Text

IR 05000458-05-005; on 10/01/2005 - 12/31/2005; River Bend Station; Licensed Operator Requalification, Operator Performance During Nonroutine Plant Evolutions, Permanent Plant Modifications
	ML060450209
Person / Time
Site:	River Bend
Issue date:	02/13/2006
From:	Kennedy K; NRC/RGN-IV/DRP/RPB-C
To:	Hinnenkamp P; Entergy Operations
References
	IR-05-005
	Download: ML060450209 (41)
	v • d • e

February 13, 2006

Paul D. Hinnenkamp

Vice President - Operations

Entergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, Louisiana 70775

SUBJECT:

RIVER BEND STATION - NRC INTEGRATED INSPECTION

REPORT 05000458/2005005

Dear Mr. Hinnenkamp:

On December 31, 2005, 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 with you and other members of your staff on

January 4, 2006.

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 one self-revealing

finding were evaluated under the risk significance determination process as having very low

safety significance (Green). The NRC has also determined that violations are associated with

these findings. However, because these violations were of very low safety significance and

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

noncited violations, consistent with Section VI.A.1 of the NRCs Enforcement Policy. If you

contest the violations or the significance of the violations, 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

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.

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

with you.

Sincerely,

/RA/

Kriss M. Kennedy, Chief

Project Branch C

Division of Reactor Projects

Docket: 50-458

License: NPF-47

Enclosures:

NRC Inspection Report 05000458/2005005

w/Attachment: Supplemental Information

cc w/enclosure:

Senior Vice President and

Chief Operating Officer

Entergy Operations, Inc.

P.O. Box 31995

Jackson, MS 39286-1995

Vice President

Operations Support

Entergy Operations, Inc.

P.O. Box 31995

Jackson, MS 39286-1995

General Manager

Plant Operations

Entergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA 70775

Director - Nuclear Safety

Entergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA 70775

Entergy Operations, Inc.

-3-

Wise, Carter, Child & Caraway

P.O. Box 651

Jackson, MS 39205

Winston & Strawn LLP

1700 K Street, N.W.

Washington, DC 20006-3817

Manager - Licensing

Entergy Operations, Inc.

River Bend Station

5485 US Highway 61N

St. Francisville, LA 70775

The Honorable Charles C. Foti, Jr.

Attorney General

Department of Justice

State of Louisiana

P.O. Box 94005

Baton Rouge, LA 70804-9005

H. Anne Plettinger

3456 Villa Rose Drive

Baton Rouge, LA 70806

Burt Babers, President

West Feliciana Parish Police Jury

P.O. Box 1921

St. Francisville, LA 70775

Michael E. Henry, State Liaison Officer

Department of Environmental Quality

Permits Division

P.O. Box 4313

Baton Rouge, LA 70821-4313

Brian Almon

Public Utility Commission

William B. Travis Building

P.O. Box 13326

1701 North Congress Avenue

Austin, TX 78711-3326

Entergy Operations, Inc.

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Chairperson

Denton Field Office

Chemical and Nuclear Preparedness

and Protection Division

Office of Infrastructure Protection

Preparedness Directorate

Dept. of Homeland Security

800 North Loop 288

Federal Regional Center

Denton, TX 76201-3698

Entergy Operations, Inc.

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Electronic distribution by RIV:

Regional Administrator (BSM1)

DRP Director (ATH)

DRS Director (DDC)

DRS Deputy Director (RJC1)

Senior Resident Inspector (PJA)

Branch Chief, DRP/C (KMK)

Senior Project Engineer, DRP/C (WCW)

Team Leader, DRP/TSS (RLN1)

RITS Coordinator (KEG)

DRS STA (DAP)

J. Dixon-Herrity, OEDO RIV Coordinator (JLD)

ROPreports

RBS Site Secretary (LGD)

W. A. Maier, RSLO (WAM)

SUNSI Review Completed: _kmk_ ADAMS: : Yes

G No Initials: __kmk__

Publicly Available G Non-Publicly Available G Sensitive

Non-Sensitive

R:\\_REACTORS\\_RB\\2005\\RB2005-05RP-PJA.wpd

RIV:SRI:DRP/C

RI:DRP/C

C:DRS/OB

C:DRS/EB1

C:DRS/PSB

PJAlter

MOMiller

ATGody

JClark

MPShannon

T - KMKennedy

E - KMKennedy /RA/

/RA/

2/ /06

C:DRS/EB2

C:DRP/C

LJSmith

KMKennedy

GDReplogle for

/RA/

2/13/06

OFFICIAL RECORD COPY

T=Telephone E=E-mail F=Fax

Enclosure

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U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket:

50-458

License:

NPF-47

Report:

05000458/2005005

Licensee:

Entergy Operations, Inc.

Facility:

River Bend Station

Location:

5485 U.S. Highway 61

St. Francisville, Louisiana

Dates:

October 1 through December 31, 2005

Inspectors:

P. Alter, Senior Resident Inspector, Project Branch C

M. Miller, Resident Inspector, Project Branch C

J. Keeton, Consultant, Region IV

P. Elkmann, Emergency Preparedness Inspector, Operations Branch

G. Johnston, Senior Operations Engineer, Operations Branch

L. Ricketson, Senior Health Physicist, Plant Support Branch

Approved By:

Kriss M. Kennedy, Chief

Project Branch C

Division of Reactor Projects

Enclosure

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TABLE OF CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

REPORT DETAILS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R01

Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

1R04

Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R05

Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R11

Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

1R13

Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 10

1R14

Operator Performance During Non-routine Plant Evolutions . . . . . . . . . . . . . . 11

1R15

Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

1R16

Operator Work-Arounds

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1R17

Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1R19

Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

1R22

Surveillance Testing

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1R23

Temporary Plant Modifications

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

1EP2

Alert and Notification System Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

1EP3

Emergency Response Organization Augmentation . . . . . . . . . . . . . . . . . . . . . 20

1EP5

Correction of Emergency Preparedness Weaknesses and Deficiencies . . . . . 20

1EP6

Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2OS2

ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4OA1

Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4OA2

Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4OA3

Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

4OA6

Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

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

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

LIST OF DOCUMENTS REVIEWED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

LIST OF ACRONYMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8

Enclosure

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SUMMARY OF FINDINGS

IR 05000458/2005005; 10/01/2005 - 12/31/2005; River Bend Station; Licensed Operator

Requalification, Operator Performance During Nonroutine Plant Evolutions, Permanent Plant

Modifications.

The report covered a 3-month period of routine baseline inspections by resident inspectors and

announced baseline inspections by regional emergency planning, operations, and radiation

protection inspectors. Three Green noncited violations were identified. The significance of

most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual

Chapter 0609, Significance Determination Process. Findings for which the significance

determination process does not apply may be Green or be assigned a severity level after NRC

management review. 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.

A.

NRC-Identified and Self-Revealing Findings

Cornerstone: Initiating Events

Green. The NRC identified a noncited violation of Technical Specification 3.4.1.A for the

licensees failure to shut down one reactor recirculation loop within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of

determining that jet pump loop flow mismatch was greater than 5 percent while

operating at greater than 70 percent of rated core flow. On October 31, 2005, the

Reactor Recirculation Flow Control Valve B hydraulic power unit tripped because of a

blown control power fuse, causing Flow Control Valve B to drift open. Operators

throttled closed Flow Control Valve A to maintain reactor power at 100 percent, resulting

in a jet pump loop flow mismatch of approximately 8.2 percent. The flow mismatch

existed for 4.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months . The licensee entered this into their corrective action program as

Condition Report CR-RBS-2006-00274.

The finding was more than minor because, if left uncorrected, it would become a more

significant safety concern. Matched recirculation loop flows is an assumption used in

the accident analysis for a loss of coolant accident resulting from a loop break. A flow

mismatch could result in core response that is more severe than assumed in the

accident analysis. The significance of this finding could not be evaluated using

MC 0609, Significance Determination Process. Based on management review, the

finding was determined to be of very low safety significance based on the short duration

of the flow mismatch, 4.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months , and the low likelihood of a loss of coolant accident

during that time. The cause of this finding is related to the crosscutting element of

human performance in that operators failed to implement Technical Specification

requirements (Section 1R14).

Cornerstone: Mitigating Systems

Green. A self-revealing noncited violation of 10 CFR Part 50, Appendix B, Criterion III,

Design Control, was identified for the licensees failure to address the worst case

conditions in the sizing calculation for the reactor core isolation cooling turbine exhaust

Enclosure

-4-

line vacuum breaker system as part of a plant modification to remove the internals of the

reactor core isolation cooling turbine exhaust line check valve. As a result, on

December 10, 2004, when the reactor core isolation cooling system was started and

subsequently shutdown on high reactor water level following a scram and loss of

feedwater, the turbine exhaust line filled with water from the suppression pool, causing

the operators to consider the system unavailable and complicating their response to the

event. The licensee entered this finding into their corrective action program as CR-

RBS-2005-00724 and reinstalled the turbine exhaust line check valve internals in

February 2005.

