IR 05000458/2006005

IR 05000458-06-005; 10/01/2006 - 12/31/2006; River Bend Station; Operability Evaluations; Post Maintenance Testing; Access Control to Radiologically Significant Areas; Event Followup

ML070440193
Person / Time
Site:	River Bend
Issue date:	02/13/2007
From:	Hay M NRC/RGN-IV/DRP/RPB-C
To:	Venable J Entergy Operations
References
IR-06-005
Download: ML070440193 (39)

Text

February 13, 2007

SUBJECT:

RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT 05000458/2006005

Dear Mr. Venable:

On December 31, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your River Bend Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 8, 2007, with Mr. Don Vinci, General Manager, Plant Operations, and other members of your staff.

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

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

The report documents five self-revealing findings of very low safety significance (Green). Four of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as noncited violations (NCVs), consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis of your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies 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 Resident Inspector at the River Bend Station facility.

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs 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 them with you.

Sincerely,

/RA/

Michael C. Hay, Chief Project Branch C Division of Reactor Projects Docket: 50-458 License: NPF-47

Enclosure:

NRC Inspection Report 05000458/2006005 w/Attachment: Supplemental Information

REGION IV==

Docket:

50-458 License:

NPF-47 Report:

05000458/2006005 Licensee:

Entergy Operations, Inc.

Facility:

River Bend Station Location:

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

October 1 through December 31, 2006 Inspectors:

P. Alter, Senior Resident Inspector, Project Branch C M. Miller, Resident Inspector, Project Branch C R. Lantz, Senior Emergency Preparedness Inspector, Operations Branch P. Goldberg, Reactor Inspector, Engineering Branch 2 Approved By:

Michael C. Hay, Chief Project Branch C Division of Reactor Projects

Enclosure-2-

SUMMARY OF FINDINGS

IR 05000458/2006005; 10/01/2006 - 12/31/2006; River Bend Station; Operability Evaluations;

Postmaintenance Testing; Access Control to Radiologically Significant Areas; Event Followup.

The report covered a 3-month period of routine baseline inspections by resident inspectors and announced baseline inspections by Region IV emergency planning, engineering, and maintenance inspectors. Four Green noncited violations and one Green finding 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. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 3, dated July 2000.

Cornerstone: Mitigating Systems

C

Green.

A self-revealing, noncited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, "Corrective Action," was identified involving the failure to identify a degraded condition affecting the steam leak detection and Division II isolation logic for residual heat removal/reactor core isolation cooling systems. The degraded condition resulted in a spurious isolation of the reactor core isolation cooling system during power operations on November 23, 2006. This issue was entered into the licensees corrective action program as CR-RBS-2006-04460.

The finding was more than minor because it is associated with the mitigating system cornerstone attribute of equipment performance and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using NRC Manual Chapter 0609, "Significance Determination Process," a Phase 2 analysis concluded that the finding was of very low safety significance. The cause of the finding is related to the crosscutting aspect of problem identification and resolution in that the licensee failed to completely and accurately identify the condition that caused a previous isolation of the reactor core isolation cooling system on October 1, 2004. This failure resulted in the spurious reactor core isolation cooling system isolation on November 23, 2006.

(Section 1R15)

Cornerstone: Barrier Integrity

C

Green.

A self-revealing, noncited violation of Technical Specification 5.4.1.a was identified involving the failure to provide adequate maintenance instructions for replacement of relays in the Division I standby gas treatment system initiation logic. As a result, on November 21, 2006, during relay replacement, the annulus pressure control system tripped and the Division II standby gas treatment system automatically initiated.

This issue was entered into the licensee's corrective action program as CR-RBS-2006-04445.

This finding was more than minor because it is associated with the barrier integrity cornerstone attribute of human performance affecting the cornerstone objective to provide reasonable assurance that the secondary containment barrier protects the public from radionuclide releases caused by accidents and events. Using the NRC Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding was determined to have very low safety significance because only the standby gas treatment system was affected. The cause of the finding is related to the crosscutting element of human performance in that the licensee failed to provide complete, accurate, and up-to-date instructions in the work package to replace the relays in the Division I standby gas treatment system initiation logic. (Section 1R19)

C

Green.

A self-revealing, noncited violation of Technical Specification 5.4.1.a was identified involving the failure to follow Procedure SOP-0048, 120 Vac System,

Revision 303. Due to ineffective self-and peer-checking a procedure step was missed, resulting in inadvertent isolation of the reactor water cleanup and the suppression pool cooling and cleanup systems. This issue was entered into the licensee's corrective action program as CR-RBS-2006-03874.

The finding was more than minor because the loss of the reactor water cleanup system, providing reactor water chemistry control, affects the fuel barrier integrity cornerstone attribute of configuration control. Using the NRC Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding was determined to have very low safety significance because only the fuel cladding barrier was affected. The cause of the finding is related to the crosscutting element of human performance in that operations personnel failed to make proper use of human performance techniques of self-and peer-checking. (Section 4OA3)

C

Green.

A self-revealing finding was identified involving the installation of a pump coupling that exceeded vendor shelf-and service-life recommendations on November 15, 2006. As a result, the reactor water cleanup Pump A coupling failed on November 28, 2006, requiring operators to remove from service the reactor water cleanup pump and a demineralizer affecting the primary means of reactor water chemistry control. This issue was entered into the licensee's corrective action program as CR-RBS-2006-04488 and -04517.

The finding is greater than minor because it would become a more significant safety concern if left uncorrected, since failure of similar couplings affecting other plant components, such as the drywell floor and equipment drain pumps, would require a plant shutdown to make repairs. The finding affected the barrier integrity cornerstone.

Using the NRC Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding was determined to have very low safety significance because the finding only affected the fuel cladding barrier. (Section 4OA3)

Cornerstone: Occupational Radiation Safety

C

Green.

A self-revealing, noncited violation of 10 CFR 20.1501(a)(2) was identified involving the failure of radiation protection personnel to perform a survey in the off-gas sample room during main condenser leak testing. As a result, when a chemistry technician entered the room to obtain a grab sample, his electronic alarming dosimeter alarmed unexpectedly. When another chemistry technician reached into the room to perform a survey of the test equipment, his dosimeter also alarmed. It was later determined that they were exposed to a dose rate of 440 and 521 millirem per hour, respectively. This issue was entered into the licensee's corrective action program as CR-RBS-2006-04340.

