IR 05000458/2008002

IR 05000458-08-002, on January 1 Through March 29, 2008, River Bend Station, NRC Integrated Inspection Report

ML081300838
Person / Time
Site:	River Bend
Issue date:	05/09/2008
From:	Rick Deese NRC/RGN-IV/DRP/RPB-C
To:	Mike Perito Entergy Operations
References
IR-08-002
Download: ML081300838 (41)

Text

UNITED STATES NUC LE AR RE G UL AT O RY C O M M I S S I O N R E GI ON I V 612 EAST LAMAR BLVD , SU I TE 400 AR LI N GTON , TEXAS 76011-4125 May 9, 2008 Michael Perito Vice President, Operations Entergy Operations, Inc.

River Bend Station 5485 US Highway 61N St. Francisville, LA 70775 Subject: RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT 05000458/2008002

Dear Mr. Perito:

On March 29, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your River Bend Station. The enclosed report documents the inspection results, which were discussed on April 10, 2008, with you and other member 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.

Based on the results of this inspection, two NRC-identified findings and two self-revealing findings of very low safety significance were identified. Three of these findings involved violations of NRC requirements. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of their very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating these issues as noncited violations in accordance with Section VI.A.1 of the NRC Enforcement Policy.

If you contest the subject or severity of any noncited violation in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, TX 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at River Bend Station.

Entergy Operations, Inc. -2-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).

Should you have any questions concerning this inspection, we will be pleased to discuss them with you.

Sincerely,

/RA/

Richard W. Deese, Acting Chief Project Branch C Division of Reactor Projects Docket: 50-458 License: NPF-47

Enclosure:

NRC Inspection Report 05000458/2008002 w/Attachment: Supplemental Information

REGION IV==

Docket: 50-458 License: NPF-47 Report: 05000458/2008002 Licensee: Entergy Operations, Inc.

Facility: River Bend Station Location: 5485 U.S. Highway 61 St. Francisville, LA Dates: January 1 through March 29, 2008 Inspectors: G. Larkin, Senior Resident Inspector, Project Branch C D. Bollock, Project Engineer, Project Branch C R. Kopriva, Senior Reactor Inspector, Engineering Branch 1 G. Guerra, CHP, Health Physicist, Plant Support Branch G. George, Reactor Inspector, Engineering Branch 1 B. Correll, Reactor Inspector, Engineering Branch 2 P. Alter, Senior Training Program Specialist, HRTD Approved By: Richard W. Deese, Acting Chief Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000458/2008002; 01/01/2008 - 03/29/2008; River Bend Station: Postmaintenance

Testing; Identification and Resolution of Problems.

This report covers a 3-month period of routine baseline inspections by resident inspectors and announced baseline inspections by regional engineering and maintenance and radiation protection inspectors. Three 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 4, dated December 2006.

Cornerstone: Initiating Events

Green.

The inspectors identified a noncited violation of Technical Specification 5.4.1.a for an inadequate procedure for securing a reactor feedwater pump. Specifically, the licensee failed to incorporate internal operating experience into the procedure. As a result, a reactor recirculation flow control valve runback resulting from a known reactor vessel water level loop tolerance issue recurred, resulting in an unplanned power reduction. This issue was entered into the licensees corrective action program as Condition Report RBS-2007-4749.

The finding is more than minor since it affects the human performance area of the initiating events cornerstone and affects the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Using the NRC Manual Chapter 0609, Significance Determination Process, Phase 1 worksheet, the finding has very low safety significance since it did not contribute to both the likelihood of a reactor scram and the likelihood that mitigating equipment would not have been available (Section 1R19.1).

Green.

A self-revealing finding was identified for the failure to properly repair condensate Demineralizer 1E tank liner prior to returning it to service. As a result, failure of the liner resulted in approximately 20,000 gallons of radiological contaminated condensate being spilled from the manway flange. Operations lowered reactor power from 90 percent to 82 percent to conserve condensate system inventory. This issue was entered into the licensees corrective action program as Condition Report RBS-2007-5440.

The finding is greater than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown and power operations. Using the NRC Manual Chapter 0609, Significance Determination Process, Phase 1 worksheet, the finding was considered to be a transient initiator contributor which contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available and, therefore, screened to Phase 2. Using the Phase 2 worksheets, the inspectors assumed that successful recovery of the condensate system from the leak was highly likely and determined the finding to be of very low safety significance. This finding has crosscutting aspects associated with human performance in the area of resources in that a complete, accurate, and up-to-date work package was not available to assure nuclear safety H.2(c) (Section 1R19.2).

Cornerstone: Mitigating Systems

Green.

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

Appendix B, Criterion III, "Design Control," for failure to incorporate accurate design information into a calculation to determine emergency diesel generator turbocharger discharge combustion air pipe stresses. This resulted in pipe failure. Specifically, a calculation assumed nonconservative pipe wall thicknesses and process air temperatures, treated pipe end points as rigid anchors and failed to use stress intensification factors. This resulted in low calculated pipe stresses. With appropriately calculated pipe stress values,

Entergy personnel could reasonably have been expected to adequately modify the combustion air piping to preclude subsequent failures. This issue was entered into the licensees corrective action program as Condition Report RBS-2008-2869.