The finding was more than minor because it was associated with the Mitigating Systems

cornerstone attribute of Design Control and affected the cornerstone objective to ensure

the availability and reliability of the reactor core isolation cooling system, a system that

responds to initiating events (loss of feedwater and station blackout), to prevent

undesirable consequences. Using Manual Chapter 0609, Significance Determination

Process, Phase 1 Worksheet, the finding was determined to have very low safety

significance because it represented a design deficiency that did not result in a loss of

system function (Section 1R17).

Cornerstone: Emergency Preparedness

Green. The NRC identified a noncited violation of 10 CFR Part 50, Appendix E,

Section IV. B., as a result of inadequate procedures for the implementation of an

emergency action level. The criteria in Procedure EIP-2-001, Classification of

Emergencies, Revision 12, for declaring an Alert emergency action level based on

primary coolant leak rate, relied solely on a computer generated leakrate report that

would not be valid under all conditions. The licensee entered this finding into their

corrective action program as CR-RBS-2005-03078 and issued Standing Order 192, as

an interim corrective action, to provide additional criteria to determine whether a primary

coolant leak rate Alert emergency action level declaration was required.

The finding is more than minor because it is associated with the Emergency

Preparedness Cornerstone attribute of procedural quality and affects the cornerstone

objective to ensure the licensee is capable of implementing adequate measures to

protect the health and safety of the public in the event of a radiological emergency. The

inadequate procedure could result in a failure to declare an Alert emergency

classification when required. Using Manual Chapter 0609, Appendix B, Emergency

Preparedness Significance Determination Process, this finding was determined to be of

very low safety significance since it was a failure to comply with a regulatory

requirement associated with a risk-significant planning standard that did not result in the

loss or degradation of that risk-significant planning standard function (Section 1R11).

B.

Licensee-Identified Violations

None.

Enclosure

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REPORT DETAILS

Summary of Plant Status

On October 1, 2005, reactor power was lowered to 70 percent to perform a rod sequence

exchange and insert two control rods for planned maintenance. The reactor was returned to

100 percent power on October 2, 2005. On October 21, 2005, reactor power was lowered to 63

percent to perform power suppression testing for a leaking fuel bundle. The reactor was

returned to 100 percent power on October 23, 2005. On November 5, 2005, reactor power was

lowered to 90 percent to adjust the control rod pattern and the reactor was returned to 100

percent later that day. On December 2, 2005, reactor power was lowered to 83 percent to

insert three control rods for planned maintenance. The reactor was returned to 100 percent

power on December 3, 2005. On December 9, 2005, reactor power was lowered to 58 percent

to perform a control rod pattern adjustment and conduct turbine valve testing. The reactor was

returned to 100 percent power on December 11, 2005. On December 17, 2005, reactor power

was lowered to 62 percent to perform power suppression testing for a leaking fuel bundle. The

reactor was returned to 100 percent on December 19, 2005, and remained at 100 percent for

the remainder of the inspection period.

1.

REACTOR SAFETY

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

Preparedness

1R01

Adverse Weather Protection

b.

Inspection Scope

Cold Weather Preparation

During the week of December 5, 2005, the inspectors reviewed the licensees

implementation of Operations Section Procedure OSP-0043, Freeze Protection and

Temperature Maintenance, Revision 6, to protect mitigating systems from cold weather

conditions. Specifically, the inspectors: (1) verified that risk-significant structures,

systems, and components will remain functional when challenged by cold weather

conditions; (2) verified that cold weather features such as heat tracing and space

heaters are operable and monitored; and (3) verified that the cold weather procedures

attachments were being completed for changing temperatures as required by the

procedure. The inspectors completed one inspection sample.

c.

Findings

No findings of significance were identified.

Enclosure

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1R04

Equipment Alignment

1.

Partial System Walkdowns

a.

Inspection Scope

On October 25, 2005, the inspectors walked down residual heat removal Division II

while residual heat removal Division I was out of service for scheduled maintenance.

On October 26, 2005, the inspectors walked down the piping and valve lineup of the

condensate storage tank, including emergency core cooling system suction and test

return valves. In each case, the inspectors verified the correct valve and power

alignments by comparing positions of valves, switches, and electrical power breakers to

the system operating procedures (SOP) and piping and instrument drawings listed

below and applicable sections of the Updated Safety Analysis Report (USAR). The

inspectors completed two inspection samples.

SOP-0031, Residual Heat Removal System, Revision 46

SOP-0008, Condensate Storage, Makeup and Transfer, Revision 16

Piping and Instrument PID 04-03A, Condensate Storage, Makeup and

Transfer, Revision 13

b.

Findings

No findings of significance were identified.

2.

Complete System Walkdown

a.

Inspection Scope

The inspectors conducted a complete walkdown of the drywell and containment leak

detection system during the week of June 26, 2005, during a drywell closeout inspection

and continuing the week of November 20, 2005. The methods of inspection included

field walkdown, in-office reviews, observation of system operation, and interviews of

computer engineering, operations, training, and emergency planning personnel. The

inspectors verified: (1) proper valve and control switch alignments, (2) computer

program algorithm, (3) power supply lineup, (4) associated support system status, and

(5) that alarms and indications in the main control room were as specified in the

following documents:

SOP-0033, Drywell and Containment Leak Detection System, Revision 11

USAR Section 5.2.5.1.1, Detection of Leakage within the Drywell

Technical Specifications (TS) Section 3.4.5, RCS Operational Leakage

The inspectors also verified electrical power requirements, labeling, hangers and

support installation, and associated support systems status. The walkdowns included

Enclosure

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evaluation of system piping and supports to ensure (1) piping and pipe supports did not

show evidence of damage, (2) hangers were secure, and (3) component foundations

were not degraded. The inspectors completed one inspection sample.

b.

Findings

No findings of significance were identified.

1R05

Fire Protection

a.

Inspection Scope

The inspectors walked down accessible portions of the plant described below to assess:

(1) the licensees control of transient combustible material and ignition sources; (2) fire

detection and suppression capabilities; (3) manual firefighting equipment and capability;

(4) the condition of passive fire protection features, such as, electrical raceway fire

barrier systems, fire doors, and fire barrier penetrations; and (5) any related

compensatory measures. The inspectors reviewed the Pre-Fire Plan/Strategy Book

during the fire protection inspections. The areas inspected were:

Auxiliary building, 70-foot, RHR Pump B Room, fire Area AB-3, on October 11,

2005

Auxiliary building, 95-foot, HPCS piping area, fire Area AB-2/Z-2, on October 12,

2005

Auxiliary building, 95-foot, LPCS panel room, fire Area AB-6/Z33, on October 12,

2005

Control building, 116-foot, safety-related 125 Vdc switchgear room, fire

Area C-24, on December 9, 2005

Control building, 116-foot, safety-related Switchgear 1C room, fire Area C-22, on

December 9, 2005

Control building, 116-foot, safety-related ENB inverter Charger A room, fire

Area C-18, on December 9, 2005

The inspectors completed six inspection samples.

b.

Findings

No findings of significance were identified.

Enclosure

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1R11

Licensed Operator Requalification Program

a.

Inspection Scope

.1

Annual Operating Examination Review

Following the completion of the annual operating examination testing cycle, which ended

the week of September 23, 2005, the inspectors reviewed the overall pass/fail results of

the annual individual job performance measure operating tests and simulator operating

tests administered by the licensee during the operator licensing requalification cycle.

Eight separate crews participated in simulator operating tests and job performance

measure operating tests, totaling 52 licensed operators. All of the crews tested passed

the simulator portion of the annual operating test. Two of the 52 licensed operators

failed the job performance measure portion and were successfully remediated. These

results were compared to the thresholds established in MC 0609, Appendix I, Operator

Requalification Human Performance Significance Determination Process. The

inspector completed one inspection sample.

.2

Resident Inspector Quarterly Review

On November 15, 2005, the inspectors observed simulator training of an operating crew,

as part of the operator requalification training program, to assess licensed operator

performance and the training evaluators critique. The inspection included observation

of high risk licensed operator actions, operator activities associated with the emergency

plan, and lessons learned from industry and plant experiences. In addition, the

inspectors compared simulator control panel configurations with the actual control room

panels for consistency. The simulator examination scenario observed was RSMS-OPS-

612, Loss of Vacuum/ATWS/Drywell Steam Leak - RPV Flooding, Revision 4. The

inspectors completed one inspection sample.

