design-

basis documents to determine the safety functions; (2) evaluated the safety functions

that may have been affected by the maintenance activity; and (3) reviewed the test

procedure to verify that it adequately tested the safety function that may have been

affected. The inspectors either witnessed or reviewed test data to verify that

acceptance criteria were met, plant impacts were evaluated, test equipment was

calibrated, procedures were followed, jumpers were properly controlled, the test dataresults were complete and accurate, the test equipment was remo

ved, the system wasproperly re-aligned, and deficiencies during testing were documented. The inspectors

also reviewed the CAP to determine if the licensee identified and corrected problems

related to postmaintenance testing. *Work Order (WO) 50370422, Division II battery cell post seal replacement,reviewed during the week of May 8, 2006*WO 87721, replace control Rods 40-37, 44-41, and 48-25 and 12-25 individualscram test switches, reviewed May 19, 2006*WO 69816, low pressure core spray keep fill pump discharge check valve, E21-VF033 replacement, reviewed during the week of June 19, 2006*WO 85194, signature testing on high pressure core spray room unit coolerservice water outlet valve, SWP-MOV74B, reviewed during the week of June 19,

2006*WO 90342, Division II EDG generator output Breaker ENS-SWG1B-ACB027charging springs failed to charge during tagout restoration, reviewed on June 23,

2006The inspectors completed five inspection samples. g.FindingsNo findings of significance were identified.1R20Refueling and Other Outage Activities a.Inspection ScopeThe inspectors reviewed the following risk important refueling outage activities to verifydefense in depth commensurate with the outage risk control plan and compliance with

the TS during RFO-13 from April 23 to May 12, 2006: (1) the risk control plan;

(2) tagging/clearance activities; (3) reactor coolant system instrumentation; (4) electrical

Enclosure-18-power; (5) decay heat removal; (6) spent fuel pool cooling; (7) inventory control;(8) reactivity control; (9) containment closure; (10) reduced inventory conditions;

(11) refueling activities; (12) heatup and cooldown activities; (13) restart activities; and

(14) licensee identification and implementation of appropriate corrective actions

associated with RFO activities. The inspectors' containment inspections included

observations of the containment sump for damage and debris, and supports, braces,

and snubbers for evidence of excessive stress, water hammer, or aging. Specific

outage activities observed and reviewed included:*Outage risk assessment team (ORAT) report to onsite safety review committee*Reactor shutdown, cooldown, and vessel disassembly

• Refueling operations, fuel sipping, and off loaded fuel inspections

• Daily/shiftly shutdown operations protection plan assessments

• Shutdown postscram report to onsite safety review committee

• Reactor recirculation pump trip logic modification installation and testing

• Main steam line local leak rate testing

• Transformer RSS1 offsite power line equipment inspection and upgrade

• Division II to Division I protected division swap

• Infrequently performed test or evolution briefings for:- Divisional loss of offsite power/loss of coolant accident testing

- Concurrent control rod mechanism and blade changeout

- Reactor vessel pressure test and scram time testing

- Reactor startup, heatup, and power ascension

- Onsite safety review committee meeting to recommend startup

- Drywell 900 psi walkdown (after shutdown and during startup)Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one inspection sample. b.FindingsIntroduction: An NRC identified NCV of 10 CFR 50.65, "Maintenance Rule,"Section (a)(4) was identified for the failure of the licensee to provide prescribed

compensatory measures for the highest shutdown risk condition during RFO-13.

Specifically, the preoutage risk assessment recommended that two WOs be in place for

maintenance electricians to provide power to one spent fuel pool cooling pump in the

event of problems with the running pump during periods of safety-related electrical bus

maintenance. The inspectors found that the WOs were not in place before enteringshutdown risk condition Orange on April 26, 2006, during the Division II ESF bus testing,

and on May 3, 2006, during the Division I ESF bus outage.Description: The inspectors observed the onsite safety review committee meeting todiscuss and approve the ORAT report for RFO-13. The report noted two Orange

shutdown risk conditions for spent fuel pool cooling (SFC). Only one SFC pump would

be available after the beginning of core offload: (1) during the Division II ESF bus

testing with the SFC-P1B breaker racked out, and (2) during the Division I ESF bus

outage when SFC-P1A was without power. As a result of the ORAT review of

Enclosure-19-Procedure AOP-0051, "Loss of Decay Heat Removal," Revision 17, they recommendedthat the planned maintenance optimization group develop WOs for maintenanceelectricians to provide alternate power from the station blackout diesel generator to the

deenergized SFC pump in the event of a failure of the running pump.In addition, Procedure OSP-0037, "Shutdown Operations Protection Plan," Revision 16,Section 4.7, "Fuel Pool Cooling," required that: (1) if work was required on SFC during

the outage, then it should be done as early as possible in the outage and not after fueloffload (when heat load is the highest); and (2) if work was required after fuel offload,

then a contingency plan shall be in place prior to removing t

he system from service. The inspectors determined that this requirement applied to deenergizing an SFC pump

for electrical bus maintenance.On May 3, 2006, during the Division I ESF bus outage, the inspectors asked theoperations shift manager if the required WO was available to provide alternate power to