This issue was determined to be more than minor because it affected the mitigating systems cornerstone objective and was similar to Manual Chapter 0612, Appendix E, Example 3.j because the errors were considered more than a minor calculation error in that the deficiency failed to identify the high pipe wall stresses that significantly reduced the overall allowable material strength margin. Later pipe and weld flaws developed at the intercooler adapter and turbocharger end connections that rendered the emergency diesel generator Division 2 inoperable. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, the inspectors determined that the issue was of very low safety significance (Green) because it did not screen as risk significant due to a seismic, flooding, or severe weather initiating event (Section 1R19.3).

Cornerstone: Barrier Integrity

Green.

A self-revealing noncited violation of Technical Specification 5.4.1.a occurred when River Bend Station reactor operators failed to comply with General Operating Procedure GOP 000-1, Plant Start Up. Specifically operators withdrew six control rods two notches past the target out notch position specified in Reactivity Control Plan RCP-15-03. No fuel damage resulted from these errors. This issue was entered into the licensees corrective action program as Condition Report RBS-2008-2174.

This finding was more than minor because the finding affected the barrier integrity cornerstone attributes of configuration control and human performance and adversely impacts the cornerstones objective to provide reasonable assurance that physical design barriers (fuel cladding) protect the public from radio nuclide releases caused by accidents or events. The inspectors completed a Phase 1 significance determination using Manual Chapter 0609 Appendix A,

Significance Determination Process Phase 1 screening worksheet, and determined the finding to be of very low safety significance (Green) because the performance issue only degraded the fuel cladding barrier. This finding had crosscutting aspects associated with human performance in the area of work practices in that the reactor operators failed to use self-check and peer-check during control rod reactivity manipulations (H.4.a) (Section 40A2).

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

The plant began the quarter at 89 percent power coasting down to Refueling Outage 15 which began on January 6, 2008. From January 6, the plant remained at zero percent power until start up on March 1. On March 5, after the station reached approximately 70 percent power, the plant scrammed due to a main turbine electro-hydraulic control speed sensor circuit failure. The plant restarted on March 7 and increased power to approximately 90 percent on March 13 when the station reduced power to approximately 60 percent for a scheduled rod pattern adjustment.

Power was increased to approximately 70 percent while the station made plans for a forced outage on March 20, to replace a severed valve stem on the feedwater first point header discharge isolation Valve FWS-MOV27B. On March 23, the station started up and ascended to 100 percent power on March 27, and stayed at 100 percent power for the remainder of the inspection period except for normally scheduled down power, to approximately 70 percent, for control rod pattern adjustments on March

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Readiness for Impending Adverse Weather Conditions - Severe Thunderstorm Watch Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility on February 26, 2008, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. On February 26, 2008, during a refueling outage, the inspectors walked down the containment and drywell hatches, the temporary diesel power for the spent fuel pool cooling system, in addition to the licensees emergency AC power systems, because their safety-related functions could be affected or required as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate.

During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspector's evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Safety Analysis Report (USAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed a sample of corrective action program (CAP) items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the CAP in accordance with station corrective action procedures.

This inspection constitutes one readiness for impending adverse weather condition sample as defined in Inspection Procedure 71111.01-05.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Division 1 125VDC (ENB)

• Division 1 spent fuel pool cooling (SFC)

• Division 1 4160 V standby switchgear (ENS)

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, USAR, Technical Specification (TS) requirements, Administrative TSs, outstanding work orders (WOs), condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization.

Documents reviewed are listed in the attachment.

These activities constituted three partial system walkdown samples as defined by Inspection Procedure 71111.04-05.

b. Findings

No findings of significance were identified.

.2 Semi-Annual Complete System Walkdown (71111.045)

a. Inspection Scope

On February 15, 2008, the inspectors performed a complete system alignment inspection of the emergency diesel generator (EDG) Division 1 to verify the functional capability of the system. This system was selected because it was considered both safety-significant and risk-significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment lineups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. The documents used for the walkdown and issue review are listed in the attachment.

This activity constitutes one complete system walkdown sample as defined by Inspection Procedure 71111.04-05.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Routine Resident Inspector Tours (71111.05Q)

a. Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• January 9-10, 2008, Fuel Building Southwest Stairwell and Elevation, 148-foot level, Fire Zone FB-1/Z-1

• February 21, 2008, Standby Cooling Tower, 118-foot level, Standby Service Water (SSW) Pump A Room, Fire Area PH-1/Z-1

• February 21, 2008, Standby Cooling Tower, 137-foot level, SSW Pump A Transformer Room, Fire Area PH-1/Z-2

• February 21, 2008, Standby Cooling Tower, 118-foot level, Remote Air Intake, Fire Area PH-3

• February 21, 2008, Standby Cooling Tower, 118-foot level, SSW Pump B Room, Fire Area PH-2/Z-1

• February 22, 2008, Standby Cooling Tower, 137-foot level, SSW Pump B Transformer Room, Fire Area PH-2/Z-2

• February 22, 2008, Diesel Generator Building, 98-foot level, Diesel Generator C Room, Fire Area DG-5/Z-1 The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

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

These activities constituted seven quarterly fire protection inspection samples as defined by Inspection Procedure 71111.05-05.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

From January 30, 2008, to February 6, 2008, the inspectors performed Inspection Procedure 71111.08, Inservice Inspection Activities. Inspection Procedure 71111.08 requires a minimum sample size, for boiling water reactors, of one for Section 02.01.