.3

Inadequate Emergency Event Classification Guidance

On June 10, 2005, the inspectors observed operating crew performance in the simulator

during annual requalification exam Scenario RSMS-OPS-509, SRV Tailpipe Steam

Leak Inside The Drywell, Revision 3. The inspectors discussed crew actions and

emergency planning requirements with the examination evaluators, training

management, emergency planning coordinators, and operations management. The

inspectors reviewed the following documents:

EIP-2-001, Classification of Emergencies, Revision 12

USAR 5.2.5.1.1, Detection of Leakage within the Drywell

Vendor computer manual, VTD-A324-0109, Analog Devices MICROMAC-5000

Final Draft, Leak Rate Detection PLC Documentation, River Bend Station -

Reactor Building Sump Systems, Revision 0

Enclosure

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Training Evaluation and Request, TEAR-RBS-2005-0477, Validating Leakage

Report, issued August 23, 2005

CR-RBS-2005-03078, Validating Leakage Report, initiated on August 26, 2005

Standing Order Number 192, Drywell Leakage Greater Than 50 gpm EAL

Guidance, Revision 0, issued November 3, 2005

b.

Findings

Introduction: The inspectors identified a Green NCV of 10 CFR Part 50, Appendix E,

Section IV.B, for inadequate procedures for implementation of an Alert emergency

action level (EAL).

Description: On June 10 2005, the inspectors observed operating crew performance in

the simulator during annual requalification exam Scenario RSMS-OPS-509, SRV

Tailpipe Steam Leak Inside The Drywell, Revision 3. The inspectors noted that when

the examination evaluators informed the team that the total drywell leakage report was

84 gpm, the team declared an Alert based on that report. Procedure EIP-2-001,

Classification of Emergencies, Revision 12, listed the criteria for an Alert EAL

classification as Total drywell LEAKAGE greater than 50 gpm.

Based on their observations in the simulator, the inspectors questioned the ability of the

leakage computer installed in the plant to accurately calculate total drywell leakage

under certain conditions. The inspectors analyzed the program run by the drywell

leakage computer and determined: (1) the drywell leakage computer would not

calculate total drywell leakage while a drywell sump pump was running; (2) computer

reports of total drywell leakage printed while a drywell sump pump was running would be

invalid; and (3) if a drywell high pressure or low reactor vessel level signal was present,

the valves in the drywell sump pump discharge lines would close, causing the drywell

sump pumps to run continuously, resulting in an invalid drywell total leakage report. The

inspectors determined that the indication used by operators to determine if the criteria

was met for declaring an Alert EAL due to total drywell leakage exceeding 50 gpm would

not be valid under certain conditions.

On August 23, 2005, the licensee initiated training evaluation action request TEAR-

2005-0477 to evaluate this condition to determine what training actions were necessary.

On August 26, 2005, the licensee initiated CR-RBS-2005-03078 that requested an

alternate means of determining the primary coolant leak Alert EAL using main control

room indications. The CR also requested additional training materials and classroom

instruction to reinforce this change.

On November 3, 2005, the licensee issued Standing Order 192 that provided additional

criteria to be used to make the determination of whether a primary coolant leak rate

Alert EAL declaration was required, without relying solely on the drywell leakage

computer. The inspectors concluded that Standing Order 192 was an adequate interim

compensatory measure until the licensee implemented permanent corrective actions.

Enclosure

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Analysis: The performance deficiency associated with this finding involved an

inadequate procedural criteria for declaring an Alert EAL in the event that total drywell

leakage exceeds 50 gpm under certain conditions. Specifically, computed drywell

leakrate used by operators to determine if total drywell leakage exceeds 50 gpm may be

invalid under certain conditions. The finding was more than minor because it is

associated with the Emergency Preparedness Cornerstone attribute of procedural

quality and affects the cornerstone objective to ensure the licensee is capable of

implementing adequate measures to protect the health and safety of the public in the

event of a radiological emergency. The inadequate procedure could result in a failure to

declare an Alert emergency classification when required. Using Manual Chapter 0609,

Appendix B, Emergency Preparedness Significance Determination Process, this

finding was determined to be of very low safety significance since it was a failure to

comply with a regulatory requirement associated with a risk-significant planning

standard that did not result in the loss or degradation of that risk-significant planning

standard function.

Enforcement: The failure to provide adequate procedures for implementation of an EAL

was a violation of 10 CFR Part 50, Appendix E, Section IV.B., which requires, in part,

that the licensees emergency plan describe the means to be used for determining the

impact of the release of radioactive materials including EALs. Because this finding was

of very low safety significance and was entered into the licensees corrective action

program as CR-RBS-2005-03078, this violation is being treated as an NCV, consistent

with Section VI.A of the NRC Enforcement Policy: NCV 05000458/2005005-01,

Inadequate procedure for implementation of an EAL.

1R13

Maintenance Risk Assessments and Emergent Work Control

a.

Inspection Scope

The inspectors reviewed selected maintenance activities to verify the performance of

assessments of plant risk related to planned and emergent maintenance work activities.

The inspectors verified: (1) the adequacy of the risk assessments and the accuracy and

completeness of the information considered, (2) management of the resultant risk and

implementation of work controls and risk management actions, and (3) effective control

of emergent work, including prompt reassessment of resultant plant risk. The inspectors

completed three inspection samples.

.1

Risk Assessment and Management of Risk

On a routine basis, the inspectors verified performance of risk assessments, in

accordance with administrative Procedure ADM-096, Risk Management Program

Implementation and On-Line Maintenance Risk Assessment, Revision 04, for planned

maintenance activities and emergent work involving structures, systems, and

components within the scope of the maintenance rule. Specific work activities evaluated

included the following planned and emergent work:

October 23, 2005, Division I residual heat removal and standby service water

equipment outage

Enclosure

-11-

November 28, 2005, Division III work week and station blackout diesel generator

planned maintenance

.2

Emergent Work Control

During emergent work, the inspectors verified that the licensee took actions to minimize

the probability of initiating events, maintained the functional capability of mitigating

systems, and maintained barrier integrity. The inspectors also reviewed the emergent

work activities to ensure the plant was not placed in an unacceptable configuration. The

specific emergent work activity followed was the cleaning of high voltage insulators in

the main transformer switchyard with a high pressure spray on October 7, 2005.

b.

Findings

No findings of significance were identified.

1R14

Operator Performance During Nonroutine Evolutions and Events

c.

Inspection Scope

The inspectors completed the two inspection samples listed below.

.1

Power Suppression Testing

The inspectors observed portions of and reviewed control room records for power

suppression testing conducted during the weekend of October 21, 2005. The inspectors

reviewed the reactivity control plan, the prejob briefing given in the main control room at

the beginning of the evolution and during control room operator and reactor engineer

shift turnover. The inspectors also reviewed the results of the test with the reactor

engineering representative and shift manager, including the recommendation to insert

Control Rod 20-45 to suppress power in the vicinity of a potential leaking fuel bundle.

Finally, the inspectors reviewed the postsuppression test off-gas pretreatment gaseous

activity levels used to monitor the success of the suppression efforts.

.2

Trip of Reactor Recirculation (RR) Flow Control Valve (FCV) Hydraulic Power

Unit (HPU)

On October 31, 2005, the inspectors observed operator response to a trip of RR FCV B

HPU. As a result, RR FCV B began to drift open. The operators took action to limit or

stop the gradual opening of RR FCV B. As RR FCV B continued to open, operators

throttled closed RR FCV A to maintain reactor power less than 100 percent. These

actions created an RR jet pump loop flow mismatch of greater than 5 percent requiring

entry into TS Action 3.4.1.A. The inspectors reviewed the TS requirements for this

condition and discussed the actions taken by the operators with the operations shift

Enclosure

-12-

manager and members of plant management team present in the control room at the

time. The following documents were reviewed by the inspectors as part of this

inspection:

C

Main Control Room Logs, October 31, 2005

C

CR-RBS-2005-03748, During Filter RCS-FLTR2B replacement, technicians

bumped an electrical cable, causing a trip of the reactor recirculation flow control

Valve B hydraulic power unit

C

W0 00075986, Replace grounded connection to Pressure Switch RCS-PDS90B

C

SOP-0003, Reactor Recirculation System, Revision 35

C

TS limiting condition for operation (LCO) 3.4.1 and applicable Bases

i.