SFC-P1A in the event that the running SFC-P1B failed. He stated that he assumed thatthe WO was written and that he would check. The inspectors then requested a copy of

the WO and a senior work planner reported that the WO was not available since it was

not yet approved for use in the electronic work planning program. Following discussions

with operators in the work management center, the licensee immediately took actions toensure that both WOs were processed and made ready for use.The inspectors reviewed AOP-0051, Attachment 1, "Spent Fuel Pool Curves," anddetermined that the approximate "time to boil" for the spent fuel pool at that time withoffload fuel in the pool was approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. Based on that data and the time

needed to generate the WOs, the inspectors determined that there was adequate timefor the licensee to connect an alternate power supply to the SFC pumps before the

spent fuel pool water started to boil if there was a failure of the running pump.Analysis: The performance deficiency associated with this finding involved the failure toestablish prescribed compensatory measures for the highest outage risk condition

during RFO-13 as required by the shutdown operations protection plan. The finding was

more than minor because the licensee failed to implement prescribed compensatory

measures and failed to effectively manage those measures. The finding affected the

mitigating system cornerstone because of the increased risk of a sustained loss of SFCduring core offloading operations. The finding could not be evaluated using the

significance determination process; therefore, the finding was reviewed by regional

management and determined to be of very low safety significance. Factors that were

considered included: (1) electrical maintenance technicians had previously performed

the task of providing alternate power to an SFC pump, (2) the necessary equipment was

staged as part of the abnormal operating procedure for loss of decay heat removal, and

(3) the relatively long "time to boil" of the spent fuel storage pool at that time during the

refueling outage. The cause of the finding was related to the cro

sscutti ng aspect ofhuman performance because the licensee's planned maintenance activities and the

predetermined increase in outage risk was not effectively managed by prescribed

compensatory measures.

Enclosure-20-Enforcement: 10 CFR 50.65(a)(4) requires, in part, that before performing maintenanceactivities, the licensee shall assess and manage the increase in risk that may result from

the proposed maintenance activities. Contrary to this, the licensee failed to properly

manage the highest outage risk condition of RFO-13. On April 26, 2006, the plant

entered an Orange outage risk condition for SFC during core offload, when SFC-P1B

was deenergized for Division II ESF bus testing. On May 3, 2006, the plant entered an

Orange outage risk condition for SFC during core offload, when SFC-P1A was

deenergized for a Division I ESF bus outage. WOs were not written and ready for use

to have electricians provide alternate power to an SFC pump in the event the running

pump failed. The root cause involved the failure of the licensee to ensure that the WOwas in place before the plant entered the Orange shutdown risk condition. Corrective

action was taken to process the WOs for immediate use. Because the finding was of

very low safety significance and was entered into the licensee's CAP as CR-RBS-2006-

01937, this violation is being treated as an NCV consistent with Section VI.A of the

Enforcement Policy: NCV 05000458/2006003-02, "Failure to adequately manage an

increase in plant risk." 1R22Surveillance Testing a.Inspection ScopeThe inspectors reviewed the USAR, procedure requirements, and TS to ensure that thesix surveillance activities listed below demonstrated that the SSCs tested were capable

of performing their intended safety functions. The inspectors either witnessed or

reviewed test data to verify that the following significant surveillance test attributes were

adequate: (1) preconditioning; (2) evaluation of testing impact on the plant;

(3) acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead

controls; (7) test data; (8) testing frequency and method demonstrated TS operability;(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of ASMECode requirements; (12) updating of performance indicator (PI) data; (13) engineering

evaluations, root causes, and bases for returning tested SSCs not meeting the test

acceptance criteria were correct; (14) reference setting data; and (15) annunciator and

alarm setpoints. The inspectors also verified that the licensee identified and

implemented any needed corrective actions associated with the surveillance testing. *STP-208-3601, "'A' Main Steam Line MSIV's and Outboard Drain Valve LeakRate Test and Inboard MSIV Inleakage Test," Revision 6, performed on May 2,

2006*STP-305-1606, "[Division I Battery] ENB-BAT1A Service Discharge Test,"Revision 17, performed on May 6, 2006*STP-050-3601, "Shutdown Margin Demonstration," Revision 27, performed onMay 12, 2006*STP-000-0102, "Power Distribution Alignment Check," Revision 5, performed onMay 14 and 15, 2006

Enclosure-21-*STP-508-4543, "Turbine First Stage Pressure Channel Functional Test,"Revision 7, performed on June 4, 2006*Reactor coolant sample using Procedures COP-0001, "Sampling via VariousBalance-Of-Plant Systems," Attachment 8, "Reactor Sample Panel Routine

Sample Points," Revision 14, and COP-0305, "Operation of the Countroom

Analysis Systems," Revision 2, performed on June 15, 2006Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six inspection samples. h.FindingsIntroduction: The inspectors identified an NCV of TS 5.4.1.a for the failure of thelicensee to provide an adequate surveillance test procedure to perform TS SurveillanceRequirement (SR) 3.8.1.1. Specifically, STP-000-0102, "Power Distribution AlignmentCheck," Revision 4, did not include steps to verify the required offsite power circuit

breaker alignment and indicated power availability for the Division III 4.16 kV ESF bus as required in Modes 1, 2, and 3. Description: As discussed in Section 1R15 of this report, operators failed to properlyrack in Breaker NNS-ACB23 on April 29, 2006. This condition was discovered on

May 22, when the breaker failed to close. During this period, on May 14, 2006, the

Division I EDG was removed from service to replace a leaking section of jacket cooling

water vent tubing. With the Division I EDG removed from service, TS Required

Action 3.8.1.a.1 required that operators perform TS SR 3.8.1.1 within one hour andonce every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> until the EDG was operable. TS SR 3.8.1.1 required operators toverify the correct breaker alignment and indicated power for each required offsite power

circuit. Operators utilized Procedure STP-000-0102, "Power Distribution AlignmentCheck," Revision 4, to satisfy the requirements of TS SR 3.8.1.1; however, the

inspectors identified that the procedure did not have steps to verify the correct breaker

alignment and indicated power availability to the Division III 4.16 kV ESF bus. As aresult, the operators did not identify that Breaker NNS-ACB23 was not racked in. During the period that the Division I EDG was removed from service, the plant wasactually in TS Condition 3.8.1.d. TS Condition 3.8.1.d states that with "One requiredoffsite circuit inoperable AND one required [E]DG inoperable," restore the EDG or the

offsite power supply to an operable status in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> or place the plant in Mode 3 within

the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The Division I EDG was inoperable for 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> and 15 minutes.Procedure STP-000-0102, Section 1.1, states, in part, that its purpose is to verify thecorrect breaker alignment and indicated power availability for each required offsitepower circuit in accordance with TS SR 3.8.1.1 in Modes 1, 2, and 3. TS 3.8.1 basesdefines an offsite power circuit as follows: "Each offsite circuit consists of incoming

breakers and disconnects to the respective preferred station service Transformers 1C

and 1D [RSS1 and RSS2], the 1C and 1D preferred station service transformers, and

the respective circuit path including feeder breakers to the three 4.16 kV ESF buses."