The inspectors fulfilled the requirements of Inspection Procedure 71111.08.

02.01 Inspection Activities Other Than Steam Generator Tube Inspections, Pressurized Water Reactor Vessel Upper Head Penetration Inspections, Boric Acid Corrosion Control

a. Inspection Scope

This inspection assesses the effectiveness of River Bends program for monitoring degradation of vital system boundaries. The inspection includes a review of the licensees nondestructive examination and welding programs. The inspectors are to verify that inservice inspection and welding activities are performed in accordance with

American Society of Mechanical Engineers (ASME) Code, other regulatory requirements, and licensee commitments.

The inspectors reviewed two volumetric examinations and two surface examinations.

From those four examinations, the inspectors observed two ultrasonic examinations. In addition, the inspectors observed the visual examination of the steam dryer. The inspectors verified that each examiner held qualifications to perform each examination.

Examinations Reviewed Component Description Examination Type Report Number N4B Discharge Nozzle Ultrasonic APR-R14-03 N6C Low Pressure Core Ultrasonic APR-R14-10 Injection SWP-MOV74B, XI- Liquid Penetrant BOP-PT-08-016 FW001 & FW005, Service Water Valve Replacement E12-MOVF094, FW008 Magnetic Particle BOP-MT-08-006

& FW009, Residual Heat Valve Replacement The inspectors reviewed the site procedures to verify that recordable indications were dispositioned in accordance with ASME Code or an NRC approved alternative. During the performance of the inspection activities, no recordable indications were identified or accepted for continued service. Documents reviewed are listed in the attachment.

The inspection procedure requires verification of one to three welds that the welding process and welding examinations were performed in accordance with ASME Code Class 1 or 2 requirements or an NRC approved alternative. The inspectors reviewed two welding activities performed during the outage.

b. Findings

No findings of significance were identified.

02.05 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed 12 CRs which dealt with inservice inspection activities and found that the corrective actions were appropriate. From this review the inspectors concluded that the licensee had an appropriate threshold for entering issues into the CAP and has procedures that direct a root cause evaluation when necessary. The licensee also had an effective program for applying industry operating experience.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

Routine Quarterly Evaluations (71111.12Q)

a. Inspection Scope

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

• 4160 Standby switchgear system (ENS)

• 4160 DC control supply standby switchgear system (ENB)

The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2) or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization.

This inspection constitutes two quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Off-site power distribution circuit, RSS #2 on January 16, 2008

• Severe thunderstorm warning on February 16, 2008 These activities were selected based on their potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

These activities constituted two samples as defined by Inspection Procedure 71111.13-05.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• CR-RBS-2008-1344, incore dry tube spring housing cracks, reviewed on February 9, 2008

• CR-RBS-2008-1581, Division 3 DC swing charger E22-PNLS001 supply breaker, on February 15, 2008

• CR-RBS-2008-1697, fuel assembly NAN692 discoloration, reviewed on February 20, 2008

• CR-RBS-2008-1975, reactor water clean up delta flow transmitter, on February 28, 2008 The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and USAR to the licensees evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations.

This inspection constitutes four samples as defined in Inspection Procedure 71111.15-05.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

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

• WO 00138196, E12-MOV037A Auxiliary Contact is Bad for the Close Circuit, reviewed on February 12, 2008

• WO 51035363, Troubleshoot and Calibrate Reactor Level Instrument Loop C33-LTN004A, reviewed on February 21, 2008

• WO 00139606, C51-K600A - Connector Needs to be Reworked Under Vessel (Source Range Monitor A), reviewed on February 22, 2008

• WO 00131247, Inspect CND-DEMN 1E and CND-DEMIN 1G, reviewed on March 19, 2008

• WO 00125692, Repair Crack in Intake (Turbo Blower Outlet) Pipe, Restore Intermediate Support Saddles Previously Removed

These activities were selected based upon the SSCs ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion), and test documentation was properly evaluated. The inspectors evaluated the activities against TS, the USAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the attachment.

This inspection constitutes five samples as defined in Inspection Procedure 71111.19.

b. Findings

===.1

Introduction.

The inspectors identified a Green noncited violation of Technical===

Specification 5.4.1.a for an inadequate procedure for securing a reactor feedwater pump. As a result, a reactor recirculation flow control valve (FCV) runback occurred when a reactor feedwater pump was secured.

Description.