The finding was more than minor because it was associated with the occupational radiation safety cornerstone attribute of programs and processes, such as the monitoring of radiological conditions, specifically the failure to perform a survey following changes in radiological conditions in the off-gas sample room, and affects the associated cornerstone objective to ensure the adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Utilizing Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the inspectors determined that the finding was of very low safety significance because it did not involve: (1) as low as is reasonably achievable planning and controls, (2) an overexposure, (3) a substantial potential for an overexposure, or (4) an impaired ability to assess dose. The cause of the finding was related to the crosscutting element of problem identification and resolution in that the licensee failed to communicate to affected personnel in a timely manner internal operating experience, specifically, while there was off-gas flow through the condenser leak test equipment, radiological conditions would increase. (Section 2OS1)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status: With the exception of a planned downpower for control rod pattern adjustments, the plant was operated at 100 percent power from October 1-19, 2006, when the reactor automatically scrammed due to a loss of feedwater flow to the reactor. The plant acquired criticality on October 22, 2006, and 100 percent power operation was achieved on October 26, 2006. Reactor power was reduced to 75 percent on November 13, 2006, for a reactor water cleanup (RWCU) system outage and condenser leak repairs. The reactor was returned to 100 percent power on November 20, 2006. Reactor power was reduced to 75 percent on December 5, 2006, to repair main condenser tube leaks and restored to 100 percent power on December 7, 2006. The reactor remained at 100 percent power throughout the remainder of the assessment period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

a. Inspection Scope

==

.1 Readiness For Seasonal Susceptibilities

The inspectors completed a review of the licensee's readiness for seasonal susceptibilities involving cold weather conditions at the beginning of November. The inspectors:

(1) reviewed plant procedures, the Updated Safety Analysis Report (USAR),and Technical Specifications (TS) to ensure that operator actions defined in adverse weather procedures maintained the readiness of essential systems;

(2) walked down portions of the systems listed below to ensure that adverse weather protection features (heat tracing, space heaters, weatherized enclosures, temporary chillers, etc.) were sufficient to support operability, including the ability to perform safe shutdown functions;

(3) evaluated operator staffing levels to ensure the licensee could maintain the readiness of essential systems required by plant procedures; and

(4) reviewed the corrective action program (CAP) to determine if the licensee identified and corrected problems related to adverse weather conditions. The inspectors also reviewed Procedure OSP-0043, Freeze Protection and Temperature Maintenance, Revision 07, used by the operators to monitor areas of the plant susceptible to cold weather conditions.

• November 3, 2006, heat trace panels in the normal switchgear building

• November 3, 2006, standby cooling tower and Tunnel G located below the cooling tower

• November 6, 2006, heat trace panels in the fire water pump house The inspectors completed one inspection sample.

.2 Readiness For Impending Adverse Weather Conditions

On October 19, 2006, the inspectors completed a review of the licensee's readiness for impending adverse weather involving severe thunderstorms, tornado watch, and flash flood warnings for West Feliciana Parish and its surrounding parishes identified by the National Weather Service. The inspectors:

(1) reviewed plant and corporate procedures to ensure that operator actions defined in adverse weather procedures maintained the readiness of essential systems; and

(2) walked down outside areas of the plant, including the transformer yard, in the protected area and around the ultimate heat sink to ensure that missile hazards were minimized.

C October 19, 2006, transformer yard and the ultimate heat sink Documents reviewed by the inspectors included:

C Abnormal Operating Procedure, AOP-0029, Severe Weather Operation, Revision19 C

Entergy Nuclear South Procedure, ENS-EP-302, Severe Weather Response, Revision 6 C

CR-RBS-2006-4108, Severe Weather Response on October 19, 2006 The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

==1R04 Equipment Alignment

Partial System Walkdowns

a. Inspection Scope

The inspectors:==

(1) walked down portions of the two risk important systems listed below and reviewed plant procedures and documents to verify that critical portions of the selected systems were correctly aligned; and

(2) compared deficiencies identified during the walkdown to the licensee's USAR and CAP to ensure problems were being identified and corrected.

C October 18, 2006, high pressure core spray system (HPCS)

C October 30, 2006, reactor core isolation cooling system (RCIC)

System operating procedures (SOP) reviewed by the inspectors included:

C SOP-0030, High Pressure Core Spray System, Revision 23 C

SOP-0035, Reactor Core Isolation Cooling System, Revision 29 The inspectors completed two inspection samples.

b. Findings

No findings of significance were identified.

Complete System Walkdown

a. Inspection Scope

The inspectors:

(1) reviewed plant procedures, drawings, including piping and instrument drawings, the USAR, TS, and vendor manuals to determine the correct alignment of the control rod drive (CRD) system;

(2) reviewed outstanding design issues, operator workarounds, and USAR documents to determine if open issues affected the functionality of the CRD system; and

(3) verified that the licensee was identifying and resolving equipment alignment problems. Documents reviewed by the inspectors included:

C SOP-0002, Control Rod Drive Hydraulics, Revision 26 C

CRD system health report and maintenance rule report C

Piping and Instrument Drawing PID-36-01C & D, Control Rod Drive Hydraulics, Revision 17 C

CR-RBS-2006-0261, Mis-positioned control rod drive pump discharge filter vent and drain valves, November 6, 2006 The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

==1R05 Fire Protection

a. Inspection Scope

==

.1 Quarterly Inspection

The inspectors walked down the six plant areas listed below to assess the material condition of active and passive fire protection features and their operational lineup and readiness. The inspectors:

(1) verified that transient combustibles and hot work activities 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 they remained functional and that access to manual actuators was unobstructed;

(4) verified that fire extinguishers and hose stations were provided at their designated locations and 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) verified that adequate compensatory measures were established for degraded or inoperable fire protection features and that the compensatory measures were commensurate with the significance of the deficiency; and

(7) reviewed the CAP to determine if the licensee identified and corrected fire protection problems.

C October 18, 2006, Auxiliary Building, 70-foot level, residual heat removal (RHR)

Pump C room, Fire Area AB-4/Z-1 & Z-2 C

October 18, 2006, Auxiliary Building, 70-foot level, RCIC room, Fire Area AB-4/Z-1 & Z2 C

October 18, 2006, Auxiliary Building, 141-foot level, standby gas treatment (SGTS)

Filter A room, Fire Area AB-14 C

October 18, 2006, Auxiliary Building, 141-foot level, SGTS Filter B room, Fire Area AB-15 C

December 8, 2006, Fuel Building, 70-foot level, fuel pool cooling Pump 1A room, Fire Area FB-1/Z-1 C

December 8, 2006, Fuel Building, 70-foot level, CRD Pump and Filter area, Fire Area FB-1/Z-1 Documents reviewed by the inspectors included:

C Pre-Fire Plan/Strategy Book C

USAR Section 9A.2, Fire Hazards Analysis, Revision 10 C

River Bend Station post-fire safe shutdown analysis C

RBNP-038, Site Fire Protection Program, Revision 06B The inspectors completed six inspection samples.

b. Findings

No findings of significance were identified.