Enclosure-22-NNS-ACB23 is one of the circuit breakers between preferred station serviceTransformer RTX-XSR1C and the Division III 4.16 kV ESF bus.Analysis: The performance deficiency associated with this finding involved thelicensee's failure to provide operators with an adequate STP to meet the requirements

of TS SR 3.8.1.1 to verify correct breaker alignment and indicated power availability tothe Division III ESF bus for each required offsite circuit. A review of previous revisionsof STP-000-0102 showed that the procedure has never verified the required offsite

power circuits for the Division III 4.16 kV ESF bus in Modes 1, 2, and 3. Although thisperformance deficiency caused the failure to verify the offsite power circuit for an

extended period of time, the risk impact was limited to the 10 days from May 12-22,

2006. Therefore, the risk characterization of this finding is the same as that described in

Section 1R15 of this inspection report. The cause of the finding was related to the

crosscutting aspect of human performance because the licensee did not provide the

operators with an adequate STP to complete the TS SR to verify the required offsite

power circuits' breaker alignment to all three 4.16 kV ESF buses. Additionally, the

cause of the finding was related to the cr

osscutting aspect of problem identification andresolution in that on two occasions, June 18, 2005, and May 22, 2006, operatorsentered TS Condition 3.8.1.a for one inoperable offsite power circuit to the Division III

4.16 kV ESF bus and performed STP-000-0102 to meet the Required Action to perform

SR 3.8.1.1, but did not recognize that STP-000-0102 did not verify the other offsitepower circuit breaker alignment to the Division III 4.16 kV ESF bus.Enforcement: TS 5.4.1.a requires that written procedures be established, implemented,and maintained covering the activities specified in Appendix A, "Typical Procedures for

Pressurized Water Reactors and Boiling Water Reactors," of Regulatory Guide 1.33,"Quality Assurance Program Requirements (Operation)," dated February 1978.

Regulatory Guide 1.33, Appendix A, Section 8.a, requires procedures for all TS SRs. Procedure STP-000-0102 states that it verified the correct breaker alignment and power

availability for each required offsite circuit in accordance with TS SR 3.8.1.1 in Modes 1,2, and 3. Contrary to this, Procedure STP-000-0102, Revision 4, did not require

verification of the correct breaker alignment for the offsite power circuits to the

Division III 4.16 kV ESF bus in Modes 1, 2, and 3. The root cause involved the incorrectinterpretation of the Division III 4.16 kV bus SRs as they apply to the unique River BendStation ESF electrical distribution system. The corrective actions to restore complianceincluded as an interim measure entering in the control room logs the breaker alignment

for and the bus voltage available to the Division III 4.16 kV ESF bus, until STP-000-0102could be revised. Because the finding was of very low safety significance and has been

entered into the licensee's CAP as CR-RBS-2006-02675 and -02402, this violation is

being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000458/2006003-03, "Inadequate procedure to verify required offsite power breaker

alignment."

Enclosure-23-1R23Temporary Plant Modifications a.Inspection ScopeThe inspectors reviewed the USAR, plant drawings, procedure requirements, and TS toensure that Temporary Alteration 2006-0011, Off Gas Pretreatment Radiation MonitorSample Chamber Drain Line Modification, was properly implemented. The inspectors:

(1) verified that the modification did not have an affe

ct on system operability/availability;(2) verified that the installation was consistent with modification documents; (3) ensured

that the postinstallation test results were satisfactory and that the impact of the

temporary modification on the operation of the pretreatment radiation monitor weresupported by the test; (4) verified that the modification was identified on control roomdrawings and that appropriate identification tags were placed on the affected drawings;and (5) verified that appropriate safety evaluations were completed. The inspectors

verified that the licensee identified and implemented any needed corrective actions

associated with temporary modifications.The inspectors completed one inspection sample. b.FindingsNo findings of significance were identified.

Cornerstone: Emergency Preparedness1EP6Drill Evaluation a.Inspection ScopeOn June 20, 2006, the inspectors observed the full scope exercise dress rehearsal,which was used to contribute to "Drill/Exercise Performance" and "Emergency ResponseOrganization Drill Performance" PI. The inspectors: (1) observed the training evolutionto identify any weaknesses and deficiencies in classification, notification, and protective

action requirements development activities; (2) compared the identified weaknesses and

deficiencies against licensee identified findings to determine whether the licensee was

properly identifying failures; and (3) determined whether licensee performance was in

accordance with the guidance of the NEI 99-02, "Voluntary Submission of Performance

Indicator Data," Revision 2, acceptance criteria. The scenario used was RDRL-EP-0602, Tornado/Loss of Offsite Power/Main Steam Line Break, dated June 16, 2006.Emergency [plan] implementing procedures reviewed by the inspectors included:

• EIP-2-001, "Classification of Emergencies," Revision 13*EIP-2-006, "Notifications," Revision 32

• EIP-2-007, "Protective Action Guidelines Recommendations," Revision 21The inspectors completed one inspection sample.

Enclosure-24- b.FindingsNo findings of significance were identified.2.RADIATION SAFETYCornerstone: Occupational Radiation Safety2OS1Access Control to Radiologically Significant Areas a.Inspection ScopeThis area was inspected to assess the licensee's performance in implementing physicaland administrative controls for airborne radioactivity areas, radiation areas, high

radiation areas, and worker adherence to these controls. The inspector used the

requirements in 10 CFR Part 20, TS, and the licensee's procedures required by TS as

criteria for determining compliance. During the inspection, the inspector interviewed the

radiation protection manager, radiation protection supervisors, and radiation workers.