On October 28, 2007, during planned operations to remove one of three running reactor feedwater pumps from service, an unexpected level dependent recirculation FCV runback occurred at 32 indicated water level when the specified feed pump was secured. Although indicated reactor water level was above that specified for two feed pump operation, 30.8, there was no procedural guidance warning the operators that previously documented and accepted water level calibration tolerances put the indicated water level of 32 in a range where the runback could occur. As a result, the unexpected FCV runback caused reactor power to drop from 75 percent to 63 percent. The inspectors reviewed the CAP for past conditions involving FCV runbacks. Two CRs, CR-RBS-2003-1777 and CR-RBS-2004-2946 described FCV runbacks at levels greater than 30.8", specifically at levels between 32 and 33" reactor water level narrow range.

Analysis.

The inspectors determined that the failure to translate internal operating experience to prevent recurrence of a FCV runback that results in a loss of reactivity control was a performance deficiency. Entergy relied on the skill of the operator to set the proper level to take control of FCV instead of incorporating the reactor water level loop information into procedure. The finding is more than minor since it affects the human performance area of the initiating events cornerstone and affects the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Using the MC 0609, Significance Determination Process, Phase 1 worksheet, the finding has very low safety significance since it did not

contribute to both the likelihood of a reactor scram and the likelihood that mitigating equipment would not have been available.

Enforcement.

Technical Specification 5.4.1.a requires that written procedures shall be established covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Section 4.o calls for instructions for operation of the feedwater system. Procedure SOP-0009, Reactor Feedwater System, was an implementing procedure to meet this requirement. Contrary to the above, after FCV runbacks in 2003 and 2004 until October 28, 2007, the licensee failed to ensure Procedure SOP-0009 was adequate as a written instruction for operation of the feedwater system. Because this finding is of very low safety significance and has been entered into the CAP as CR-RBS-2007-4749, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:

NCV 05000458/2008002-01, Internal Operating Experience Not Used to Prevent Recurrence of Reactor Recirculation FCV Runbacks.

===.2

Introduction.

A self-revealing Green finding was identified for the failure to properly===

repair condensate Demineralizer 1E tank liner prior to returning it to service. As a result, failure of the liner resulted in approximately 20,000 gallons of radiological contaminated condensate being spilled from the manway flange. Operations lowered reactor power from 90 percent to 82 percent to conserve condensate system inventory.

Description.

On December 8, 2007, the condensate Demineralizer 1E manway flange liner failed due to a degraded tank liner. Operations lowered reactor power from 90 percent to 82 percent to conserve condensate system inventory. The condensate demineralizers are carbon steel vessels with a 3/16 thick rubber lining. The lining is necessary to protect the vessel from the corrosive effects of resin. Per industry experience, the life of the rubber lining is between fifteen and twenty five years depending upon its storage, inservice and maintenance history. RBSs demineralizers were 29 years old. Cracking issues began in 1996, the most common failure mode occurred when the rubber lining became brittle. The cracking usually began at the sight glass or manway flanges. RBS also routinely opened the manway and sight glass flanges to flush out the depleted residual tank resin left behind from resin transfer.

Disassembling flanges was not a common industry practice following resin transfer and added stress to the liner material at the flange. To repair the damaged linings, Entergy developed various permanent and temporary repair methods. On November 23, 2007, Entergy inspected the condensate Demineralizer 1E manway gasket and rubber coating and found cracks in the rubber lining, up to 1/8 wide, covering the entire manway flange face. Contrary to the vendors recommendations, a temporary repair method was selected using Permatex Form-A Gasket to fill in the cracks and smooth the damaged manway rubber liner for the flange gasket to lay flat. This temporary fix should only be performed on minor hairline cracks where the base metal does not show. However, the work procedure contained only vague repair instructions with no repair method described or reference to any applicable engineering documents. Through the years, maintenance had become desensitized to the appearance of liner cracking. When the technician notified the supervisor of the liner cracking, the response was to use Permatex without fully understanding the extent of the degradation.

Analysis.

The inspectors determined that the failure to properly repair condensate Demineralier 1E prior to returning it to service was a performance deficiency.

Specifically, the damaged rubber liner was not permanently replaced or effectively repaired with an approved method. The finding is greater than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown and power operations.

Using the NRC Manual Chapter 0609, Significance Determination Process, Phase 1 worksheets, the finding was determined to be a transient initiator contributor which contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment would not be available and, therefore, screened to Phase 2. Using Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations, of Manual Chapter 0609, the inspectors assumed that successful recovery of the condensate system from the leak was highly likely and determined the finding to be of very low safety significance. This finding had crosscutting aspects associated with human performance in the area of resources in that a complete, accurate, and up-to-date work package was not available to assure nuclear safety H.2(c).

Enforcement.

The inspectors determined that no violations of NRC requirements occurred for the failure to properly repair condensate Demineralizer 1E tank liner prior to returning it to service. This determination was based on the fact that the condensate demineralizer is not a safety-related system, structure or component. The licensee entered this into the CAP as CR-RBS-2007-5440. This finding is identified as Finding FIN 05000458/2008002-02, Condensate Demineralizer Tank Liner Failure.

===.3

Introduction.