==1R06 Flood Protection Measures

a. Inspection Scope

Semiannual Internal Flooding The inspectors:==

(1) reviewed the USAR, the flooding analysis, and plant procedures to assess seasonal susceptibilities involving internal flooding;

(2) reviewed the USAR and CAP to determine if the licensee identified and corrected flooding problems;

(3) verified that operator actions for coping with flooding can reasonably achieve the desired outcomes; and

(4) walked down the area to verify the adequacy of:

(a) equipment seals located below the floodline,

(b) floor and wall penetration seals,

(c) watertight door seals,

(d) common drain lines and sumps,

(e) sump pumps, level alarms, and control circuits, and

(f) temporary or removable flood barriers. The specific areas inspected, during the week of December 11, 2006, were the RCIC and RHR Pump C rooms.

Documents reviewed by the inspectors included:

C River Bend Individual Plant Examination of External Events C

USAR Section 3.4.1, Flood Protection C

G13.18.12.3.15, Internal Flooding Screening Analysis C

G13.2.3 PN-317, Max Flood Elevations for Moderate Energy Line Cracks in Cat 1 Structures The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

==1R07 Biennial Heat Sink Performance

==

.1 Performance of Testing, Maintenance, and Inspection Activities

a. Inspection Scope

The inspector selected three heat exchangers that were either directly or indirectly connected to the safety-related service water system. The inspector reviewed the licensee's testing and cleaning methodology for the following heat exchangers:

• Heat exchangers used to cool normal service water

• HPCS Pump Room Cooler 1HVR*UC5

• Low Pressure Core Spray Pump Room Cooler 1HV8*UC6 In addition, the inspector reviewed test data for the heat exchangers and design and vendor-supplied information to ensure that the heat exchangers were performing within their design bases. The inspector also reviewed chemical controls used to avoid fouling and heat exchanger test, inspection, and cleaning results. Specifically, the inspector verified proper extrapolation of test conditions to design conditions, appropriate use of test instrumentation, and appropriate accounting for instrument inaccuracies.

Additionally, the inspector verified that the licensee appropriately trended these inspection and cleaning results, assessed the causes of the trends, and took necessary actions for any step changes in these trends. The inspector reviewed the methods and results of heat exchanger inspection and cleaning, verified that the methods used to inspect and clean were consistent with industry standards, and ensured that the as-found results were appropriately dispositioned such that the final conditions were acceptable.

The inspector completed three inspection samples.

b. Findings

No findings of significance were identified.

.2 Verification of Conditions and Operations Consistent with Design Bases

a. Inspection Scope

For the selected heat exchangers, the inspector verified that the licensee established heat sink and heat exchanger condition and operation and test criteria that were consistent with the design assumptions. Specifically, the inspector reviewed the applicable calculations to ensure that the thermal performance test acceptance criteria for the heat exchangers were being applied consistently throughout the calculations.

The inspector also verified that the appropriate acceptance values for fouling and tube plugging for the component cooling water heat exchangers remained consistent with the values used in the design-basis calculations.

b. Findings

No findings of significance were identified.

.3 Identification and Resolution of Problems

a. Inspection Scope

The inspector verified that the licensee had entered significant heat exchanger/heat sink performance problems into the CAP. The inspector reviewed nine condition reports (CRs), which are listed in the attachment.

b. Findings

No findings of significance were identified.

==1R11 Licensed Operator Requalification Program

a. Inspection Scope

==

The inspectors observed testing and training of senior reactor operators and reactor operators to identify deficiencies and discrepancies in the training, to assess operator performance, and to assess the evaluator's critique. The training scenario involved a loss of Division III DC distribution panel, with RCIC tagged out, which required entry into a 12-hour limiting condition for operation and plant shutdown. Documents reviewed by the inspectors included:

C Simulator Scenario, RSMS-OPS-419, Loss of Div III 125 VDC, Revision 3 C

Operations Section Procedure, OSP-0053, Emergency and Transient Response Support Procedure, Revision 4 The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

The inspectors reviewed the two maintenance activities listed below to:

(1) verify the appropriate handling of structures, systems, and components (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 the TS.

C December 20, 2006, CRD Discharge Filter C11-FCTD003B had high differential pressure prematurely C

December 21, 2006, CRD Pump C11-PC001A had a degraded trend for CRD accumulator charging pressure Documents reviewed by the inspectors included:

C NUMARC 93-01, Nuclear Energy Institute Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2 C

Licensee maintenance rule function list C

Licensee maintenance rule performance criteria list C

SSC maintenance rule Performance Evaluations C11-FCTD003B and C11-PC001A The inspectors completed two inspection samples.

b. Findings

No findings of significance were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

.1 Risk Assessment and Management of Risk

The inspectors reviewed the two assessment activities listed below to verify:

(1) performance of 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 04B, 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;

(3) that the licensee recognizes, and/or enters as applicable, the appropriate licensee-established risk category according to the risk assessment results and licensee procedures; and

(4) that the licensee identified and corrected problems related to maintenance risk assessments. Documents reviewed by the inspectors included licensee computer generated equipment out-of-service risk assessment displays/printouts.

• Week of October 16, 2006, RCIC system outage with occasional severe thunderstorms during the week

• Week of October 30, 2006, HPCS system outage with CRD Pump A out of service The inspectors completed two inspection samples.

b. Findings

No findings of significance were identified.

==1R15 Operability Evaluations

a. Inspection Scope

The inspectors:==

(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 in accordance with Procedure EN-OP-104, Operability Determinations, Revision 01;

(2) referred to the USAR and design basis documents to review the technical adequacy of licensee operability evaluations;

(3) evaluated compensatory measures associated with operability evaluations;

(4) determined degraded component impact on any TS;

(5) used the Significance Determination Process to evaluate the risk significance of degraded or inoperable equipment; and

(6) verified that the licensee has identified and implemented appropriate corrective actions associated with degraded components. The licensee operability evaluations were documented in the following CRs:

C CR-RBS-2006-04460, RCIC system isolated on high steam line differential pressure, reviewed on November 24, 2006 C

CR-RBS-2006-04516, RCIC high steam line differential pressure instrument spiking, reviewed on December 1, 2006 C

CR-RBS-2006-04101, Containment purge exhaust Penetration KJB-Z33 local leak rate test results above administrative limits, reviewed on December 27, 2006 The inspectors completed three inspection samples.

b. Findings

Introduction:

A self-revealing noncited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified involving the failure to identify a degraded condition affecting the steam leak detection and Division II isolation logic for RHR/RCIC systems. The degraded condition resulted in a spurious isolation of the RCIC system during power operations on November 23, 2006.