Findings

Introduction: The inspectors identified a Green noncited violation of TS Action 3.4.1.A.1

for the licensees failure to restore compliance with LCO 3.4.1 or shut down one RR loop

within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of determining that RR loop jet pump flow mismatch was greater than

5 percent while operating at greater than 70 percent of rated core flow.

Description: On October 31, 2005, at 2:54 p.m., the RR FCV B HPU tripped. As a

result, RR FCV B began to drift open. The operators took action to limit or stop the

gradual opening of RR FCV B. As RR FCV B continued to open, operators throttled

closed RR FCV A to maintain reactor power less than 100 percent.

At 3:06 p.m., the operators entered TS LCO Condition 3.4.1.A because the RR loop jet

pump flow mismatch exceeded 5 percent with the plant operating at greater than 70

percent rated core flow. The highest flow mismatch was 8.2 percent. TS Action

3.4.1.A.1 required the licensee to shut down one recirculation loop with 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

The licensee issued a work request and began to troubleshoot the HPU trip. At the

same time, operators requested that reactor engineers develop a reactivity control plan

to insert control rods to lower reactor power. This would allow operators to reopen

RR FCV A to reduce the RR jet pump loop flow mismatch to less than the required

5 percent.

At 4:24 p.m., the licensee determined that the cause for the HPU trip was a blown

control power fuse. The fuse blew as a result of a grounded wire to a filter high

differential pressure switch, which was bumped by maintenance technicians who were

changing the filter cartridge. The inspectors asked the operators and licensee

management if they intended to shut down one RR loop or perform the actions

necessary to reduce the jet pump flow mismatch to less than 5 percent, as required by

TS 3.4.1. The licensee responded that they did not want to maneuver the plant and

change core conditions, which might exacerbate the existing condition of two leaking

fuel bundles.

Enclosure

-13-

At 5:06 p.m., the operators exited TS Action 3.4.1.A without shutting down one RR loop

or reducing jet pump loop flow mismatch to less than 5 percent. Instead they entered

TS Action 3.4.1.D.1, which required that the reactor be placed in Mode 3 in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

When asked, the operators and licensee management stated that they could commence

a plant shutdown within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and still meet the requirement to be in Mode 3

in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . They also stated that at the 6-hour point, they would commence the

shutdown with the reactivity control plan to reduce reactor power by inserting control

rods and open RR FCV A to reduce jet pump loop flow mismatch to less than 5 percent.

If that was successful, they would then exit TS LCO 3.4.1.

Subsequently, the repairs were completed to the pressure switch wire, the control power

fuse was replaced, and RR FCV B HPU was restarted. Following a one-hour warmup,

the RR FCV B HPU was returned to service. RR jet pump loop flow was reduced below

5 percent and the licensee exited TS LCO 3.4.1. at 7:36 p.m., 4.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after entry into

TS LCO Condition 3.4.1.A.

The inspectors determined that: (1) when the cause of the trip of RR FCV B HPU was

determined to be the grounded pressure switch wire, the licensee knew that the time to

make the repairs and return the HPU to service would exceed the 2-hour completion

time of TS Action 3.4.1.A.1; and (2) the licensee was capable of restoring RR jet pump

loop flow mismatch to less than 5 percent or shutting down one RR loop within the

2-hour completion time of TS Action 3.4.1.A.1.

Analysis: The licensees failure to restore compliance with TS LCO 3.4.1 or complete

the required action of TS 3.4.1.A.1 to shut down one RR loop within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months was a

performance deficiency. The finding was more than minor because, if left uncorrected,

it would become a more significant safety concern. According to TS LCO 3.4.1 Bases,

the operation of the RR pumps is an initial condition assumed for the design basis loss-

of-coolant accident (LOCA). During a LOCA caused by a RR loop break, the intact RR

loop is assumed to provide coolant flow during the first few seconds of the accident.

The initial core flow decrease is rapid because the RR pump in the broken loop ceases

to pump water through the vessel almost immediately. The pump in the intact loop

coasts down more slowly. This pump coast down governs the core flow response for

the next several seconds until the jet pump suctions are uncovered. The analyses

assume that both RR loops are operating at the same flow prior to the LOCA. However,

if the LOCA analysis is reviewed for an initial jet pump flow mismatch with the break

assumed to be in the loop with the higher flow, the flow coast down and core response

are potentially more severe, since the intact loop starts at a lower flow rate.

The significance of this finding could not be evaluated using MC 0609, Significance

Determination Process. Based on management review, the finding was determined to

be of very low safety significance based on the short duration of the flow mismatch,

4.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months , and the low likelihood of a LOCA during that time. The cause of this finding

is related to the crosscutting element of human performance in that operators failed to

implement TS requirements.

Enforcement: TS LCO 3.4.1 states that two RR loops shall be in operation with

matched flows when the reactor is in Modes 1 or 2. If RR loop jet pump flow mismatch

Enclosure

-14-

is not less than or equal to 5 percent of rated core flow when operating at greater than

or equal to 70 percent of rated core flow (Condition 3.4.1.A), then the licensee must shut

down one RR loop (Required Action A.1) within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months (Completion Time). Contrary to

the above, on October 31 , 2005, 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months after RR loop jet pump flow mismatch was

greater than 5 percent of rated core flow, the licensee exited TS 3.4.1.A.1 without

shutting down one RR loop or restoring the jet pump flow mismatch to less than

5 percent. Because the finding is of very low safety significance and has been entered

into the licensees corrective action program as CR-RBS-2006-00274, this violation is

being treated as an NCV in accordance with Section IV.A of the NRC Enforcement

Policy and is identified as NCV 05000458/2005005-02: Failure to complete TS required

actions within allowed completion time.

1R15

Operability Evaluations

a.

Inspection Scope

The inspectors reviewed selected operability determinations on the basis of potential

risk importance. The selected samples are addressed in the condition reports (CRs)

listed below. The inspectors assessed: (1) the accuracy of the evaluations, (2) the use

and control of compensatory measures if needed, and (3) compliance with TS, the

Technical Requirements Manual, the USAR, and other associated design-basis

documents. The inspectors review included a verification that the operability

determinations were made as specified by Entergy Procedure EN-OP-104, Operability

Determinations, Revision 1. The operability evaluations reviewed were associated with:

CR-RBS-2004-1270, Check valves in primary Containment 113' elevation airlock

not included in the in-service testing program, reviewed on October 11, 2005

CR-RBS-2005-3563, Check valves in primary Containment 113' elevation airlock

not included in the in-service testing procedure, reviewed on October 19, 2005

CR-RBS-2005-3568, In-service test program changed for primary containment

113' elevation airlock without changing in-service test procedure, reviewed on

October 19, 2005

CR-RBS-2005-04251, -04252, Safety-related Inverter ENB-INV01B1 frequency

and safety-related instrument Bus VBS-PNL01B voltage out of specification high,

reviewed on December 27, 2005

The inspectors completed two inspection samples.

f.

Findings

No findings of significance were identified.

Enclosure

-15-

1R16

Operator Workarounds

a.

Inspection Scope

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 November 28, 2005, the inspectors reviewed an operator

workaround which required operators to hold the control switch for throttle valves for at

least 5 seconds after the full closed indication is received. The inspectors interviewed

operators to determine if they knew specifically which valves were affected and if they

were aware of this operational requirement from memory.

During the week of December 5, 2005, the inspectors reviewed the cumulative effect of

the existing operator workarounds 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 of the operator workarounds on

the ability of the operators to respond in a correct and timely manner to plant transients

and accidents. The procedures and other documents reviewed by the inspectors were:

Operator Workaround - Control Room Deficiency Program Guidelines,

Revision 11

Operator workaround report

Operator burden report

Daily plant status reports

Operations shift turnover sheet

Standing Order Number 190, Electrically Operated Throttle Valve Operations,

Revision 0

The inspectors completed two inspection samples.

b.

Findings

No findings of significance were identified.

1R17

Permanent Plant Modifications

a.

Inspection Scope

The inspectors reviewed MR96-0063, Remove Internals of [Reactor Core Isolation

Cooling Turbine (RCIC) Exhaust Check Valve] E51-VF040, dated September 18, 1996,

Enclosure

-16-

and the assumptions made with respect to the capability of the RCIC turbine exhaust

line vacuum breaker vent line. On December 10, 2004, the RCIC turbine was manually

started and ran for a short period of time before shutting down on high reactor water

level. The RCIC exhaust line drain trap high level alarm came in and operators

observed water draining from the drain trap for 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The documents reviewed as

part of this inspection are listed in the attachment. The inspectors completed one

inspection sample.

b.