The inspector performed independent radiation dose rate measurements and reviewed

the following items:*PI events and associated documentation packages reported by the licensee inthe occupational radiation safety cornerstone*Controls (surveys, posting, and barricades) of three radiation, high radiation, orairborne radioactivity areas*Radiation work permits, procedures, engineering controls, and air samplerlocations *Conformation of electronic personal dosimeter alarm setpoints with surveyindications and plant policy; workers' knowledge of required actions when their

electronic personnel dosimeter noticeably malfunctions or alarms*Barrier integrity and performance of engineering controls in airborne radioactivityareas*Adequacy of the licensee's internal dose assessment for any actual internalexposure greater than 50 millirem committed effective dose equivalent*Physical and programmatic controls for highly activated or contaminatedmaterials (nonfuel) stored within spent fuel and other storage pools. *Self-assessments, audits, licensee event reports (LER), and special reportsrelated to the access control program since the last inspection *Corrective action documents related to access controls

Enclosure-25-*Licensee actions in cases of repetitive deficiencies or significant individualdeficiencies *Radiation work permit briefings and worker instructions

• Adequacy of radiological controls, such as required surveys, radiation protectionjob coverage, and contamination controls during job performance *Dosimetry placement in high radiation work areas with significant dose rategradients *Changes in licensee procedural controls of high dose rate - high radiation areasand very high radiation areas*Controls for special areas that have the potential to become very high radiationareas during certain plant operations*Posting and locking of entrances to all accessible high dose rate - high radiationareas and very high radiation areas *Radiation worker and radiation protection technician performance with respect toradiation protection work requirements The inspector completed 21 of the required 21 samples. b.Findings 1.Unguarded High Radiation Area BoundaryIntroduction: The inspector reviewed a self-revealing NCV of TS 5.7.1, resulting fromthe licensee's failure to control access to a high radiation area. The finding had very low

safety significance.Description: On April 6, 2006, the licensee transferred reverse osmosis system filtersfrom one elevation of the radwaste building to another. Because dose rates on the filter

barrels were as high as 600 millirem per hour, the licensee assigned personnel to guardthe elevator entrances to prevent workers from entering high radiation areas. On this

occasion, the guards were not using radios, as was a common practice. Because of the

lack of good communication, a guard prematurely left his post in front of the 123-foot

elevation elevator door. Coincidently, two workers attempted to board the elevator on

the 123-foot elevation after the guard had left. The elevator carrying the barrels ofradioactive filters stopped at the 123-foot elevation, the doors opened, and theelectronic dosimeters of the workers alarmed because of the high dose rates. The

guard returned and evacuated the workers before they accrued additional radiation

dose. The highest dose rate recorded by an electronic alarming dosimeter was 164

millirem per hour. Planned corrective action was still being evaluated by the licensee atthe conclusion of the inspection.

Enclosure-26-Analysis: The failure to control access to a high radiation area was a performancedeficiency. The significance of the finding was greater than minor because it was

associated with the occupational radiation safety attribute of exposure control and

affected the cornerstone objective, in that not controlling access to a high radiation areacould increase personal exposure. Using the Occupational Radiation Safety

Significance Determination Process, the inspector determined that the finding was ofvery low safety significance because it did not involve: (1) an as low as is reasonably

achievable (ALARA) finding, (2) an overexposure, (3) a substantial potential foroverexposure, or (4) an impaired ability to assess dose. Additionally, this finding hadcrosscutting aspects associated with human performance in that the failure of the

individual to guard the elevator door directly contributed to the violation.Enforcement: TS 5.7.1 requires each high radiation area, as defined in 10 CFR Part 20,in which the intensity of radiation is greater than 100 millirems per hour but less than1000 millirems per hour, be barricaded and conspicuously posted as a high radiationarea and entrance thereto shall be controlled by requiring issuance of a radiation work

permit. The licensee violated TS 5.7.1 when it failed to barricade and conspicuously

post the elevator housing the radioactive filter barrels or maintain a guard to ensure

workers did not enter a high radiation area. Because this failure to control a high

radiation area was of very low safety significance and has been entered into the

licensee's CAP as CR-RBS-2006-01294, this violation is being treated as an NCV,

consistent with Section VI.A of the NRC Enforcement Policy:

NCV 05000458/2006003-04, "Failure to control access to a high radiation area." 2.Unanalyzed Airborne Radioactivity SurveyIntroduction: The inspector identified an NCV of 10 CFR 20.1501(a) because thelicensee failed to survey airborne radioactivity. The finding had very low significance.Description: On May 2, 2006, during the removal of local power range monitors, thelicensee started collecting an air sample of the work area. The air sample spanned two

shifts. A health physics technician on the second shift discarded the sample because

the first shift had not documented a start time. Therefore, the sample was never

analyzed. However, all workers successfully passed through the portal monitors at the

exit of the controlled access area without alarm, confirming that no worker experienced

an uptake of radioactive material. Planned corrective action is still being evaluated.Analysis: The failure to survey airborne radioactivity was a performance deficiency. This finding was greater than minor because it was associated with the occupational

radiation safety program attribute of exposure control and affected the cornerstone

objective in that the lack of knowledge of radiological conditions could increase

personnel dose. Using the 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 ALARA finding, (2) an overexposure, (3) a substantial

potential for overexposure, or (4) an impaired ability to assess dose. Additionally, thisfinding had crosscutting aspects associated with human performance in that the failureto maintain the sample for analysis directly contributed to the violation.