Description:

On November 23, 2006, the leak detection system Transmitter E31-N084B output signal spuriously spiked and isolated RCIC during steady state operations at 100 percent power, as documented in CR-RBS-2006-04460. The licensee declared Transmitter E31-N084B inoperable and returned RCIC to a normal standby lineup. The licensee then conducted a high pressure low volume flush of the Transmitter E31-N084B sensing line and checked the calibration of the instrument. The licensee determined that Transmitter E31-N084B was responding correctly and was capable of performing its safety function to isolate RCIC, so they restored Transmitter E31-N084B to service.

The inspectors noted that the November 23, 2006, spurious isolation of RCIC, caused by Transmitter E31-N084B, had previously occurred on October 1, 2004, immediately following a reactor scram, as documented in CR-RBS-2004-02906. The licensees analysis of the October 1, 2004, isolation resulted in a corrective action to flush Transmitter E31-N084B sensing lines whenever the reactor is in Modes 4 or 5. The licensees analysis of the October 1, 2004, spurious isolation failed to identify that Transmitter E31-N084B instrument noise and occasional spiking had existed prior to that scram.

On November 30, 2006, following a return to full power from a RWCU system outage, operators declared Transmitter E31-N084B inoperable, as documented in CR-RBS-2006-04516, due to noise and occasional spiking. The licensee determined that a low volume flush was not sufficient, performed a high-pressure, high-volume flush of the instrument lines to correct the condition, and declared Transmitter E31-N084B operable.

On December 15, 2006, following a return to full power from a main condenser waterbox outage, the inspectors notified the operations shift manager that Transmitter E31-N084B noise and occasional spiking had returned. Operators consulted with system engineers and declared Transmitter E31-N084B inoperable, as documented in CR-RBS-2006-04663. The licensee performed a high-pressure, high-volume flush of the instrument lines to correct the condition and declared Transmitter E31-N084B operable.

On December 17, 2006, operations management initiated CR-RBS-2006-04670 documenting that a missed opportunity was identified for establishing additional monitoring criteria for ensuring the operability of the RCIC system following the isolation on November 24, 2006. On December 18, 2006, the licensee issued an Operational Decision Making Issue Plan for Transmitter E31-N084A & -B fluctuations, establishing trigger points and actions to be taken should Transmitter E31-N084A or -B noise levels or spikes exceed predefined values.

The inspectors noted that the licensee had Transmitter E31-N084B data readily available and failed to effectively use this information to identify the conditions causing the increased noise and occasional spiking of Transmitter E31-N084B output, resulting in RCIC isolations.

The inspectors reviewed the plant data server graphs of Transmitters E31-N084A and

-B output signals and found the following:

• A reactor scram on August 15, 2004, began a cycle of noise and spikes which directly led to the isolation on October 1, 2004.

• Reactor scrams on September 18, 2002, and September 22, 2003, exacerbated or began the instrument noise and occasional spiking.

• Corrective actions to flush the instrument line during cold shutdown did little to reduce the noise and spiking; however, this was not recognized by the licensee.

• The noise and spikes got worse after the December 10, 2004, scram and were clearly visible on computer data graphs before and after the January 15, 2005, scram.

• The recurring nature of the instruments noise and occasional spiking was not identified by the licensee until November 2006.

The inspectors determined that, following the October 1, 2004, isolation of RCIC, the licensee failed to identify and correct the conditions causing Transmitter E31-N084B noise level and spiking, resulting in the inadvertent isolation of RCIC on November 23, 2006.

Analysis:

The performance deficiency associated with this finding involved the failure of the licensee to promptly identify and correct those conditions causing leak detection system Transmitter E31-N084B noise and occasional spiking following the inadvertent isolation of RCIC on October 1, 2004. The finding was more than minor because it was associated with the mitigating system cornerstone attribute of equipment performance and affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the NRC MC 0609, Significance Determination Process, Phase 1 Worksheet, a Phase 2 analysis was required because this finding resulted in the loss of a system safety function. Using NRC MC 0609, Appendix A, Attachment 1, "User Guidance for Determining the Significance of Reactor Inspection Findings for At-Power Situations," and the Risk-Informed Inspection Notebook for River Bend Station, Revision 2, the finding was determined to be of very low risk significance. This assessment was based on an exposure time of 18 days and the most limiting sequence being a transient with a loss of feedwater, with a failure of HPCS and failure to emergency depressurize. The cause of the finding was related to the crosscutting aspect of problem identification and resolution in that the licensee failed to completely and accurately identify the conditions that caused the October 1, 2004, RCIC isolation resulting in recurrence on November 23, 2006.

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that in the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to this, following an inadvertent isolation of RCIC on October 1, 2004, the licensee failed to identify the causes and implement corrective actions to prevent recurrence, resulting in an additional inadvertent isolation of RCIC on November 23, 2006. The licensee entered this issue into their CAP as CR-RBS-2006-04460. Because this finding was of very low safety significance and has been entered into the licensees CAP, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000458/2006005-01, Failure to Identify a degraded condition of steam leak detection system Transmitter E31-N084B.

==1R19 Postmaintenance Testing

a. Inspection Scope

==

The inspectors selected the three postmaintenance test activities listed below of risk significant systems or components. For each item, 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 ensure 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 data results were complete and accurate, the test equipment was removed, the system was properly realigned, 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. The postmaintenance testing was part of the following work orders (WO):

• WO 00078881 01, Division III diesel generator starting air receiver pressure relief valve, reviewed on October 1, 2006

• WO 00098673 01, Perform high volume flush of Transmitter E31-PDTN084B, reviewed on December 1, 2006

• WO 51055430, Replace six relays in the Division I SGTS initiation circuit, reviewed November 21, 2006 The inspectors completed three inspection samples.

b. Findings

Introduction:

A self-revealing NCV of TS 5.4.1.a was identified involving the failure to provide adequate instructions for relay replacement in the Division I SGTS initiation logic. As a result, during relay removal for replacement, the annulus pressure control (APC) system tripped and the Division II SGTS automatically initiated.

Description:

On November 21, 2006, operators started Division I SGTS, using SOP-0043, Standby Gas Treatment System, Revision 12, in preparation for replacement of six relays in the Division I SGTS initiation logic in accordance with WO 51055430. The operational impact statement in the WO stated that pulling the relays would automatically start Division I SGTS, so the system should be running before work was started.

During removal of Relay HVR-FN16B, the running annulus pressure control (APC)system tripped and Division II SGTS automatically started. Work was stopped since this response was not anticipated. When interviewed, the operator who wrote the operational impact statement for WO 51055430 acknowledged that the instructions were inadequate since they failed to reference the appropriate system operating procedure for starting Division I SGTS, locking out Division II SGTS, and securing the APC system prior to the relay replacement. The inspectors determined that the failure to specify the appropriate initial conditions and procedure to use prior to replacement of the Division I SGTS initiation logic relays in WO 51055430 resulted in the inadvertent challenge to APC and SGTSs.