Findings

Introduction: The inspectors identified a self-revealing NCV of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, for failure to address a full spectrum of design

conditions for the RCIC turbine exhaust line vacuum breaker system as part of a plant

modification to remove the internals of the RCIC turbine exhaust line check valve. As a

result, on December 10, 2004, when RCIC was started and subsequently shut down on

high reactor water level following a scram and loss of feedwater, the RCIC exhaust line

filled with water from the suppression pool, causing the operators to consider RCIC

unavailable, complicating their response to the event.

Description: In September 1996, in response to a request from mechanical

maintenance, design engineering processed a design change to remove RCIC Turbine

Exhaust Check Valve E51-VF040. As part of Modification Request MR-96-0063, an

evaluation was performed on the adequacy of the RCIC turbine exhaust line vacuum

breaker system to prevent the siphoning of suppression pool water into the RCIC turbine

exhaust line following a shutdown of the RCIC turbine. During the evaluation it was

determined that the as-built vacuum breaker vent line was not in accordance with the

original design of the vacuum breaker line. A new calculation was performed for the

as-built configuration (globe valves and lift check valves versus gate valves and swing

check valves). The basic assumption used for Calculation PH-056, RCIC Turbine

Exhaust Line Vacuum Breaker Vent Line Sizing Verification, Revision 1A, was that the

RCIC exhaust line would be at equilibrium conditions when the turbine tripped. The

turbine would run long enough for the exhausted steam and exhaust piping to be at the

same temperature and that the only cooling effect would be to ambient. The result was

that the gradual cooldown of the steam and exhaust piping would cause the formation of

a vacuum in approximately 35.5 minutes. The revised sizing calculation showed that the

as-built vacuum breaker vent line was capable of relieving a vacuum created in as short

a time as 3.5 minutes.

On December 10, 2004, following a reactor scram, RCIC was started to maintain reactor

water level due to the pending loss of all reactor feed pumps. When RCIC Steam to

Turbine Valve E51-MOV045 stroked full open, it automatically reclosed due to the high

reactor water level interlock. It was later determined that steam was admitted to the

turbine for approximately 11 seconds. As a result, the steam in the exhaust line

condensed more rapidly than assumed and the exhaust line pressure became a vacuum

within 17 seconds. This rapid pressure reduction overwhelmed the vacuum breaker

vent line and 84 gallons of suppression pool water was siphoned into the RCIC turbine

exhaust line.

Enclosure

-17-

The licensee later determined that the static and dynamic loads on the turbine exhaust

line for a restart on the RCIC turbine would be within design limits, although a water

hammer transient would occur. Based on test data provided by the turbine

manufacturer, the licensee also determined that the turbine would experience no

damage and not trip on overspeed if it were to be started with water in its exhaust line.

The turbine startup would be slower than normal, but within the assumed values in the

safety analysis. The turbine exhaust line check valve internals were reinstalled in

February 2005.

Analysis: The failure to adequately address worst case design conditions in the sizing

calculation for the RCIC turbine exhaust line vacuum breaker vent line to allow for the

removal of the exhaust line check valve was a performance deficiency. The finding was

more than minor because it was associated with the Mitigating Systems cornerstone

attribute of Design Control and affected the cornerstone objective to ensure the

availability and reliability of the RCIC system, a system that responds to initiating events

(loss of feedwater and station blackout), to prevent undesirable consequences. Using

the MC 0609, Significance Determination Process, Phase 1 Worksheet, the finding

was determined to have very low safety significance because it represented a design

deficiency that did not result in a loss of system function.

Enforcement: 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part,

that design changes, including field changes, shall be subject to design change control

measures commensurate with those applied to the original design. Contrary to the

above, the RCIC turbine exhaust line vacuum breaker vent line sizing calculation, used

as part of the modification process to remove the exhaust line check valve, did not take

into consideration the most limiting exhaust line conditions. As a result the vacuum

breaker vent line was not capable of preventing the siphoning of suppression pool water

into the RCIC Turbine Exhaust line. Because this finding was of very low safety

significance and was documented in the licensees corrective action program as

CR-RBS-2005-00724, it is being treated as an NCV in accordance with Section IV. A of

the NRC Enforcement Policy and is identified as NCV 05000458/2005005-03:

Inadequate design assumption results in RCIC turbine exhaust header filling with water

following an automatic high water level shutdown.

1R19

Postmaintenance Testing

a.

Inspection Scope

The inspectors reviewed selected work orders (WO) to ensure that testing activities

were adequate to verify system operability and functional capability. The inspectors:

(1) identified the safety function(s) for each system by reviewing applicable licensing

basis and/or design-basis documents; (2) reviewed each maintenance activity to identify

which maintenance function(s) may have been affected; (3) reviewed each test

procedure to verify that the procedure did adequately test the safety function(s) that may

have been affected by the maintenance activity; (4) reviewed the acceptance criteria in

the procedure to ensure consistency with information in the applicable licensing basis

and/or design-basis documents; and (5) identified that the procedure was properly

reviewed and approved. The eight WOs inspected are listed below:

Enclosure

-18-

C

WO 00063768, replace hydrogen igniter in containment dome, review conducted

during the week of October 31, 2005

C

WO 00075881, replace rod control and information system isolation transformer,

reviewed during the week of October 31, 2005

C

WO 00074806, rebuild control rod drive Hydraulic Control Unit 4833, review

conducted during the week of December 12, 2005

C

WO 50969759, rebuild control rod drive Hydraulic Control Unit 1625, review

conducted during the week of December 12, 2005

C

WO 00066597, rework Inverter BYS-INV01A to fix blown fuse problem, review

conducted during the week of December 12, 2005

C

WO 50968926, replace frequency detector board on Inverter ENB-INV01B1,

review conducted during the week of December 12, 2005

C

WO 00072137, quarterly inspection and lubrication of the station blackout diesel,

review conducted during the week of December 19, 2005

C

WO 50967030, clean, inspect, and lubricate the station blackout diesel, review

conducted during the week of December 19, 2005

The inspectors completed eight inspection samples.

b.

Findings

No findings of significance were identified.

1R22

Surveillance Testing

a.

Inspection Scope

The inspectors verified, by witnessing and reviewing test data, that risk-significant

system and component surveillance tests met TS, USAR, and procedure requirements.

The inspectors ensured that surveillance tests demonstrated that the systems were

capable of performing their intended safety functions and provided operational

readiness. The inspectors specifically: (1) evaluated surveillance tests for

preconditioning; (2) evaluated clear acceptance criteria, range, accuracy and current

calibration of test equipment; and (3) verified that equipment was properly restored at

the completion of the testing. The inspectors observed and reviewed the following

surveillance tests and surveillance test procedures (STP):

C

STP-552-4202, "Post Accident Monitoring/Remote Shutdown System -

Suppression Pool Water Level Channel Calibration (CMS-LT23B, CMS-ESX23B,

CMS-LI23B, CMS-TR40B, CMS-LIX23B)," Revision 9A, performed on

October 13, 2005

Enclosure

-19-

C

MCP-4303, Functional Test of Standby Cooling Tower #1 Station Blackout

Division I Standby Service Water Return Valve and Valve Logic

(SWP-AOV599), Revision 01A, performed on October 25, 2005

C

STP-552-4502, "Post Accident Monitoring/Remote Shutdown System - Drywell

Pressure Channel Calibration (CMS-PT2A, CMS-T103, CMS-PR2A),"

Revision 14A, performed on November 28, 2005

The inspectors completed three inspection samples.

b.

Findings

No findings of significance were identified.

1R23

Temporary Plant Modifications

a.

Inspection Scope

During the week of December 19, 2005, the inspectors reviewed the following temporary

plant modifications: (1) temporary Alteration TA05-0015-00 to supply Division II safety-

related 120 volt ac electrical distribution Panel SCM-PNL01B from safety-related power

Supply RPS-XRC10B1 so that repairs to safety-related power Supply SCM-XRC14B1

could be made; and (2) temporary Alteration TA05-0014-01 to install radiation shielding

in front of standby gas treatment control Panels GTS-PNL28A/B until a permanent

solution could be installed. This shielding was installed after an equipment qualification

evaluation showed that the total integrated dose for standby gas treatment Panel GTS-

PNL28A/B could exceed qualification doses of internal electrical equipment after the

annulus mixing system was retired. Specifically, the inspectors: (1) reviewed each

temporary modification and its associated 10 CFR 50.59 screening against the system's

design basis documentation, including the USAR and TS; (2) verified that the installation

of the temporary modification was consistent with the modification documents; and

(3) reviewed the postinstallation test results to confirm that the actual impact of the

temporary modification on SCM-PNL01B and GTS-PNL28A/B had been adequately

verified. The inspectors completed two inspection samples.

b.

Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Testing

a.

Inspection Scope

The inspector discussed with licensee staff the status of offsite siren systems to

determine the adequacy of licensee methods for testing the alert and notification system

Enclosure

-20-

in accordance with 10 CFR Part 50, Appendix E. The licensees alert and notification

system testing program was compared with criteria in NUREG-0654, Criteria for

Preparation and Evaluation of Radiological Emergency Response Plans and

Preparedness in Support of Nuclear Power Plants, Revision 1, Federal Emergency

Management Agency (FEMA) Report REP-10, Guide for the Evaluation of Alert and

Notification Systems for Nuclear Power Plants, and the licensees current

FEMA-approved alert and notification system design report. The inspector also

reviewed Procedures EPP-2-701, Prompt Notification System Maintenance and

Testing, Revision 18, and EPP-2-401, Inadvertent Siren Sounding, Revision 7. The

inspector completed one inspection sample.

b.

Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation

a.

Inspection Scope

The inspector reviewed the following documents to determine the licensees ability to

staff emergency response facilities in accordance with the licensee emergency plan and

the requirements of 10 CFR Part 50, Appendix E.

EIP-2-006, Notifications, Revision 32

EPP-2-502, Emergency Communications Equipment Testing, Revision 21

Details of 10 staffing augmentation and quarterly pager drills

The inspector completed one inspection sample.

b.

Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a.

Inspection Scope

The inspector reviewed the following documents related to the licensees corrective

action program to determine the licensees ability to identify and correct problems in

accordance with 10 CFR 50.47(b)(14) and 10 CFR Part 50, Appendix E:

Quality assurance audits of the emergency preparedness program conducted in

2003, 2004, and 2005

Four licensee self-assessments

Licensee evaluation reports for 11 drills and exercises

Enclosure

-21-

Summaries of 146 corrective actions assigned to the emergency preparedness

department between February 2003 and October 2005

Details of 17 selected CRs

The licensees corrective action program was also compared with the requirements of

Procedure EN-LI-102, Corrective Action Process, Revision 2. The inspector

independently evaluated the emergency operations facility during an October 18, 2005,

drill and compared the postdrill critique of licensee performance. The inspector

completed one inspection sample.

b.

Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a.

Inspection Scope

The inspectors observed the emergency preparedness drill conducted on October 18,

2005, to identify any weaknesses and deficiencies in classification, notification, and

protective action recommendation development activities. The inspectors also

evaluated the licensee assessment of classification, notification, and protective action

recommendation development during the drill in accordance with plant procedures and

NRC guidelines. The inspectors also observed the drill evaluator immediate critiques of

the drill participants classification, notification, and protective action recommendation

activities. The following procedures and documents were reviewed during the

assessment:

C

EIP-2-001, Classification of Emergencies, Revision 13

C

EIP-2-006, Notifications, Revision 32

C

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

The inspectors completed one inspection sample.

b.

Findings

No findings of significance were identified.

Enclosure

-22-

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS2 ALARA Planning and Controls

a.

Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual and

collective radiation exposures as low as is reasonably achievable (ALARA). The

inspector used the requirements in 10 CFR Part 20 and the licensees procedures

required by TS as criteria for determining compliance. The inspector interviewed

licensee personnel and reviewed:

Current 3-year rolling average collective exposure

Three on-line maintenance work activities scheduled during the inspection period

and associated work activity exposure estimates which were likely to result in the

highest personnel collective exposures

Site-specific ALARA procedures

ALARA work activity evaluations, exposure estimates, and exposure mitigation

requirements

Intended versus actual work activity doses and the reasons for any

inconsistencies

Dose rate reduction activities in work planning

Method for adjusting exposure estimates, or replanning work, when unexpected

changes in scope or emergent work were encountered

Use of engineering controls to achieve dose reductions and dose reduction

benefits afforded by shielding

Radiation worker and radiation protection technician performance during work

activities in radiation areas, airborne radioactivity areas, or high radiation areas

Self-assessments and audits related to the ALARA program since the last

inspection

Corrective action documents related to the ALARA program and follow-up

activities such as initial problem identification, characterization, and tracking

The inspector completed 9 of the required 15 inspection samples and 2 of the optional

inspection samples.

Enclosure

-23-

b.

Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Emergency Preparedness Cornerstone

a.

Inspection Scope

The inspector sampled licensee submittals for the performance indicators listed below

for the period July 1, 2004, through September 30, 2005. The definitions and guidance

of NEI 99-02, Regulatory Assessment Indicator Guideline, Revisions 2 and 3, were

used to verify the licensees basis for reporting each data element in order to verify the

accuracy of performance indicator data reported during the assessment period. The

licensees performance indicator data was also reviewed against the requirements of

Procedure EN-LI-114, Performance Indicator Process, Revision 0.

Drill and Exercise Performance

Emergency Response Organization Participation

Alert and Notification System Reliability

The inspector reviewed a 100 percent sample of drill and exercise scenarios, licensed

operator simulator training sessions, notification forms, and attendance and critique

records associated with training sessions, drills, and exercises conducted during the

verification period. The inspector reviewed emergency responder qualification, training,

and drill participation records for 20 key licensee emergency response personnel. The

inspector reviewed procedures for conducting siren testing and a 100 percent sample of

siren test records. The inspector also interviewed licensee personnel that were

accountable for collecting and evaluating the performance indicator data.

The inspector completed three inspection samples.

b.

Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

1.

Emergency Preparedness Annual Sample Review

a.

Inspection Scope

The inspector reviewed a summary listing of 146 corrective actions assigned to the

emergency preparedness department, reviewed 17 CRs in detail, and independently

Enclosure

-24-

assessed the licensees ability to identify problems associated with an October 18, 2005,

integrated drill, in order to assess the licensees ability to identify and correct problems.

The inspector completed one inspection sample.

b.

Findings

No findings of significance were identified.

2.

ALARA Planning and Controls Annual Sample Review

a.

Inspection Scope

The inspector evaluated the effectiveness of the licensee's problem identification and

resolution processes regarding exposure tracking, higher than planned exposure levels,

and radiation worker practices. The inspector reviewed the corrective action documents

listed in the attachment against the licensees problem identification and resolution

program requirements. The inspector completed one inspection sample.

b.

Findings

No findings of significance were identified.

3.

Semiannual Trend Review

a.

Inspection Scope

The inspectors performed a 6-month review of the licensees corrective action program

and associated documents to identify trends that could indicate the existence of a more

significant safety issue. The inspectors review was focused on repetitive issues, but

also considered the results of daily inspector screening of CRs and licensee trending

efforts. The inspectors review considered the six month period of July through

December 2005. Inspectors reviewed 76 specific CRs and their associated operability

evaluations. Operability determinations set the priority for corrective actions to resolve

conditions adverse to quality. The CR numbers are listed in the attachment.

The inspectors also evaluated the CRs and the operability determinations against the

requirements of the following guidance documents:

Procedure EN-LI-102, Corrective Action Process, Revision 1

Procedure EN-OP-104, Operability Determinations, Revision 1

Procedure OSP-0040, LCO Tracking and Safety Function Determination

Program, Revision 10

MC 9900, Operability Determinations and Functionality Assessments for

Resolution of Degraded or Nonconforming Conditions Adverse to Quality or

Safety, dated September 26, 2005

Enclosure

-25-

The inspectors completed one inspection sample.

b.

Assessment and Observations

There were no findings of significance identified. The inspectors determined that a

number of operability determinations stated that the equipment that was the subject of

the CR was currently inoperable and being tracked using the LCO Tracking System.

The inspectors found that this system was an effective mechanism for resolution of TS

LCOs. However, from a corrective action program perspective, there was no closure of

the condition adverse to quality (system inoperability) or a discussion of the corrective

actions taken to restore the equipment to operable status in the subject CR. In addition,

the inspectors observed that a number of operability determinations described

conditions where the system was declared operable but the system or a support system

was in a degraded or nonconforming condition. In some cases, compensatory actions

were being taken to ensure system operability, but no mechanism was in place to

ensure that these compensatory measures remained in place until the degraded or

nonconforming condition was corrected. The inspectors did not find any examples

where the nonconforming condition was not corrected within a reasonable period of

time.

4.

Resident Inspector Annual Sample Review

The inspectors completed two inspection samples.

Ultimate Heat Sink Long Term Heat Removal Capacity

c.

