ML070450249

IR 05000313-06-005 and 05000368-06-005 for Arkansas Nuclear One

ML070450249
Person / Time
Site:	Arkansas Nuclear
Issue date:	02/14/2007
From:	Clark J NRC/RGN-IV/DRP/RPB-E
To:	Forbes J Entergy Operations
References
IR-06-005
Download: ML070450249 (44)

See also: IR 05000313/2006005

Text

February 14, 2007

Jeffrey S. Forbes, Vice President,

Operations

Arkansas Nuclear One

Entergy Operations, Inc.

1448 S.R. 333

Russellville, Arkansas 72801-0967

SUBJECT: ARKANSAS NUCLEAR ONE - NRC INTEGRATED INSPECTION REPORT

05000313/2006005 AND 05000368/2006005

Dear Mr. Forbes:

On December 31, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an

inspection at your Arkansas Nuclear One, Units 1 and 2, facility. The enclosed integrated

report documents the inspection findings, which were discussed on January 17, 2007, and

again on February 8, 2007, with you and other members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and

compliance with the Commission's rules and regulations and with the conditions of your

licenses. The inspectors reviewed selected procedures and records, observed activities, and

interviewed personnel.

The report documents five self-revealing findings of very low safety significance (Green). Three

of these findings were determined to involve violations of NRC requirements. However,

because of the very low safety significance and because they are entered into your corrective

action program, the NRC is treating these findings as noncited violations consistent with

Section VI.A.1 of the NRC Enforcement Policy. If you contest these noncited 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 Arkansas Nuclear One,

Units 1 and 2, facility.

In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, its

enclosure, and your response (if any) will be made available electronically for public inspection

Entergy Operations, Inc.

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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 Web site at

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

Sincerely,

/RA/

Jeffrey A. Clark, Chief

Project Branch E

Division of Reactor Projects

Dockets: 50-313

50-368

Licenses: DPR-51

NPF-6

Enclosure:

NRC Inspection Report 05000313/2006005 and 05000368/2006005

w/Attachment: Supplemental Information

cc w/Enclosure:

Senior Vice President

& 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.

Arkansas Nuclear One

1448 S. R. 333

Russellville, AR 72802

Director, Nuclear Safety Assurance

Entergy Operations, Inc.

Arkansas Nuclear One

1448 S. R. 333

Russellville, AR 72802

Entergy Operations, Inc.

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Manager, Licensing

Entergy Operations, Inc.

Arkansas Nuclear One

1448 S. R. 333

Russellville, AR 72802

Director, Nuclear Safety & Licensing

Entergy Operations, Inc.

1340 Echelon Parkway

Jackson, MS 39213-8298

Section Chief, Division of Health

Radiation Control Section

Arkansas Department of Health and

Human Services

4815 West Markham Street, Slot 30

Little Rock, AR 72205-3867

Section Chief, Division of Health

Emergency Management Section

Arkansas Department of Health and

Human Services

4815 West Markham Street, Slot 30

Little Rock, AR 72205-3867

Manager, Washington Nuclear Operations

ABB Combustion Engineering Nuclear

Power

12300 Twinbrook Parkway, Suite 330

Rockville, MD 20852

County Judge of Pope County

Pope County Courthouse

100 West Main Street

Russellville, AR 72801

James Mallay

Director, Regulatory Affairs

Framatome ANP

3815 Old Forest Road

Lynchburg, VA 24501

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 (RWD)

Branch Chief, DRP/E (ZKD)

Senior Project Engineer, DRP/E (VGG)

Team Leader, DRP/TSS (RLN1)

RITS Coordinator (MSH3)

DRS STA (DAP)

D. Cullison, OEDO RIV Coordinator (DGC)

ROPreports

ANO Site Secretary (VLH)

SUNSI Review Completed: _JAC__ ADAMS: / Yes No Initials: __JAC____

/ Publicly Available G Non-Publicly Available G Sensitive

/ Non-Sensitive

R:\\_REACTORS\\_ANO\\2006\\AN2006-05RP-RWD.wpd

RIV:RI:DRP/E

RI:DRP/E

SRI:DRP/E

C:DRS/OB

CHYoung

JEJosey

RWDeese

ATGody

T-JAC

T-JAC

T-JAC

/RA/

2/5/2007

2/5/2007

2/5/2007

2/4/2007

C:DRS/PSB

C:DRS/EB1

C:DRS/EB2

C:DRP/E

MPShannon

WBJones

LJSmith

JAClark

/RA/

/RA/

/RA/

/RA/

2/5/2007

2/1/2007

2/1/2007

2/14/2007

OFFICIAL RECORD COPY

T=Telephone E=E-mail F=Fax

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Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Dockets:

50-313, 50-368

Licenses:

DPR-51, NPF-6

Report:

05000313/2006005 and 05000368/2006005

Licensee:

Entergy Operations, Inc.