Analysis:

The performance deficiency associated with this finding involved the failure to provide adequate instructions for relay replacement in the Division I SGTS initiation logic. As a result, during relay removal for replacement, the APC system tripped and the Division II SGTS automatically initiated. This inadvertent challenge to APC and SGTS was greater than minor because it was associated with the barrier integrity cornerstone attribute of human performance and affected the associated cornerstone objective to provide reasonable assurance that the secondary containment barrier protects the public from radionuclide releases caused by accidents and events. Using the NRC MC 0609, "Significance Determination Process," Phase 1 Worksheet, the finding was determined to have very low safety significance because the finding only affected the SGTS. The cause of the finding was related to the crosscutting element of human performance in that the licensee failed to provide complete, accurate, and up-to-date instructions in the work package to replace the relays in the Division I SGTS initiation logic.

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 9.a, requires procedures for maintenance on safety-related systems, such as SGTS. Contrary to this, WO 51055430 failed to provide adequate instructions for relay replacement in the Division I SGTS initiation logic. As a result, during relay removal for replacement, the APC system inadvertently tripped and the Division II SGTS automatically initiated. Because the finding was of very low safety significance and has been entered into the licensees CAP as CR-RBS-2006-04445, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000458/2006005-02, Inadequate work instructions result in isolation of annulus pressure control system and automatic start of the Division II standby gas treatment system.

==1R22 Surveillance Testing

a. Inspection Scope

==

The inspectors reviewed the USAR, procedure requirements, and TS to ensure that the three surveillance test procedures (STPs) 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 ASME Code requirements;

(12) updating of performance indicator data;

(13) accuracy of engineering evaluations, root causes, and bases for returning tested SSCs not meeting the test acceptance criteria;

(14) reference setting data; and

(15) annunciators and alarms setpoints. The inspectors also verified that the licensee identified and implemented any needed corrective actions associated with the surveillance testing.

• STP-050-0700, RCS Pressure/Temperature Limits verification, Revision 16A, reviewed on December 20, 2006

• STP-209-6800, RCIC Cold Shutdown Valve Operability Test, Revision 5A, reviewed on December 1, 2006 (Inservice test surveillance)

• STP-403-7301, Containment Purge System Isolation Valve Leak Rate Test, Revision 4, reviewed on December 21, 2006 The inspectors completed three inspection samples.

b. Findings

No findings of significance were identified.

==1R23 Temporary Plant Modifications

a. Inspection Scope

==

The inspectors reviewed the USAR, plant drawings, procedure requirements, and TS to ensure that the temporary modification listed below was properly implemented. The inspectors:

(1) verified that the modifications did not have an affect 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 modifications on permanently installed SSCs were supported by the test;

(4) verified that the modifications were identified on control room drawings 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 the temporary modification.

• Temporary Alteration 2006-0013, safety-related Transformer RTX-ESR1E pressure relay bypass, reviewed on December 5, 2006 The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector performed an in-office review of Revision 14 to Emergency Implementing Procedure EIP-2-001, "Classification of Emergencies," submitted in October 2006. The revision:

(1) added a definition of hostile force,

(2) revised fuel damage indicators for off-gas pretreatment radiation monitor readings based on actual off-gas flowrates,

(3) deleted the notice of unusual event Emergency Action Level 11-2 for a train derailment on site, and

(4) modified the indicators for alert Emergency Action Level 14-1 for a seismic event. The revision also added a new enclosure (Enclosure 1) to provide guidance and interim compensatory measures for implementation of the emergency action levels when equipment or indications used for the emergency action level are not available. This enclosure was not reviewed as part of the inspection.

The revision was compared to the previous revision; to the criteria of NUREG-0654, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," Revision 1; Nuclear Energy Institute 99-01, "Methodology for Development of Emergency Action Levels," Revision 4; and the standards in 10 CFR 50.47(b) to determine if the revision was adequately conducted following the requirements of 10 CFR 50.54(q). This review was not documented in a safety evaluation report and did not constitute approval of licensee changes; therefore, the revision is subject to future inspection.

The inspector completed one inspection sample.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

During the site emergency preparedness drill and simulator-based training listed below contributing to Drill/Exercise Performance and Emergency Response Organization Performance Indicators, the inspectors:

(1) observed the training evolution to identify any weaknesses and deficiencies in classification, notification, and protective action requirements development activities;

(2) reviewed the identified weaknesses and deficiencies against licensee-identified findings to determine whether the licensee is properly identifying failures; and

(3) determined whether licensee performance was in accordance with the guidance of the Nuclear Energy Institute 99-02, "Voluntary Submission of Performance Indicator Data," Revision 2, acceptance criteria.

C October 4, 2006, Team C Site Drill, loss of reserve station transformer Line 1, failure to automatically scram and security event Documents reviewed by the inspectors included:

C EIP-2-001, Classification of Emergencies, Revision 14 C

EIP-2-006, Notifications, Revision 32 C

EIP-2-007, Protective Action Guidelines Recommendations, Revision 21 C

EP-M-06-038, Drill Evaluation Report, ERO Team C, dated December 11, 2006 The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas

a. Inspection Scope

On November 10 and 12, 2006, the licensee performed leak testing of the main condenser. The inspectors reviewed and assessed the licensees performance in implementing physical and administrative controls of the high radiation area in the off-gas sample room where test equipment was installed to monitor off-gas sample flow for sodium hexaflouride (SF6) gas used during the testing.

The inspectors completed one inspection sample.

b. Findings

Introduction:

A self-revealing NCV of 10 CFR 20.1501(a) was identified involving the failure of radiation protection (RP) personnel to perform a survey in the off-gas sample room during main condenser leak testing. The violation had very low safety significance.

Description:

On November 10, 2006, the license was preparing for a downpower to make repairs to leaks in the main condenser. Previously, on November 8, 2006, during a challenge meeting for the condenser repairs, the former as low as is reasonably achievable program coordinator recommended that special attention be paid to the desiccant filter and water trap of the SF6 gas testing equipment that was to be used to identify which condenser waterbox was leaking. An action item was assigned to RP supervision to ensure that the filter and trap were monitored during testing. The RP supervisor briefed the RP technician and chemistry department personnel assigned to cover and perform the SF6 testing and directed the RP technician to place a remote reading dosimeter (telemetry) on the SF6 sample equipment. Since the exact location placement was not specified, the technician used his previous experience with condenser leak testing that used a different gas and placed the telemetry outside the off-gas sample room where the chemistry supervisor and technicians would be located during the testing.