Inspection Scope

The inspectors reviewed CR-RBS-2002-01243, ultimate heat sink capacity less than the

30-day requirement, during the week of November 28, 2005. The inspectors evaluated

the CR against the requirements of the licensees corrective action program as

described in nuclear management manual Procedure LI-102, Corrective Action

Process, Revision 4, and 10 CFR Part 50, Appendix B, Criterion XVI.

b. Findings and Observations

There were no findings of significance identified. On August 28, 2002, the inspectors

found: (1) the single failure assumption made for the design of the ultimate heat sink

was a trip of standby diesel Generator B immediately after a small line break event, with

bypass, coincident with a loss-of-offsite power and plant trip, (2) the ultimate heat sink

capacity would be less than 30 days if, instead, all ECCS systems worked as designed

and no operator actions were taken to secure ECCS, and (3) specific procedures to

replenish the ultimate heat sink during a loss-of-offsite power had not been written. In

response to the inspectors' concerns, the licensee wrote CR-RBS-2002-01243 and took

the following corrective actions: (1) revised their procedures to clarify operator actions if

no single failure occurred and to provide instructions for makeup to the ultimate heat

Enclosure

-26-

sink during a 30-day loss-of-offsite power; and (2) issued license amendment Request

LAR-2001-026, dated March 18, 2003, to revise their TS Bases 3.7, Standby Service

Water System and Ultimate Heat Sink, and USAR.

Simulator Fidelity Issue Regarding Wide-Range Level Recorders

d.

Inspection Scope

The inspectors reviewed the corrective actions taken by the licensee in response to

NCV 05000458/2004005-02, wide-range reactor water level indication did not respond

as expected by operators following an unplanned reactor scram. On December 10,

2004, a failure of a balance of plant instrument bus caused the feedwater regulating

valves to fail in their 100 percent flow position. Following a reactor scram, the feedwater

pumps overfed the reactor and tripped on high reactor water level. The excess

feedwater caused reactor water level to continue to rise after the feed pump trip. The

wide-range level recorders' digital output continued to indicate reactor water level

greater than +60 inches, the top end of the wide-range level instruments. The reactor

operators were not aware that the recorders digital output would continue to increase

beyond +60 inches because the digital readout of wide-range level recorders in the

simulator stopped at +60 inches. This response caused some confusion and

complicated the operators' response to the event. The inspectors reviewed CR-RBS-

2004-04289, -04295, -04296 and -04299 written by the licensee in response to this

event.

e.

Findings and Observations

There were no findings of significance identified. The inspectors found that, when a

design change was implemented changing the wide-range reactor water level recorders

from analog to digital models, the simulator modification made the software for the

recorders stop indicating at the top of scale (+60 inches). The digital recorders installed

in the control room, however, had no upper limit on the digital indication. On

December 10, 2004, reactor water level rose above the reference leg tap for the level

transmitter and, as the reference leg condensing chamber cooled down, the wide-range

level transmitters output continued to increase and the digital indication showed a level

as high as +140 inches. The inspectors reviewed the corrective actions taken by the

licensee and determined that they were reasonable and adequate to correct the

operator knowledge deficiency caused by the simulator fidelity issue. The inspectors

interviewed a cross-section of control room operators and determined that the

phenomena was understood and they understood that any wide-range digital indication

greater that +60 inches was invalid and not indicative of actual reactor water level.

4OA3 Event Followup

1.

(Closed) Licensee Event Report (LER) 50-458/04-001-00, Automatic Reactor Scram

Due to Main Generator Trip Resulting from Switchyard Fault

On August 15, 2004, a transmission tower guy wire failed. This allowed a 230 kV

transmission line structure between Port Hudson and Fancy Point (Line 353) to fall and

Enclosure

-27-

create a ground fault condition on the line. Four breakers in the station switchyard were

slow to open to clear the fault. As a result: (1) Reserve Station Transformer 2 was

deenergized, causing a partial loss of off-site power and start of the Division 2

emergency diesel generator; and (2) main transformer protection relays caused a main

generator lockout, which resulted in a generator load reject reactor scram.

NRC Integrated Inspection Report 05000458/2004005, issued February 14, 2005,

documented a Green, self-revealing finding associated with this event for preconditioned

speed testing of station switchyard breakers and three similar failures of station

switchyard breakers. The licensee revised the speed testing procedures to avoid

preconditioning the breakers.

NRC Supplemental Inspection Report 05000458/2005012, issued October 24, 2005,

documented a supplemental inspection performed in accordance with Inspection

Procedure 95001. The supplemental inspection was in response to four unplanned

reactor scrams that occurred between August 15, 2004, and January 15, 2005. The

licensees root cause analysis identified several programmatic changes which were

incorporated into a switchyard reliability program to improve switchyard maintenance

practices.

The inspectors reviewed the LER and the licensees resolution of identified problems

and determined there were no findings of significance and no other violations of NRC

requirements. The licensee documented the failed equipment in CR-RBS-2004-02332.

4OA6 Meetings, Including Exit

Exit Meetings

On October 21, 2005, the inspector presented the emergency preparedness inspection

results to Mr. J. Leavines, Manager, Emergency Planning, and other members of his

staff who acknowledged the findings. The inspector confirmed that proprietary

information was not provided or examined during the inspection.

On November 4, 2005, the inspector presented the licensed operator requalification

program inspection results to Mr. Mike Cantrell, Operations Training Supervisor, and

other members of the licensees management staff. The licensee acknowledged the

findings presented. The inspector confirmed that proprietary information was not

provided or examined during the inspection.

On December 8, 2005, the inspector presented the ALARA inspection results to

Mr. R. King, Director, Nuclear Safety Assurance, and other members of his staff who

acknowledged the findings. The inspector confirmed that proprietary information was

not provided or examined during the inspection.

Enclosure

-28-

On January 4, 2006, the inspectors presented the integrated baseline inspection results

to Paul Henninkamp, Vice President, Operations, and other members of licensee

management. The inspector confirmed that proprietary information was not provided or

examined during the inspection.

ATTACHMENT: SUPPLEMENTAL INFORMATION

A-1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

M. Boyle, Manager, Radiation Protection

D. Burnett, Superintendent, Chemistry

M. Cantrell, Operations Training Supervisor

J. Clark, Assistant Operations Manager - Training

T. Coleman, Manager, Planning and Scheduling/Outage

M. Davis, Acting Manager, Radiation Protection

C. Forpahl, Manager, Corrective Actions

H. Goodman, Director, Engineering

P. Hinnenkamp, Vice President - Operations

B. Houston, Manager, Plant Maintenance

G. Huston, Assistant Operations Manager - Shift

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

P. Russell, Manager, System Engineering

C. Stafford, Manager, Operations

W. Trudell, Manager, Training and Development

D. Vinci, General Manager - Plant Operations

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000458/2005005-01

NCV

Inadequate procedure for implementation of an EAL

05000458/2005005-02

NCV

Failure to complete TS required actions within allowed

completion time

05000458/2005005-03

NCV

Inadequate design assumption results in RCIC turbine

exhaust header filling with water following an automatic

high water level shutdown

Closed

05000458/2004-001-00

LER

Automatic Reactor Scram Due to Main Generator Trip

Resulting from Switchyard Fault

A-2

Attachment

LIST OF DOCUMENTS REVIEWED

The following documents were selected and reviewed by the inspectors to accomplish the

objectives and scope of the inspection and to support any findings:

Section 1R11: Licensed Operator Requalification Program

Job Performance Measures

RJPM-OPS-052-04, Alternate Control Rod Drive Pumps, August 4, 2005

RJPM-OPS-053-03R5, Reset a FCV runback, July 26, 2005

RJPM-OPS-109.4, July 26, 2005

RJPM-OPS-110-04, Synchronize the Main Generator with the Grid, August 2, 2005

RJPM-OPS-256-03R4, Restore level in the SBCT with deepwell pumps, July 26, 2005

RJPM-OPS-309-050, July 19, 2005

RJPM-OPS-508-04, Restore RPS B Normal Power Supply, August 19, 2005

RJPM-OPS-508-07, Respond to reactor scram with control rods failing to insert,

August 2, 2005

RJPM-OPS-800-17R1, Vent the CCRD over-piston volume, July 26, 2005

RJPM-OPS-05206R2, Control rod operability faulted, July 12, 2005

RJPM-OPS-05207R2, Alternate control rod drive pumps (Fuel Bldg), July 12, 2005

RJPM-OPS-05304R, Startup A recirc HPU, July 12, 2005

RJPM-OPS-20005R, Perform ATC actions for remote shutdown, August 2, 2005

RJPM-OPS-20006R5, Perform Attachment 13 UO actions, July 26, 2005

Scenarios

RSMS-OPS-822, Loss of All Feed Water / RCIC Failure / LOCA, Revision: 00

RSMS-OPS-823, APRM Failure /SRV Failure / EHC Failure / ATWS, Revision: 00

RSMS-OPS-824, LPRM Failure / Loss of Vacuum with MSIV Closure / ATWS,

Revision: 00

A-3

Attachment

RSMS-OPS-825, Loss of RPS B / Relief Valve Fails Open / Steam Leak in the Drywell