The inspectors identified a Green noncited violation (NCV) of Title 10 CFR===

Part 50, Appendix B, Criterion III, "Design Control," for failure to incorporate accurate design information into a calculation to determine EDG turbocharger discharge combustion air pipe stresses. This resulted in pipe failure.

Description.

On October 9, 2007, during a 24-hour surveillance test run of EDG Division 2, Entergy identified a through wall crack next to the fillet weld attaching a nonstandard slip-on flange to the turbocharger combustion air discharge piping. The turbocharger combustion air outlet is a 12 diameter pipe that expands to 14 and is welded at the other end to the intercooler inlet adaptor.

The EDG Division 2 intercooler inlet adapter plate has a history of failed welds (March and May 1989, August 1990, November 1990, August 1997, October 1998, and December 2001). In October 1991, in an effort to understand the failure mechanisms, Entergy developed Calculation G13.18.10.2-68, Turbocharger Discharge Piping -

Intercooler Nozzle Weld Size. The inspectors noted several weaknesses in G13.18.10.2-68. For example the calculation assumed: 1) a 0.375 wall thickness for the entire pipe length even though the 12 diameter pipe was 0.220 thick and the 14 diameter pipe was 0.438 thick; 2) no stress intensification factors were used to account for stress risers in fillet welds or for the flanges and reducer fabricated from plate instead of standard design; 3) a nonconservative process air temperature (225 degrees vice 300 degrees); and 4) rigidly anchored pipe ends even though there is substantial vibration at both ends, most significantly at the turbocharger end.

Following the December 2001 intercooler weld failure, Entergy concluded in CR-RBS-2001-1676 that the root cause of the repeated cracks on the intercooler adapter was the failure to consider end plate stresses due to flexure under vibratory motion. However, Entergy did not re-evaluate the turbocharger end connection for fatigue failure under this mechanism even though the pipe wall is only half as thick and has a much larger vibration signature than the intercooler connection. Until the end of 2007, Entergy continued to use G13.18.10.2-68 as an engineering basis for making decisions concerning modification and maintenance of the combustion air piping. Had the root cause of CR-RBS- 2001-1676 been expanded to consider vibratory motion effects on the entire length of pipe and G13.18.10.2-68 corrected as stated above, Entergy could reasonably have been expected to adequately modify the combustion air piping to preclude subsequent failures.

Analysis.

The inspectors determined that the failure to include proper design basis information in the calculation of EDG turbocharger combustion air discharge pipe stresses was a performance deficiency. This issue was determined to be more than minor because it affected the mitigating systems cornerstone objective and was similar to MC 0612, Appendix E, example 3.j because the errors were considered more than a minor calculation error in that the deficiency failed to identify the high pipe wall stresses that significantly reduced the overall allowable material strength margin. Later pipe and weld flaws developed at the intercooler adapter and turbocharger end connections that rendered the EDG Division 2 inoperable. Using the MC 0609, "Significance Determination Process," Phase 1 worksheet, the inspectors determined that the issue was of very low safety significance (Green) because it did not screen as risk significant due to a seismic, flooding, or severe weather initiating event.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion III, "Design Control," states that measures shall also be established for the selection and review for suitability of application of materials, parts, equipment and processes that are essential to the safety-related functions of the structures, systems and components. Contrary to this requirement, the licensee failed to adequately consider the design input values to calculate the suitability of application of the EDG turbocharger combustion air pipe.

Because the finding is of very low safety significance and has been entered into the CAP as CR-RBS-2008-2869, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000458/2008002-03, Improper Design Control for Evaluating Emergency Diesel Generator Turbocharger Combustion Air Pipe Stresses."

1R20 Refueling and Other Outage Activities

Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan and contingency plans for Refueling Outage 14, conducted January 6 to March 4, 2008, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured

maintenance of defense-in-depth. During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

• periodically attended outage control center meetings to assess licensees priorities and plans

• periodically reviewed shutdown operations protection plan risk assessment

• walked down alternate power supply for fuel pool cooling pumps during full core offload

• walked down circulating water flume temporary blowdown system

• reviewed licensees response to two similar fuel handling mishaps

• outage risk assessment team 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

• 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 2 to Division 1 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 This inspection constitutes one refueling outage sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

Routine Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• STP-390-0602, Division II Emergency Core Cooling System Test, Revision 26, reviewed on January 15 and 16, 2008

• STP-305-1604, ENB-CHGR1B Load Test, Revision 301, performed on January 16, 2008

• STP-305-1701, ENB-BAT01B Performance Discharge Test, Revision 23, performed on January 17, 2008

• STP-309-0201, Division 1 Diesel Generator Operability Test, Revision 32, performed on March 13, 2008 (inservice test surveillance)

The inspectors observed in-plant activities and reviewed procedures and associated records to determine whether: any preconditioning occurred; effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; plant equipment calibration was correct, accurate, and properly documented; as left setpoints were within required ranges; the calibration frequency was in accordance with TS, the USAR, procedures, and applicable commitments; measuring and test equipment calibration was current; test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied; test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used; test data and results were accurate, complete within limits, and valid; test equipment was removed after testing; where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable; where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure; where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished; prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test; equipment was returned to a position or status required to support the performance of the safety functions; and all problems identified during the testing were appropriately documented and dispositioned in the CAP. Documents reviewed are listed in the attachment.