Enclosure-27-Enforcement: 10 CFR 20.1501(a) requires that each licensee make or cause to bemade surveys that may be necessary for the licensee to comply with the regulations in

10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extentof radiation levels, concentrations or quantities of radioactive materials, and the potential

radiological hazards that could be present. Pursuant to 10 CFR 20.1003, a "survey"

means an evaluation of the radiological conditions and potential hazards incident to the

production, use, transfer, release, disposal, or presence of radioactive material or other

sources of radiation. In part, 10 CFR 20.1201(a) states that the licensee shall controlthe occupational dose to individual adults. The licensee violated 10 CFR 20.1501(a)

when it failed to perform an evaluation of airborne radioactivity to ensure compliance

with 10 CFR 20.1201(a). Because this failure to perform a radiological survey was of

very low safety significance and has been entered into the licensee's CAP as

CR-RBS-2006-01994, this violation is being treated as an NCV, consistent with

Section VI.A of the NRC Enforcement Policy: NCV 05000458/2006003-05, "Failure toperform airborne radiation survey."2OS2ALARA Planning and Controls a.Inspection ScopeThe inspector assessed licensee performance with respect to maintaining individual andcollective radiation exposures ALARA. The inspector used the requirements in 10 CFR Part 20 and the licensee's procedures required by TS as criteria for determining

compliance. The inspector interviewed licensee personnel and reviewed:*Current 3-year rolling average collective exposure

• Three outage or on-line maintenance work activities scheduled during theinspection period and associated work activity exposure estimates which were

likely to result in the highest personnel collective exposures *ALARA work activity evaluations, exposure estimates, and exposure mitigationrequirements*Intended versus actual work activity doses and the reasons for anyinconsistencies *Shielding requests and dose/benefit analyses

• Dose rate reduction activities in work planning

• Use of engineering controls to achieve dose reductions and dose reductionbenefits afforded by shielding *Workers use of the low dose waiting areas

• First-line job supervisors' contribution to ensuring work activities are conductedin a dose efficient manner

Enclosure-28-*Radiation worker and radiation protection technician performance during workactivities in radiation areas, airborne radioactivity areas, or high radiation areas The inspector completed 6 of the required 15 samples and 4 of the optional samples. b.FindingsNo findings of significance were identified.4.OTHER ACTIVITIES

4OA1Performance Indicator Verification a.Inspection Scope 1.Barrier Integrity CornerstoneThe inspectors sampled licensee submittals for the two PIs listed below for the periodOctober 1, 2004, through March 31, 2006. The definitions and guidance of NEI 99-02,

"Regulatory Assessment Indicator Guideline," Revision 4, were used to verify the

licensee's basis for reporting each data element in order to verify the accuracy of PI

data reported during the assessment period. The inspectors: (1) reviewed reactor

coolant system (RCS) chemistry sample analyses for dose equivalent Iodine-131 andcompared the results to the TS limit; (2) observed a chemistry technician obtain and

analyze an RCS sample; (3) reviewed operating logs and surveillance results formeasurements of RCS identified leakage; and (4) observed a surveillance test thatdetermined RCS identified leakage.RCS Specific ActivityRCS LeakageThe inspectors completed two inspection samples. 2.Occupational Radiation Safety CornerstoneThe review included corrective action documentation that identified occurrences inlocked high radiation areas (as defined in the licensee's TS), very high radiation areas

(as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in

NEI 99-02), specifically CR-RBS-2006-01910. Additional records reviewed included

ALARA records and whole-body counts of selected individual exposures. The inspector

interviewed licensee personnel that were accountable for collecting and evaluating the

PI data. In addition, the inspector toured plant areas to verify that high radiation, lockedhigh radiation, and very high radiation areas were properly controlled. PI definitions and

guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline,"

Revision 3, were used to verify the basis in reporting for each data element.

Enclosure-29-*Occupational Exposure Control EffectivenessThe inspector completed the one required sample in this cornerstone. 3.Public Radiation Safety CornerstoneThe inspector reviewed licensee documents from June 1, 2005, through March 31,2006. Licensee records reviewed included corrective action documentation that

identified occurrences for liquid or gaseous effluent releases that exceeded PI

thresholds and those reported to the NRC. The inspector interviewed licenseepersonnel that were accountable for collecting and evaluating the PI data. PI definitionsand guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline,"

Revision 3, were used to verify the basis in reporting for each data element.*Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences The inspector completed the one required sample in this cornerstone. f.FindingsNo findings of significance were identified.4OA2Identification and Resolution of Problems 1.Semiannual Trend Review g.Inspection ScopeThe inspectors completed a semiannual trend review of repetitive or closely relatedissues related to identify trends that might indicate the existence of more safety

significant issues. The inspectors' review consisted of the 6-month period from

January 1 to June 30, 2006, of CAP items associated with the three EDG starting air

systems documented in 42 CRs. When warranted, some of the samples expandedbeyond those dates to fully assess the issue. The inspectors compared and contrasted

their results with the results contained in adverse trend CRs for problems related to the

starting air compressors and air dryers. Corrective actions associated with a sample of

the issues identified were reviewed for adequacy. The CRs reviewed by the inspectors

are listed in the attachment.The inspectors completed one inspection sample. b. Findings and ObservationsThere were no findings of significance identified associated with the CRs reviewed.