With Failure of the Drywell, Revision: 00

RSMS-OPS-827, Rod Drop / Fuel Failure / RCIC Steam Leak / Partial ATWS,

Revision: 00

RSMS-OPS-829, Failure Of STX-XS2B / Loss Of Condenser Vacuum / ATWS,

Revision: 00

RSMS-OPS-830, Inadvertent HPCS Injection and Loss of Stator Cooling, Revision: 00

Section 1R17: Permanent Plant Modifications

Event Notification 41252, Reactor Scram due to Loss of Vital Instrument Bus

LER 05-458/04-005-01, Unplanned Automatic Scram due to Loss of Non-Vital 120 Volt

Instrument Bus, June 22, 2005

CR-RBS-2004-04291 RCIC system initiated and subsequently tripped on Level 8

CR-RBS-2005-00724 MR96-0063 removed internals from RCIC Turbine Exhaust Check

Valve E51-VF040

SDRP-P43, System Design Requirements Document, Reactor Core Isolation Cooling,

Revision 0

SDC-209, Reactor Core Isolation Cooling System Design Criteria, Revision 0,

November 9, 1998

SDC-209, Reactor Core Isolation Sooling System Design Criteria, Revision 3,

September 27, 2004

RBS USAR Section 5.4.6, Reactor Core Isolation Cooling System, Revision 17

NUREG-0989, RBS Safety Evaluation Report and Supplements, May 1984 through

October 1985

GE SIL-30, HPCI/RCIC Turbine Exhaust Line Vacuum Breakers, October 31, 1973

GS AID-56, HPCI/RCI Turbine Exhaust Check Valve Cycling, August 1985

VPF-3622-353 (1) - 1, RCIC Turbine Instruction Manual, January 1975 through

March 1978

MR96-0063, Remove Internals of [RCIC Exhaust Check Valve] E51-VF040,

September 18, 1996

A-4

Attachment

CR-RBS-1996-1671, Existing plant configuration of RCIC turbine exhaust line vacuum

breaker vent line does not correspond with configuration assumed in Calculation PH-56,

Revision 0

Calculation PH-56, RCIC Turbine Exhaust Line Vacuum Breaker Vent Line Sizing

Verification, Revision 1A, November 27, 1996

Piping and Instrument Drawing PID-27-06A, Reactor Core Isolation Cooling System,

Revision 42

Calculation G13.18.2.0-079, Determination of Quantity of Water Entering RCIC Turbine

Exhaust Line, May 11, 2005

Calculation G13.18.10.2*225, RCIC Fluid Transient Analysis - Water in Turbine Exhaust

Line, May 17, 2005

ER-RB-2005-0084-000, Replace Check Valve E51-VF040 or Reinstall Internal Parts,

February 20, 2005

Terry Turbine SAM-12, Terry Wheel Water Slug Test, March 1, 1973

Section 1EP2: Alert and Notification System Testing

River Bend Station Emergency Plan, Revision 28

River Bend Station Prompt Notification System Design Report, Revision 1,

December 2001

Section 1EP3: Emergency Response Organization Augmentation Testing

Evaluation Reports for Pager and Augmentation Tests conducted:

February 10, 2004

June 17, 2004

August 24, 2004

September 23, 2004

December 8, 2004

January 25, 2005

March 22, 2005

July 25, 2005

September 27, 2005

Section 1EP5: Correction of Emergency Preparedness Weaknesses and Deficiencies

Procedures

EN-LI-118, Root Cause Analysis Process, Revision 1

EN-LI-119, Apparent Cause Evaluation Process, Revision 3

A-5

Attachment

Quality Assurance

Quality Assurance Audit Report, QA-7-2003-RBS-1

Quality Assurance Audit Report, QA-7-2004-RBS-1

Quality Assurance Audit Report, QA-7-2005-RBS-1

Condition Reports

Evaluation Reports for Drills conducted

September 3, 2003

March 2 2004

April 20, 2004

May 25, 2004

June 9, 2004

July 27, 2004

December 1, 2004 (simulator)

December 1, 2004 (medical)

March 24, 2005

April 19, 2005

June 21, 2005

Licensee Self-Assessments

2004 Evaluated Exercise Pre-Assessment

LO-RLO-2004-00004 CA56, 2004 Long Range ERO Staffing Assessment

2005 Emergency Planning Program Assessment

Snapshot Assessment of RBS Siren System

Section 4OA1: Performance Indicator Verification

Procedures

EN-EP-201, Emergency Planning Performance Indicators, Revision 2

EPP-2-703, Performance Indicators, Revision 2

EIP-2-001, Classification of Emergencies, Revision 12

EIP-2-002, Classification Actions, Revision 24

EIP-2-006, Notifications, Revision 32

EIP-2-007, Protective Action Recommendation Guidelines, Revision 20

EIP-2-007, Protective Action Recommendation Guidelines, Revision 21

A-6

Attachment

Section 2OS2: ALARA Planning and Controls

Condition Reports

CR-RBS-2005-01472

CR-RBS-2005-01474

CR-RBS-2005-02076

CR-RBS-2005-02558

CR-RBS-2005-03382

CR-RBS-2005-04004

Audits and Self-Assessments

QA-14-2005-RBS-1

Quality Assurance Audit of Radiation Protection Snapshot

Assessment /Benchmark on: Effectiveness of the RP TAC/TRG

(July 11-13, 2005)

QS-2005-RBS-009

ALARA Planning and Controls (August 22 through

September 1, 2005)

LO#2005-00123

Radiation Protection Program (July 11-15, 2005)

Radiation Work Permits

2005-1073

Change out filter elements LWS-SKD5-F100A

2005-1110

Clean-up FB 113' cask pool and install cask pool impact limiter

2005-1310

Recirc Flow Control Valve Maintenance

Procedures

ENS-RP-105 Radiation Work Permits, Revision 7

RP-110

ALARA Program, Revision 2

ALARA Committee Minutes

AMC 05-01

January 11, 2005

AMC 05-02

January 12, 2005

AMC 05-03

January 17, 2005

AMC 05-11

July 14, 2005

Section 4OA2: Identification and Resolution of Problems

Condition reports

CR-RBS-2005-02481

CR-RBS-2005-02494

CR-RBS-2005-02563

CR-RBS-2005-02590

CR-RBS-2005-02621

CR-RBS-2005-02626

A-7

Attachment

CR-RBS-2005-02649

CR-RBS-2005-02664

CR-RBS-2005-02693

CR-RBS-2005-02722

CR-RBS-2005-02727

CR-RBS-2005-02754

CR-RBS-2005-02767

CR-RBS-2005-03106

CR-RBS-2005-03114

CR-RBS-2005-03131

CR-RBS-2005-03151

CR-RBS-2005-03165

CR-RBS-2005-03182

CR-RBS-2005-03242

CR-RBS-2005-03273

CR-RBS-2005-03443

CR-RBS-2005-03471

CR-RBS-2005-03503

CR-RBS-2005-03513

CR-RBS-2005-03554

CR-RBS-2005-03594

CR-RBS-2005-03629

CR-RBS-2005-03670

CR-RBS-2005-03728

CR-RBS-2005-03753

CR-RBS-2005-03831

CR-RBS-2005-03887

CR-RBS-2005-03948

CR-RBS-2005-04018

CR-RBS-2005-04071

CR-RBS-2005-04103

CR-RBS-2005-04118

A-8

Attachment

LIST OF ACRONYMS

ALARA

as low as is reasonably achievable

CFR

Code of Federal Regulations

CR

condition report

CR-RBS

River Bend Station condition report

EAL

emergency action level

FEMA

Federal Emergency Management Agency

FCV

flow control valve

HPU

hydraulic power unit

MC

manual chapter

LER

licensee event report

LCO

limiting condition for operation

LOCA

loss of coolant accident

NCV

noncited violation

NEI

Nuclear Energy Institute

NRC

U.S. Nuclear Regulatory Commission

RCIC

reactor core isolation cooling system

RCS

reactor coolant system

RR

reactor recirculation system

SOP

system operating procedures

STP

surveillance test procedure

TS

Technical Specification

USAR

Updated Safety Analysis Report

WO

work order

ML060450209

Text

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