This inspection constitutes four routine surveillance testing samples as defined in Inspection Procedure 71111.22.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary modification:

• Modification EC-6355 and EC-6356, installs a bias in the reactor water clean-up (RWCU) differential flow loop to ensure RWCU isolates prior to system leakage reaching its TS limit, reviewed on March 5, 2008 The inspectors compared the temporary configuration changes and associated 10 CFR 50.59 screening and evaluation information against the design basis, the USAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors also compared the licensees information to operating experience information to ensure that lessons learned from other utilities had been incorporated into the licensees decision to implement the temporary modification. The inspectors, as applicable, performed field verifications to ensure that the modifications were installed as directed; the modifications operated as expected; modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. Lastly, the inspectors discussed the temporary modification with operations, engineering, and training personnel to ensure that the individuals were aware of how extended operation with the temporary modification in place could impact overall plant performance. Documents reviewed are listed in the attachment.

This inspection constitutes one sample as defined in Inspection Procedure 71111.23-05.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess the licensees performance in implementing physical and administrative controls for airborne radioactivity areas, radiation areas, high radiation areas, and worker adherence to these controls. The inspectors used the requirements in 10 CFR Part 20, the TSs, and the licensees procedures required by TSs as criteria for determining compliance. During the inspection, the inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. Documents reviewed by the inspectors are listed in the attachment.

The inspectors performed independent radiation dose rate measurements and reviewed the following items:

• Performance indicator events and associated documentation packages reported by the licensee in the occupational radiation safety cornerstone

• Controls (surveys, posting, and barricades) of radiation, high radiation, or airborne radioactivity areas

• Radiation work permits, procedures, engineering controls, and air sampler locations

• Conformity of electronic personal dosimeter alarm set points with survey indications 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 radioactivity areas

• Self-assessments, audits, licensee event reports, and special reports related to the access control program since the last inspection

• Corrective action documents related to access controls

• Licensee actions in cases of repetitive deficiencies or significant individual deficiencies

• Radiation work permit briefings and worker instructions

• Adequacy of radiological controls, such as required surveys, radiation protection job coverage, and contamination control during job performance

• Dosimetry placement in high radiation work areas with significant dose rate gradients

• Changes in licensee procedural controls of high dose rate - high radiation areas and very high radiation areas

• Controls for special areas that have the potential to become very high radiation areas during certain plant operations

• Posting and locking of entrances to all accessible high dose rate - high radiation areas and very high radiation areas

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements The inspector completed 19 of the required 21 samples.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed licensee performance with respect to maintaining individual and collective radiation exposures as low as reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR Part 20 and the licensees procedures required by TSs as criteria for determining compliance. Documents review by the inspectors are listed in the attachment. The inspectors interviewed licensee personnel and reviewed:

• Site-specific ALARA procedures

• Three work activities of highest exposure significance

• ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements

• Integration of ALARA requirements into work procedure and radiation work permit documents

• Shielding requests and dose/benefit analyses

• Dose rate reduction activities in work planning

• Use of engineering controls to achieve dose reductions and dose reduction benefits afforded by shielding

• Workers use of the low dose waiting areas

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

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas The inspector completed 5 of the required 15 samples and 5 of the optional samples.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered Into the CAP

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

This assessment was accomplished by reviewing CR and work orders, 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.

.2 Selected Issue Followup Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the two issues listed below 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.

• February 26, 2008, Reactor vessel level drain down during integrated leak rate testing

• March 8, 2008, Mispositioned control rods during reactor startup

Documents reviewed by the inspectors are listed in the attachment.

The above constitutes completion of two in-depth problem identification and resolution samples.

b. Findings

Introduction.

A Green self-revealing NCV of TS 5.4.1.a occurred when RBS reactor operators failed to comply with General Operating Procedure GOP 000-1, Plant Start Up. Specifically operators withdrew six control rods two notches past the target out notch position specified in Reactivity Control Plan RCP-15-03. No fuel damage resulted from these errors.

Description.

On March 8, 2008, the reactor was critical at 25 percent power. Reactor operators were withdrawing control rods to increase reactor power. Contrary to Reactivity Control Plan RCP-15-03 and General Operating Procedure GOP 000-1, Plant Start Up, Step G.2, reactor operators withdrew six sequential control rods two notches past target out notch Position 20 to notch Position 24. An incorrect target out position was stated and repeated back for six consecutive control rod manipulations because the dedicated reactor operator at-the-controls failed to self-check and the dedicated peer-check reactor operator failed to peer-check. In addition, the target out notch position remained incorrect for six consecutive control rod manipulations because the dedicated senior reactor operator failed to enforce Entergys human performance standards of self-check and peer-check. The operators received a rod control limiter rod block and alarm when each of the six control rods reached notch Position 24 but because they did not know that the target out notch position was actually notch Position 20, they failed to recognize the alarm as unexpected. The dedicated peercheck reactor operator identified that the reactor operator at-the-controls had stated an incorrect target out notch position on the seventh control rod selected. The operator at-the-controls halted withdrawal of the seventh rod at notch Position 18. A review of previous rod manipulations revealed the six consecutive withdrawal errors. Operations management relieved from duty the reactor operator at the controls, the peer-check reactor operator and the senior reactor operator dedicated to manage reactivity manipulations. These six rod withdrawal errors resulted in no fuel damage, however RBS reactor engineering has determined that at a different time in core life and at higher power levels errors such as these could damage fuel.