The inspectors noted that the licensee had identified a long-standing issue related to theperformance of the EDG starting air systems' air compressors. Since January 1, 2006,

Enclosure-30-there were 18 CRs written for high metal wear products in monthly air compressor oilsamples. Each of these CRs was closed to CR-RBS-2004-02165. An additional

28 CRs written since August 2, 2004, for high metal wear product concentrations and

high moisture content in monthly compressor oil samples were closed to CR-RBS-2004-

02165. In addition, operators wrote adverse trend CR-RBS-2006-02407 to detail

compressor problems, including excessive run times. The inspectors determined that

the licensee is taking appropriate actions to understand the problem with the EDG

starting air compressors, including sending

the system engineer to observe the vendor'steardown and refurbishment of two of the starting air compressors. Another four CRs have been written since January 1, 2006, describing problems withstarting air system dryers and dryer prefilters. Following a June 29, 2006, meeting heldto discuss overall EDG starting air system maintenance problems, the licensee wroteCR-RBS-2006-02799, to look into the relationship between the prefilter and dryer

problems. The inspectors noted that this meeting was the first discussion of the overall

condition of the EDG starting air systems and to evaluate the interrelationship betweencompressor, dryer, and prefilter problems. 2.Occupational Radiation Safety a.Inspection ScopeThe inspector evaluated the effectiveness of the licensee's problem identification andresolution process with respect to the following inspection areas:*Access Control to Radiologically Significant Areas (Section 2OS1)*ALARA Planning and Controls (Section 2OS2) b. Findings and ObservationsNo findings of significance were identified. 3.Inservice Inspection Activities a.Inspection ScopeThe inspector reviewed selected inservice inspection related CRs issued during thecurrent and past refueling outages. The review served to verify that the licensee's CAP

was being correctly utilized to identify conditions adverse to quality and that thoseconditions were being adequately evaluated, corrected, and trended. b.FindingsNo findings of significance were identified.

Enclosure-31-4OA3Event Followup 1.(Closed) LER 50-458/2004-003-01, Unplanned Automatic Start of Standby DieselGenerator Due to Loss of Division 1 Switchgear On October 31, 2004, technicians caused an unexpected degraded voltage signal,which resulted in a loss of the Division I 4.16 kV ESF bus during preparations for the

Division I loss of offsite power/loss of coolant accident test. The Division I EDG

automatically started and powered the ESF bus and all equipment operated asexpected. Initial inspection of this event was documented in NRC integrated inspection

Report 05000458/2004005. During this inspection period, the inspectors reviewed the

LER, the root cause analysis, and corrective actions documented in

CR-RBS-2004-03518. No additional findings of significance were identified. This LER

is closed. 2.(Closed) LER 50-458/2004-004-01, Unplanned Automatic Start of Standby DieselGenerator Due to Loss of Division 2 SwitchgearOn November 1, 2004, technicians inadvertently caused a trip of Transformer RSS2preferred station service Transformer RTX-XSR1F while troubleshooting a transformer

sudden pressure relay trip circuit. As a result, power was also lost to preferred station

Transformer RTX-XSR1D and the Division II 4.16 kV ESF bus. The running shutdown

cooling, alternate decay heat removal, and plant operating water cleanup systems lostpower until the Division II EDG started and restored power to the ESF bus. Shutdown

cooling was restored in less than one hour. Initial inspection of this event was

documented in NRC integrated inspection Report 05000458/2004005. During thisinspection period, the inspectors reviewed the LER, the root cause analysis, and

corrective actions documented in CR-RBS-2004-03546. No additional findings of

significance were identified. This LER is closed. 3.(Closed) LER 50-458/2004-005-01, Unplanned Automatic Scram Due to Loss ofNon-Vital 120 Volt Instrument BusOn December 10, 2004, an automatic scram occurred due to a loss of power tononsafety-related instrumentation Bus VBN-PNL01B1. A capacitor on the control boardfor the nonsafety-related Inverter BYS-INV01B static switch failed, which caused a loss

of power to Bus VBN-PNL01B1, a subsequent downshift of the plant operating

recirculation pumps and a lockup of the main feedwater regulating valves. The result

was an automatic plant scram complicated by a loss of normal feedwater. Inspection of

this event was documented in NRC integrated inspection Report 05000458/2004005. Additional inspection was documented in

NRC supplemental inspection Report05000458/2005012. During this inspection period, the inspectors reviewed the LER, the

root cause analysis, and corrective actions documented in CR-RBS-2004-04289. No

additional findings of significance were identified. This LER is closed.

Enclosure-32- 4.(Closed) LER 50-458 /2005-001-01, Unplanned Manual Scram Due to Indication ofGround Fault in Main GeneratorOn January 15, 2005, while the plant was at 100 percent power, a main generator fieldground fault alarm was received. Control room operators tripped the turbine in

accordance with alarm response Procedure ARP-680-09. The licensee later determined

that one of the five rectifier banks in the generator excitation control system was thesource of the ground and removed it from service. In addition, the licensee tested the

relay that causes the main generator ground fault alarm and found it to be out of

calibration such that it alarmed before the ground current reached its setpoint. The

alarm response procedure requirement to trip the turbine was revised to allow validation

of the alarm before tripping the main turbine. Inspection of this event was documented

in NRC integrated inspection Report 05000458/2005002. Additional inspection wasdocumented in NRC supplemental inspection Report 05000458/2005012. During thisinspection period, the inspectors reviewed the LER, the root cause analysis, and

corrective actions documented in CR-RBS-2005-00140. No additional findings of

significance were identified. This LER is closed.4OA5Other ActivitiesImplementation of Temporary Instruction 2515/165 - Operational Readiness of OffsitePower and Impact on Plant Risk a.Inspection ScopeThe objective of Temporary Instruction 2515/165, "Operational Readiness of OffsitePower and Impact on Plant Risk," was to gather information to support the assessment

of nuclear power plant operational readiness of offsite power systems and impact onplant risk. During this inspection, the inspectors interviewed licensee personnel,

reviewed licensee procedures, and gathered information for further evaluation by the

Office of Nuclear Reactor Regulation. b.FindingsNo findings of significance were identified.4OA6Meetings, Including ExitExit MeetingsOn May 5, 2006, the inspector presented the occupational radiation safety inspectionresults to Mr. D. Vinci, General Manager, Plant Operations, and other members of his

staff who acknowledged the findings. The inspector confirmed that proprietary

information was not provided or examined during the inspection.On May 5, 2006, the inspector presented the results of this inspection of inserviceinspection activities to Mr. P. Russell, Manager, System Engineering, and other