Due to difficulties with setting up for injecting the SF6 gas into the condenser waterboxes, the testing was delayed to November 12, 2006. The prejob brief of the RP and chemistry personnel did not include the potential for high dose rates from the desiccant filter and water trap, but did note that telemetry was set up on the test equipment for remote monitoring by the RP control point. When testing began, the chemistry technician entered the off-gas sample room to initiate condenser off-gas sample flow through the SF6 test equipment and its desiccant filter and water trap.

Later during the testing, an off-gas pretreatment high radiation alarm was received.

Operators directed a second chemistry technician to obtain an off-gas sample in accordance with the alarm response procedure. When the second technician was briefed by the RP technician, normal off-gas sample room radiation levels were used because the telemetry (outside the room) showed no increase above those normal levels. The normal radiation levels in the off-gas sample room were a maximum of 45 millirem per hour general area, with a hot spot of 200 millirem per hour on contact and 100 millirem at one foot from the off-gas sample valve manifold.

When the second chemistry technician arrived at the off-gas sample room, the first technician covering the SF6 test briefed him on the physical location of the test equipment, which was near the sample valve manifold in the room. The second technician entered the room and, when he reached to fully open the valve to purge the sample line for his grab sample, his EAD alarmed. He immediately left the room without opening the valve. He consulted the first chemistry technician, who then reached into the room with a portable radiation monitor to determine the dose rate in the area of the SF6 test equipment and the off-gas sample valves. (The licensees chemistry technicians are qualified to perform radiation surveys.) When he did so, the first chemistry technicians EAD also alarmed. The results of the survey showed that the dose rates at the desiccant filter were 600 millirem per hour on contact and 180 millirem per hour at one foot.

The chemistry technicians informed the RP technician of their EAD alarms and the results of the survey of the desiccant filter. Based on the survey information, the RP technician authorized the second technician to enter the room and start sample purge flow, being careful to avoid the desiccant filter. The second technician entered the room, started the sample purge flow, and left the room. When the RP technician came to the scene, he entered the off-gas sample room and performed a new survey. The results showed that the dose rates at the desiccant filter had increased to 6,000 millirem per hour on contact and 1,800 millirem per hour at one foot. The RP technician immediately controlled the off-gas sample room as a locked high radiation area. The increase in dose rates was the result of increased off-gas sample flow through the desiccant filter. The chemistry technicians were not in the off-gas sample room when dose rates exceeded 1,000 millirem per hour at one foot from the source of radiation.

The RP technician briefed the two chemistry technicians on the dose rates in the off-gas sample room and authorized the second chemistry technician to enter the room to obtain his off-gas grab sample. Then he authorized the first chemistry technician to enter the room to close the sample purge valve. The off-gas sample room was then secured and posted as a locked high radiation area. Later, when their EADs were processed, it was determined that the chemistry technicians received a maximum dose rate of 521 and 440 millirem per hour and a dose of 9 and 7 millirem, respectively.

The inspectors determined that RP personnel failed to make proper use of previous plant operating experience with SF6 testing and failed to survey the desiccant filter and water trap in the test equipment once off-gas flow was initiated through the filter. Also, the telemetry used was not in a position (outside the off-gas sample room) to alert personnel of the changing radiological conditions in the vicinity of the desiccant filter inside the room.

Analysis:

The performance deficiency associated with this finding involved the failure of RP personnel to perform a survey in the off-gas sample room during main condenser leak testing, resulting in unexpected high dose rate alarms for individuals working in the area. The finding was more than minor because it was associated with the occupational radiation safety cornerstone attribute of programs and processes, such as the monitoring of radiological conditions, to ensure adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Using NRC MC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, the finding was of very low safety significance because it was not an as low as is reasonably achievable planning or work control issue, there was no overexposure or substantial potential for overexposure, and the ability to assess dose was not compromised. The cause of the finding was related to the crosscutting element of problem identification and resolution in that the licensee failed to utilize internal operating experience. Specifically, when there was off-gas flow through the condenser leak test equipment, the radiological conditions would change, requiring additional controls.

Enforcement:

10 CFR 20.1501(a) requires, in part, that each licensee shall make, or cause to be made, surveys that are reasonable under the circumstances to evaluate potential radiological hazzards. Contrary to this, the licensee failed to perform a survey of the condenser leak detection equipment in the off-gas sample room once sample flow was started through the equipment. As a result, two chemistry technicians EADs alarmed when they entered the room and got close to the test equipment. Because the finding was of very low safety significance and has been entered into the licensees CAP as CR-RBS-2006-04340, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000458/2006005-03, Licensee failed to perform a radiological survey in off gas sample room after radiological conditions had changed.

4OA1 Performance Indicator (PI) Verification

Cornerstone: Mitigating Systems

The Mitigating Systems Performance Index performance indicator was evaluated in accordance with Temporary Instruction 2515/169. The purpose of this inspection was to validate the unavailability and unreliability input data and to verify the accuracy of the results reported during the second and third quarters of 2006. On a sampling basis, the inspectors:

(1) reviewed surveillance procedures which when performed would not render the train unavailable for less than 15 minutes;

(2) reviewed a sample of baseline planned unavailability data;

(3) reviewed the licensees records for actual planned and unplanned unavailability data;

(4) reviewed the licensees records to confirm the accuracy on failure data for the identified monitored components; and

(5) reviewed the licensees criteria for selecting each systems boundary and system components monitored under the index.

The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

The inspectors performed a daily screening of items entered into the licensee's CAP.

This assessment was accomplished by reviewing work requests and CRs and attending corrective action review and work control meetings. The inspectors:

(1) verified that equipment, human performance, and program issues were being identified by the licensee at an appropriate threshold and that the issues were entered into the CAP;

(2) verified that corrective actions were commensurate with the significance of the issue; and

(3) identified conditions that might warrant additional follow-up through other baseline inspection procedures.

The inspectors completed one inspection sample.

.2 Selected Issue Follow-up Inspection

In addition to the routine review, the inspectors selected one issue for a more in-depth review. The inspectors considered the following during the review of the licensee's actions:

(1) complete and accurate identification of the problem in a timely manner;

(2) evaluation and disposition of operability/reportability issues;

(3) consideration of extent of condition, generic implications, common cause, and previous occurrences;

(4) classification and prioritization of the resolution of the problem;

(5) identification of root and contributing causes of the problem;

(6) identification of corrective actions; and

(7) completion of corrective actions in a timely manner. The inspectors reviewed WO 954417 used to verify yoke-to-body bolt torque on representative valves used to evaluate extent of condition for CR-RBS-2006-00162, loose yoke-to-body bolts found on RHR shutdown cooling suction Valve E12-MOVF006A.

The inspectors completed one inspection sample.