The inspectors determined that the finding was self-revealing because an unexpected rod block and alarm revealed each of the six control rod withdrawal errors. Poor implementation of RBS human performance standards prevented the operators from recognizing these six self-revealing events.

Analysis.

The inspectors determined that a performance deficiency existed when the licensee failed to properly implement a reactor plant startup procedure which resulted in the inadvertent misalignment of six reactor control rods. This finding was more than minor because the finding affected the barrier integrity cornerstone attributes of configuration control and human performance and adversely impacts the cornerstones objective to provide reasonable assurance that physical design barriers (fuel cladding)protect the public from radio nuclide releases caused by accidents or events. The

inspectors completed a Phase 1 significance determination using MC 0609 Appendix A, Significance Determination Process Phase 1 screening worksheet, and determined the finding to be of very low safety significance (Green) because the performance issue only degraded the fuel cladding barrier. This finding had crosscutting aspects associated with human performance in the area of work practices in that the reactor operators failed to use self-check and peer-check during control rod reactivity manipulations (H.4.a).

Enforcement.

Technical Specification 5.4.1.a requires written procedures be established, implemented, and maintained covering the activities specified in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Item 2.b, requires procedures for control of nuclear power plant startup evolutions. General Operating Procedure GOP 000-1, Plant Start Up, Step G.2, requires a reactor engineering rod withdrawal sequence to be followed in order to maintain proper rod pattern control. Contrary to the above, on March 8, 2008, RBS reactor operators did not follow the prescribed reactor engineering rod withdrawal sequence in Reactivity Control Plan RCP-15-03 for the plant startup and withdrew six control rods two notches past the target out notch position specified resulting in an improper rod pattern. Because this violation is of very low safety significance and has been entered into the licensee's CAP as CR-RBS-2008-2174, it is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000458/2008002-04, Failure to Follow Reactor Startup Procedure Results in Six Control Rod Withdrawal Errors.

.3 Occupational Radiation Safety

a. Inspection Scope

The inspectors evaluated the effectiveness of the licensees problem identification and resolution 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 Observations

No findings of significance were identified.

4OA3 Event Followup

.1 Inadvertent Initiation of Division 1 SSW

a. Inspection Scope

On January 8, 2008, an inadvertent initiation of Division 1 SSW occurred when a technician lifted a lead from a logic system neutral bus de-energizing the automatic start logic for Division 1 SSW. Division 1 SSW responded as expected and the operators responded as required by Procedure AOP-0053, Initiation of Standby Service Water with Normal Service Water Running, Revision 10. The inspectors reviewed the procedure to insure that the necessary response actions were performed and that the

Division 1 SSW system was properly secured and the normal service water lineup was restored. The inspectors noted that during the event the Division III SSW Pump 3C also automatically started due to service water system low pressure while the Division I SSW system valves repositioned in response to automatic initiation signal. The inspectors questioned this response and will evaluate the licensees response as documented in CR-RBS-2008-00130.

b. Findings

No findings of significance were identified.

.2 Unit Transient - March 5, 2008

a. Inspection Scope

On March 5, 2008, the inspectors responded to an unplanned automatic reactor scam.

The station investigation determined that the cause of the event was an equipment malfunction in the main turbine electro-hydraulic control speed sensor circuit. This failure caused the main turbine control valve to close and had the effect of causing the reactor steam pressure to exceed the trip set point for the reactor protection system which initiates the reactor scram signal. The inspectors discussed the event with licensee management, engineering, operations, and maintenance personnel to understand the conditions leading to the speed sensor circuit failure and the subsequent equipment actuations. The inspectors also reviewed the event for reportability in accordance with NUREG 1022, Event Reporting Guidelines.

b. Findings

No findings of significance were identified.

.3 (Closed) Licensee Event Report (LER) 05000458/2007-002-00, Unplanned Manual

Reactor Scram Due to Loss of Cooling on No. 2 Main Transformer On May 4, 2007, an unplanned manual reactor scram was initiated following the loss of cooling on the No.2 main transformer. Reactor power at the time of the scram was approximately 67 percent. The plant responded as expected and no emergency coolant injection system actuation was required. The loss of cooling to the transformer resulted from an electrical fault in the cooling system control cabinet caused by rainwater intrusion. The cabinet was repaired and sealed, and preventive maintenance procedures were enhanced to prevent recurrence. The licensee tracked this issue under CR-RBS-2007-01802. The inspectors have reviewed the licensees actions and have no significant findings. This LER is closed.