Enclosure-33-members of licensee management. The inspector confirmed that proprietaryinformation was not provided or examined during the inspection.On July 5, 2006, the resident inspectors presented the integrated baseline inspectionresults to Mr. P. Hinnenkamp, Vice President - Operations, and other members of

licensee management. The inspectors confirmed that proprietary information was not

provided or examined during the inspection.ATTACHMENT: SUPPLEMENTAL INFORMATION

AttachmentA-1SUPPLEMENTAL INFORMATIONKEY POINTS OF CONTACTLicensee PersonnelT. Baccus, Acting Supervisor, ALARA PlanningL. Ballard, Manager, Quality Programs

D. Burnett, Superintendent, Chemistry

C. Bush, Manager, Outage

J. Clark, Assistant Operations Manager - Training

T. Coleman, Manager, Planning and Scheduling/Outage

M. Davis, Manager, Radiation Protection

C. Forpahl, Manager, Corrective Action Program

T. Gates, Manager, Equipment ReliabilityH. Goodman, Director, Engineering

K. Higginbotham, Assistant Operations Manager - Shift

P. Hinnenkamp, Vice President - Operations

B. Houston, Manager, Plant Maintenance

A. James, Superintendent, Plant Security

K. Jenks, Supervisor, Engineering Codes and Standards

N. Johnson, Manager, Engineering Programs & Components

R. King, Director, Nuclear Safety Assurance

J. Leavines, Manager, Emergency Planning

D. Lorfing, Manager, Licensing

J. Maher, Superintendent, Reactor Engineering

W. Mashburn, Manager, Design Engineering

J. Miller, Manager, Training and DevelopmentP. Russell, Manager, System Engineering

C. Stafford, Manager, Operations

D. Vinci, General Manager - Plant OperationsLIST OF ITEMS OPENED, CLOSED, AND DISCUSSEDOpened and Closed05000458/2006003-01NCVFailure to identify Division III ESF bus supply breaker notracked in05000458/2006003-02NCVFailure to adequately manage an increase in plant risk 05000458/2006003-03NCVInadequate procedure to verify required offsite powerbreaker alignment05000458/2006003-04NCVFailure to control access to a high radiation area

05000458/2006003-05NCV Failure to perform airborne radiation survey

AttachmentA-2Closed50-458/2004-003-01LERUnplanned Automatic Start of Standby Diesel GeneratorDue to Loss of Division 1 Switchgear50-458/2004-004-01LER Unplanned Automatic Start of Standby Diesel GeneratorDue to Loss of Division 2 Switchgear50-458/2004-005-01LERUnplanned Automatic Scram Due to Loss of Non-Vital 120Volt Instrument Bus50-458 /2005-001-01LERUnplanned Manual Scram Due to Indication of GroundFault in Main GeneratorLIST OF DOCUMENTS REVIEWEDThe following documents were selected and reviewed by the inspectors to accomplish theobjectives and scope of the inspection and to support any findings:Section 1R06: Inservice Inspection ActivitiesProceduresCEP-NDE-0400, "Ultrasonic Examination," Revision 0CEP-NDE-0404, "Manual Ultrasonic Examination of Ferritic Piping Welds (ASME XI),"Revision 1CEP-NDE-0407, "Straight Beam Ultrasonic Examination of Bolts and Studs (ASME XI),"Revision 1CEP-NDE-0423, "Manual Ultrasonic Examination of Austenitic Piping Welds (ASME XI),"Revision 1CEP-NDE-0424, "Manual Ultrasonic Examination of the Reactor Vessel Flange Ligament Areas(ASME XI)," Revision 1CEP-NDE-0428, "Manual Ultrasonic Throughwall Sizing in Piping Welds (ASME XI)," Revision 1

CEP-NDE-0641, "Liquid Penetrant Examination for ASME Section XI," Revision 1

CEP-NDE-0731, "Magnetic Particle Examination (ASME Section XI)," Revision 0

SPP-7010, "Preparation of Weld Data Documents," Revision 9

AttachmentMiscellaneous Documents7228.000-701-131A, "Risk Informed Break Exclusion Region Evaluation for River BendStation," Revision 0Liquid Penetrant ExaminationsBOP-PT-06-024BOP-PT-06-025BOP-PT-06-026BOP-PT-06-029UT Calibration ReportsCAL -06-015CAL -06-016CAL-06-017UT Pipe Weld ExaminationsISI-UT-06-003ISI-UT-06-006ISI-UT-06-009ISI-UT-06-012ISI-UT-06-004ISI-UT-06-007ISI-UT-06-010ISI-UT-06-013

ISI-UT-06-005ISI-UT-06-008ISI-UT-06-011ISI-UT-06-014Condition ReportsCR-RBS-2005-00065CR-RBS-2005-00067CR-RBS-2005-00100CR-RBS-2005-01379Section 1R15: Operability EvaluationsPrimary Containment Purge Exhaust Line OperabilityCR-RBS-2006-00964, primary containment purge exhaust line leak rate test results showingnegative trendADM-0050, "Primary Containment Leakage Rate Testing Program," Revision 8

SEP-APJ-001, "Primary containment Leakage Rate Testing (Appendix J) Program,"Revision 0GSTP-403-7301, "Containment Purge System Isolation Valve Leak Rate Test," Revisions 0, 1, 2, and 3RBS-ER-00-0589, "Post RF-09 LLRT Testing Interval Determination," dated January 25, 2001