.3 Semiannual Trend Review

The inspectors completed a semiannual trend review of licensee programs designed to identify trends that might indicate the existence of more safety significant issues.

Specifically, the inspectors interviewed four representative system engineers to determine how they tracked and trended system and component performance of safety-related systems, including 125 Vdc and 120 Vac engineering safety feature systems, control rod drive mechanisms and hydraulics, standby service water, and emergency diesel generators. The system engineers provided examples of tracking mechanisms used by all system engineers, including:

(1) in-plant system walkdowns and monitoring program,

(2) inservice test and vibration monitoring program database,

(3) process computer system parameter trending,

(4) surveillance testing and performance monitoring data collection,

(5) work request/work order database,

(6) lube oil chemistry analysis results, and

(7) condition reports and CAP database. The inspectors compared and contrasted their results with the results contained in the licensee's system health report system and top ten list. Documents reviewed by the inspectors included:

C EN-DC-143, System Health Reports, Revision 03 C

EN-DC-159, System Monitoring Program, Revision 01 C

EN-DC-178, System Walkdowns, Revision 01 The inspectors completed one inspection sample.

.4 Operator Workaround Cumulative Effects Review

An operator workaround is defined as a degraded or nonconforming condition that complicates the operation of plant equipment and is compensated for by operator action. During the week of December 18, 2006, the inspectors reviewed the cumulative effect of the existing operator workarounds and contingency plans. The inspectors concentrated on the effect the workarounds have on:

(1) the reliability, availability, and potential for misoperation of any mitigating system;

(2) whether they could increase the frequency of an initiating event; and

(3) their effect on the operation of multiple mitigating systems. In addition, the inspectors reviewed the cumulative effects the operator workarounds have on the ability of the operators to respond in a correct and timely manner to plant transients and accidents. Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one inspection sample.

b. Findings and Observations

There were no findings of significance identified associated with the CRs and programs reviewed.

4OA3 Event Follow-up

Event Notification 43012, Unplanned Isolation of RWCU System Due to Loss of 120 Vac Instrument Power Supply

Introduction:

The inspectors identified a self-revealing NCV of TS 5.4.1.a for the failure of operators to follow Procedure SOP-0048, 120 Vac System, Revision 303. Due to ineffective self-and peer-checking a procedure step was missed, resulting in a loss of power to safety-related instrument power Panel VBS-PNL01A. As a result, the RWCU system and the suppression pool cooling and cleanup systems isolated. This event was documented in the licensees 10 CFR 50.72(a)(1) 60-day Event Notification 43012 dated November 28, 2006.

Description:

On September 29, 2006, an operator trainee was performing Procedure SOP-0048, 120 Vac System, Revision 303, Section 5.9, Transfer from ENB-INV01A (Elgar) to ENB-INV01A1 (SCI) supplying VBS-PNL01A. The trainee was properly marking each procedure step as it was read and discussed with the operator trainer.

When each action was completed, the trainee properly marked the step complete. After the trainee marked and read step 5.9.5.8, the trainer discussed the expected response of the inverter with the trainee and the system engineer, who was also present. Step 5.9.5.8 was marked complete during the discussion. However, the trainee failed to put Inverter ENB-INV01A in manual bypass as required by step 5.9.5.8. When the trainee preformed the next step to open the inverters static switch input breaker, a loss of power from Inverter ENB-INV01A to safety-related instrument power Panel VBS-PNL01A occurred.

The loss of power to Panel VBS-PNL01A caused the isolation valves for the suppression pool cooling and cleanup and RWCU systems to close. Loss of RWCU is of concern because it is the primary means for controlling reactor water chemistry parameters within specifications to protect the fuel cladding barrier. The control room operators responded to the loss of Panel VBS-PNL01A in accordance with Procedure AOP-0042, Loss of Instrument Bus, Revision 25, and restored power to it by restarting Inverter ENB-INV01A1. The RWCU system was unisolated and returned to service.

The inspectors discussed the event with members of the operating shift and the operator trainer and trainee and reviewed the human performance event report and root cause analysis as documented in CR-RBS-2006-03874. The inspectors determined that the failure to use self-and peer-checking led directly to the loss of Panel VBS-PNL01A and isolation of RWCU. The trainee became distracted by the discussion of the inverters response to the actions being performed and failed to realize that the action to close the inverter manual bypass switch had not been performed. In addition, the trainer did not independently verify that the manual bypass switch was in bypass before allowing the trainee to proceed to the next step. Following this event, licensee actions included a focus by operations department personnel on procedure use, attention to detail, and communications and operations supervisors focus on self-and peer-checking during the fourth quarter on 2006.

Analysis:

The performance deficiency associated with this finding involved an operator trainee marking a procedure step prior to completion of the step, as a result, that step was not performed, resulting in loss of supply power to safety-related instrument Panel VBS-PNL01A. The finding was more than minor because it is associated with the barrier integrity cornerstone attribute of configuration control and affects the associated cornerstone objective to provide reasonable assurance the fuel cladding barrier protects the public from radionuclide releases caused by accidents and events. Using the NRC MC 0609, Significance Determination Process, Phase 1 Worksheet, the finding was determined to have very low safety significance because only the fuel cladding barrier was affected. The cause of this finding is related to the crosscutting element of human performance in that operators failed to make proper use of human performance techniques of self-and peer-checking.

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 4.w, requires procedures for safety-related ac electrical distribution systems. Procedure SOP-0048, 120 Vac System, Section 5.9, Transfer from ENB-INV01A (Elgar) to ENB-INV01A1 (SCI) supplying VBS-PNL01A, required that Inverter ENB-INV01A be placed in manual bypass prior to opening the inverters static switch input breaker. Contrary to this, on September 29, 2006, operators failed to place the inverter in manual bypass and the inverter output was lost, resulting in an automatic isolation of the suppression pool cooling and cleanup and RWCU systems. Because the finding is of very low safety significance and has been entered into the licensees CAP as CR-RBS-2006-03874, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy:

NCV 05000458/2006005-04, Failure to follow procedure resulted in loss of power to safety related instrumentation bus and isolation of reactor water cleanup system.

Automatic Scram due to Loss of Feedwater to the Reactor On October 19, 2006, an automatic scram occurred when the main feedwater block valves closed, causing a complete loss of feedwater to the reactor. Following the reactor scram, operators failed to place the reactor mode switch to shutdown. This caused a main steam line isolation and complicated the operators response to the event. The inspectors reviewed the operator actions taken in response to the event and attended the operational safety review committee meeting that reviewed Procedure GOP-0003, Scram Recovery, Revision 17, completed on October 20, 2006, prior to recommending reactor restart.

This event was the subject of an NRC Special Inspection conducted during the week of October 23, 2006. The results of that inspection are documented in NRC Inspection Report 05000458/2006013.