.4 (Closed) LER 05000458/2008-001-00, Automatic Actuation of Standby Service Water

System Due to Inadequate Work Instructions On January 8, 2008, an unplanned automatic actuation of the Division 1 and 3 SSW systems occurred during maintenance. The plant was shutdown for a refueling outage at the time of the event. The maintenance being performed at the time involved the

replacement of a power supply in the Division 1 containment penetration valve leakage control system. When lifting a neutral ground lead per procedure, power was interrupted in other parts of the connected circuitry which was not anticipated. The loss of power caused an invalid initiation signal to the Division 1 SSW system resulting in the automatic start of the SSW Pump A, and a subsequent initiation signal to the SSW Pump C due to normal system configuration and response to SSW Pump A starting.

Investigation of this event found that relevant technical information had been inadvertently omitted from the work package. In previous periodic replacement of the same power supply it was identified that the neutral lead on the power supply was "daisy-chained" to other power supplies not related to the work being performed. This was overlooked in preparing the work package used in the case of this event. This inadequate work instruction constitutes a minor violation of TS 5.4.1 and is not subject to enforcement action in accordance with Section IV of the NRC's Enforcement Policy. The licensee documented this event in CR-RBS-2008-00187. This LER is closed.

4OA6 Meetings, Including Exit

Exit Meetings On January 31, 2008, the inspectors presented the occupational radiation safety inspection results to you and other members of your staff who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

On February 6, 2008, the inspectors presented the inservice inspection activities inspection results to you and other members of your staff who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

On April 10, 2008, the inspectors presented the integrated baseline inspection results to you and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, for being dispositioned as an NCV.

• TS 5.4.1.a requires that maintenance activities be performed in accordance with documented instructions. Procedure FHP-0003, Refuel Platform Operation, requires the grapple control operator to appropriately exercise the grapple controls to raise and lower fuel. On January 13, 2008 and January 14, 2008, while moving irradiated fuel within the reactor vessel, the refueling bridge driver inadvertently lowered a grappled fuel bundle that contacted the top of the reactor core. There was no radiological or industrial consequence as a result of this event. The root cause evaluation determined that the primary factors in both events was the failure to appropriately use the human performance tools including self-checking, peer-

checking, and three leg communications. This event is described in the licensees CAP as CR-RBS-2008-0326. This finding was more than minor because the finding is related to the human performance attribute of the barrier integrity cornerstone and negatively impacts the cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding) protect the public from radio nuclide releases caused by accidents or events. The inspectors completed a Phase 1 significance determination using IMC 0609 Appendix A, Significance Determination Process Phase 1 Screening Worksheet, and determined the finding to be of very low safety significance (Green) because the performance issue only degraded the fuel cladding barrier and its associated cornerstone.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Baccus, Supervisor, Radiation Protection

M. Briley, Sr. Lead Technical Specialist, Code Programs

M. Chase, Manager, Training and Development

J. Clark, Assistant Operations Manager - Training

C. Forpahl, Manager, Engineering Programs & Components

B. Heath, Superintendent, Chemistry

D. Hebert, Technical Specialist, Code Programs

K. Higginbotham, Assistant Operations Manager - Shift

W. Holland, Supervisor, Radiation Protection

B. Houston, Manager, Radiation Protection

K. Huffstatler, Technical Specialist, Licensing

A. James, Manager, Security

J. Leavines, Manager, Emergency Preparedness

J. Loque, Manager, Plant Maintenance

D. Lorfing, Manager, Licensing

J. Maher, Superintendent, Reactor Engineering

W. Mashburn, Manager, Design Engineering

B. Matherne, Manager, Planning and Scheduling/Outage

R. McAdams, manager, System Engineering

J. McElwain, Manager, Human Resources

J. Miller, Manager, Operations

E. Olson, General Manager - Plant Operations

E. Roan, Manager, Outage

J. Roberts, Director, Nuclear Safety Assurance

P. Russell, Manager, Corrective Action Program

R. Seeman, Sr. Engineer, Engineering

T. Tankersley, Manager, Quality Assurance

J. Venable, Senior Site Vice President

D. Wiles, Director, Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Open and

Closed

05000458/2008002-01 NCV Internal Operating Experience Not Used to Prevent Recurrence of Reactor Recirculation FCV Runbacks Insert Description (Section 1R19.1)

05000458/2008002-02 FIN Condensate Demineralizer Tank Liner Failure (Section 1R19.2)

Attachment

05000458/2008002-03 NCV Improper Design Control for Evaluating Emergency Diesel Generator Turbocharger Combustion Air Pipe Stresses (Section 1R19.3)

05000458/2008002-04 NCV Failure to Follow Reactor Startup Procedure Results in Six Control Rod Withdrawal Errors (Section 4OA2)

Closed

50-458/2007-002-00 LER Unplanned Manual Reactor Scram Due to Loss of Cooling on No. 2 Main Transformer (Section 4OA3.3)

50-458/2008-001-00 LER Automatic Actuation of Standby Service Water system Due to Inadequate Work Instructions (Section 4OA3.4)