RBS TS Amendment 81, dated July 20, 1995

RBS TS Bases Revision 126, dated March 31, 206

AttachmentA-4NNS-ACB23 Not FunctionalElectrical DrawingsEE-001AC, "Startup Electrical Distribution Chart," Revision 33ESK-05NNS03, "Elementary Diagram - 4.16 kV Switchgear Bus 1C Normal Supply ACB,"Revision 13Corrective Action DocumentsCR-RBS-2006-02402CR-RBS-2006-0235CR-RBS-2006-02337CR-RBS-1998-00190ProceduresOSP-0022, "Operations General Administrative Guidelines," Revision 01GOP-0001, "Plant Startup," Revision 47, performed on May 12, 2006STP-000-0102, "Power Distribution Alignment Check," Revision 4, performed on May 9, 2006

STP-000-0102, "Power Distribution Alignment Check," Revision 4, performed on May 22, 2006Work RequestsWR 76625WR 77441WR77478

Miscellaneous DocumentsMain Control Room LogsTS LCO Records: 1-OPT-06-01871-TS-06-0694

RBS Tagout Record: 1-302-NNS-SWG1A-006-ASection 1R20: Refueling and Other Outage ActivitiesProceduresRSP-0217, "Auxiliary Access Control Functions," Revision 27GOP-0003, "Scram Recovery," Revision 14A, post scram report, dated April 23, 2006

OSP-0031, "Shutdown Operations Protection Plan," Revision 16OSP-0041, "Alternate Decay Heat Removal," Revision 8A

AOP-0051, "Loss of Decay Heat Removal," Revision 18

OSP-0034, "Control of Obstructions for Primary Containment/Fuel Building Operability,"Revision 3

AttachmentA-5GOP-0001, "Plant Startup," Revision 47, performed on May 12, 2006Corrective Action DocumentsCR-RBS-2006-00691CR-RBS-2006-01937

Miscellaneous DocumentsControl Room Logs

TS LCO Logs

Daily Refueling Outage Updates

ORAT Report

WO 50340401 and 81284

ER-RB-2005-0157-000, "Install new relays on the output of EOC-RPT optical output cardsC71A-AT17 and C71A-AT18," dated May 16, 2006WO 5034041's task outline to configure the station blackout diesel to supply power to spent fuelpool cooling Pump SFC-P1AWO 5034041, Configure the station blackout diesel to supply power to spent fuel pool coolingPump SFC-P1A, written May 3, 2006Section 1R22: Surveillance TestingDrawing EE-001AC, "Startup Electrical Distribution Chart," Revision 33TS Section 3.8.1 and Bases 3.8.1, Revision 0

USAR Section 8.2.1.2.1, "General Design Criteria," Revision 16

NUREG-0989, "Safety Evaluation Report Related to the Operation of River Bend Station,"dated May 1984TS LCO Logs1-TS-06-0694I-TS-06-06851-TS-05-0386

Corrective Action DocumentsCR-RBS-2006-02675CR-RBS-2006-02402CR-RBS-2005-02331

AttachmentA-6Section 4OA2: Identification and Resolution of ProblemsSemiannual Trend ReviewCR-RBS-2004-02165CR-RBS-2006-00159

CR-RBS-2006-00226

CR-RBS-2006-00279

CR-RBS-2006-00296

CR-RBS-2006-00434

CR-RBS-2006-00663

CR-RBS-2006-00798

CR-RBS-2006-00799

CR-RBS-2006-00928

CR-RBS-2006-00993

CR-RBS-2006-01131

CR-RBS-2006-01132

CR-RBS-2006-01205

CR-RBS-2006-01261CR-RBS-2006-01270CR-RBS-2006-01324

CR-RBS-2006-01333

CR-RBS-2006-01429

CR-RBS-2006-01464

CR-RBS-2006-01489

CR-RBS-2006-01490

CR-RBS-2006-02269

CR-RBS-2006-02348

CR-RBS-2006-02349

CR-RBS-2006-02356

CR-RBS-2006-02375

CR-RBS-2006-02406

CR-RBS-2006-02407CR-RBS-2006-02469CR-RBS-2006-02484

CR-RBS-2006-02540

CR-RBS-2006-02544

CR-RBS-2006-02550

CR-RBS-2006-02558

CR-RBS-2006-02559

CR-RBS-2006-02651

CR-RBS-2006-02661

CR-RBS-2006-02682

CR-RBS-2006-02683

CR-RBS-2006-02732

CR-RBS-2006-02733

CR-RBS-2006-02799Section 2OS1: Access Controls to Radiologically Significant Areas

Corrective Action DocumentsCR-RBS-2006-00090 CR-RBS- 2006-01294 CR-RBS-2006-01787 CR-RBS- 2006-01950Radiation Work Permits2006-1915RFO-13, Remove and Replace LPRMs, Including Support Activities2006-1921RFO-13, Flow Control Valve Maintenance, Including Support Activities

2006-1929RFO-13, Recirc Pump Work, Including Support ActivitiesProceduresRP-103Access Control, Revision 2RP-106Radiological Survey Documentation, Revision 1

RP-108Radiation Protection Posting, Revision 2

RPP-0006Performance of Radiological Surveys, Revision 19Section 2OS2: ALARA Planning and Controls (71121.02)Corrective Action DocumentsCR-RBS-2006-01746ProceduresENS-RP-105Radiation Work Permits, Revision 7

AttachmentA-7LIST OF ACRONYMSCDFcore damage frequencyALARAas low as is reasonably achievable

ASMEAmerican Society of Mechanical Engineers

CAPcorrective action program

CFRCode of Federal RegulationsCR-RBSRiver Bend Station condition report

EDGemergency diesel generator

LERlicensee event report

MCinspection manual chapter

NCVnoncited violation

NDEnondestructive examination

NEINuclear Energy Institute

NRCU.S. Nuclear Regulatory Commission

ORAToutage risk assessment team

PIperformance indicators

RCSreactor coolant system

RFOrefueling outage

SFCspent fuel pool cooli ng syst emSOPsystem operating proceduresSRsurveillance requirement

SSCstructures, systems, or componentsSTPsurveillance test procedure

TSTechnical Specifications

USARUpdated Safety Analysis Report

WOwork order

WRwork request