RWCU Pump Coupling Failure

Introduction:

The inspectors identified a self-revealing finding involving the installation of a pump coupling that exceeded vendor shelf-and service-life recommendations. This deficiency resulted in a RWCU Pump A coupling failure on November 28, 2006.

Description:

On November 15, 2006, maintenance technicians replaced the motor-to-pump coupling on RWCU Pump A, using WO 51025634. A review of the work package showed that there was no requirement to verify the age of the coupling and document the vendor date of manufacture shown on the orange polyurethane flexible coupling. On November 28, 2006, the licensee determined that the coupling had severely degraded and was about to fail. In order to secure the pump, RWCU Demineralizer A had to be removed from service. RWCU Pump A was removed from service and the coupling showed a failure of the orange polyurethane flexible joint. It was also determined that the coupling was clearly marked with the manufacture date of the fourth quarter of 1996. The coupling was replaced and the pump and demineralizer were returned to service.

The inspectors reviewed Vendor Manual VTD-R996-0100, Installation, operating and maintenance instructions for Rexnord Omega Couplings, Revision 00, and determined that the expected service life of the flexible coupling was 6 to 8 years after the date of manufacture. This information was not included in WO 51025634. The inspectors also reviewed engineering Standard ME-S-022-R, Replace Centrifugal Pump Couplings with Rubber Disk Couplings, dated June 3, 2006. The engineering standard states that for a properly sized coupling in a mild environment, the coupling is expected to last 6-8 years before having to replace the element. The inspectors noted that this guidance does not refer to after date of manufacture as stated in the vendor manual. Finally, the inspectors reviewed Modification Request 88-0187 to replace couplings on the RWCU pumps, dated May 13, 1988, and Field Change Notice 1 for Modification Request 88-0187, dated December 27, 1990. Neither of these documents described expected service life for the couplings.

The inspectors determined that the failure of the 10-year old flexible coupling 9 days after installation on RWCU Pump A was due to the failure to provide vendor manual instructions in the modification paperwork, allowing the use of these couplings on RWCU pumps and in the routine task work instructions used to generate WO 51025634. Additionally, the inspectors reviewed Engineering Request ER-RB-2003-0176-000, dated March 17, 2003, that approved the use of these couplings on the drywell floor drain pumps. There was no reference to expected service for the couplings, so these pumps may be susceptible to the same mode of failure.

The licensee conducted an apparent cause evaluation and extent of condition review documented in CR-RBS-2006-04488. The licensee determined that these couplings were also used on the drywell and containment equipment drain pumps as well as nine other nonsafety-related pumps throughout the plant. The licensees corrective actions based on that review were to ensure that new shelf life requirements be placed on these couplings, that all couplings installed in the plant be inspected for date of manufacture and replaced as necessary, and that routine maintenance tasks be generated to replace these couplings within their expected service lifetime.

Analysis:

The performance deficiency associated with this finding involved the licensees failure to provide adequate maintenance instructions to ensure that an out-of-date coupling was not installed on RWCU Pump A on November 15, 2006. The coupling failed on November 28, 2006, and RWCU Pump A and RWCU Demineralizer A had to be removed from service. The finding was more than minor because it would become a more significant safety concern if left uncorrected in that the couplings were also used on the drywell floor and equipment drain pumps. If those pumps were to fail, it would require a plant shutdown to make repairs. The finding affected the barrier integrity cornerstone. Using the NRC MC 0609, "Significance Determination Process,"

Phase 1 Worksheet, the finding was determined to have very low safety significance because only the fuel cladding barrier was affected. This issue was entered into the licensee's corrective action program as CR-RBS-2006-04490 and -04517.

Enforcement:

Since the RWCU system is not safety related, no violation of NRC requirements was identified. This finding is identified as FIN 05000458/2006005-05, Newly installed reactor water cleanup pump coupling failed because it was beyond its expected service life time. No violation of NRC requirements were identified.

The inspectors completed three inspection samples.

4OA5 Other Activities

.1 Temporary Instruction 2515/169, Mitigating System Performance Index

Verification, was completed on December 30, 2006. See report Section 4OA1 for details.

.2 Apparent Violation (AV)05000458/2006011-01, Failure to Maintain a Standard

Scheme of Emergency Classification and Action Levels, was closed by letter, dated September 7, 2006. Because the finding was determined to have very low safety significance and has been entered into the licensees corrective action program as CR-RBS-2006-01283, the violation was treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000458/2006011-01, "Failure to Maintain a Standard Scheme of Emergency Classification and Action Levels in Use."

4OA6 Meetings, Including Exit

Exit Meetings On November 2, 2006, the inspector presented the emergency plan change review inspection results to Mr. J. Leavines, Manager, Emergency Planning. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On October 6, 2006, the inspector presented the biennial heat sink performance inspection results to Mr. D. Vinci, General Manager, Plant Operations, and other members of licensee management. Licensee management acknowledged the inspection findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On January 8, 2007, the inspectors presented the integrated baseline inspection results to Mr. D. Vinci, General Manager, Plant Operations, and other members of licensee management. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

L. Ballard, Manager, Quality Programs

M. Davis, Manager, Radiation Protection

T. Burnett, Acting Manager, Training and Development

C. Bush, Manager, Outage

J. Clark, Assistant Operations Manager - Training

M. Feltner, Manager, Planning and Scheduling/Outage

C. Forpahl, Manager, Corrective Action Program

T. Gates, Manager, Equipment Reliability

H. Goodman, Director, Engineering

B. Heath, Acting Superintendent, Chemistry

K. Higginbotham, Assistant Operations Manager - Shift

B. Houston, Manager, Plant Maintenance

A. James, Superintendent, Plant Security

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, Operations

P. Russell, Manager, System Engineering

J. Schlesinger, Supervisor, Design Engineering

D. Steinsiek, Supervisor, Engineering Programs & Components

J. Venable, Site Vice President

D. Vinci, General Manager - Plant Operations

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000458/2006005-01 NCV Failure to identify a degraded condition of steam leak detection system Transmitter E31-N084B

05000458/2006005-02 NCV Inadequate work instructions result in isolation of annulus pressure control system and automatic start of the Division II standby gas treatment system

05000458/2006005-03 NCV Licensee failed to perform a radiological survey in off-gas sample room after radiological conditions had changed

05000458/2006005-04 NCV Failure to follow procedure resulted in loss of power to safety-related instrumentation bus and isolation of reactor water cleanup system

05000458/2006005-05 FIN Newly installed reactor water cleanup pump coupling failed because it was beyond its expected service lifetime

Closed

05000458/2006011-01 AV Failure to Maintain a Standard Scheme of Emergency Classification and Action Levels in Use