Facility:

Arkansas Nuclear One, Units 1 and 2

Location:

Junction of Hwy. 64W and Hwy. 333 South

Russellville, Arkansas

Dates:

September 24 through December 31, 2006

Inspectors:

L. Carson II, Senior Health Physicist, Plant Support Branch

R. Deese, Senior Resident Inspector

J. Josey, Resident Inspector

J. Kirkland, Project Engineer

R. Lantz, Senior Emergency Preparedness Inspector

D. Livermore, Senior Project Engineer

C. Paulk, Senior Reactor Inspector

C. Young, Resident Inspector

Accompanying

Personnel:

S. Makor, Reactor Inspector

Approved By:

Jeffrey A. Clark, Chief, Project Branch E

Division of Reactor Projects

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Enclosure

TABLE OF CONTENTS

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

1R01

Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

1R02

Evaluation of Changes, Tests, or Experiments . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R04

Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R05

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

1R07

Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

1R08

Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

1R11

Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1R12

Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1R13

Maintenance Risk Assessments and Emergent Work Control . . . . . . . . . . . . . 14

1R15

Operability Evaluations

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

1R17

Permanent Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

1R19

Postmaintenance Testing

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

1R20

Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

1R22

Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

1EP4

Emergency Action Level and Emergency Plan Changes . . . . . . . . . . . . . . . . . 22

1EP6

Drill Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

2OS1 Access Control To Radiologically Significant Areas . . . . . . . . . . . . . . . . . . . . . 23

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

4OA1 PI Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

4OA3 Followup of Events and Notices of Enforcement Discretion . . . . . . . . . . . . . . 28

4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

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-9

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Enclosure

SUMMARY OF FINDINGS

IR 05000313/2006005, 05000368/2006005; 09/24/2006 - 12/31/2006; Arkansas Nuclear One,

Units 1 and 2; Fire Protection, Operability Evaluations, Refueling and Outage Activities, Follow-

up of Events and Notices of Enforcement Discretion.

This report covered a 3-month period of inspection by resident and regional specialist

inspectors. Five Green findings, three of which were noncited violations were identified. The

significance of most findings is indicated by their color (Green, White, Yellow, or Red) using

Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the

significance determination process does not apply may be Green or be assigned a severity

level after NRC management's 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. A self-revealing noncited violation of Unit 2 Technical Specification 6.4.1.c, Fire Protection Program Implementation, was identified for

the failure of maintenance personnel to follow Procedure EN-DC-127, Control of

Hot Work and Ignition Sources, while performing hot work. Specifically, the

licensee failed to ensure that combustible material within 35 feet of the work area

was removed or protected. Consequently, torch cutting activities near the Unit 2

containment sump strainer caused a nearby plastic bag containing used

protective clothing to ignite. This issue was entered into the licensee's

corrective action program as Condition Reports ANO-2-2006-1565 and Condition

Report ANO-2-2006-1701. A number of additional examples of hot work

activities that involved inadequate implementation of applicable hot work control

procedures were also identified.

The finding is greater than minor because it is associated with the protection

against external factors attribute of the initiating events cornerstone, and it

directly affects the cornerstone objective to limit the likelihood of those events

that upset plant stability and challenge critical safety functions during shutdown

as well as power operations. Additionally, if left uncorrected, the practice of

conducting hot work in a manner that results in unintended combustion of nearby

materials would become a more significant safety concern in that it could result

in a fire in or near other risk important equipment. The finding is not suitable for

evaluation with the significance determination process neither the fire protection

significance determination process nor the shutdown operations significance

determination process address shutdown fire protection findings. However, the

finding is determined to be of very low safety significance by NRC managements

review because the finding occurred while the unit was already in a cold

shutdown condition, and the operability of equipment necessary to maintain safe

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Enclosure

shutdown was not challenged. The cause of the finding is related to the

crosscutting element of human performance associated with work practices

because the fire watch failed to use error prevention techniques like self

checking and peer checking which would have prevented the event

(Section 1R05).

Green. A self-revealing noncited violation of Unit 2 Technical Specification 6.4.1.a, Procedures, was identified when an operator failed to

close Valve 2DCH-11, resin sluice header drain valve, when securing from a

resin transfer as required by procedure. One week later, while aligning the plant

for alternate purification with Valve 2DCH-11 being out of position, an

unanticipated loss of approximately 230 gallons of reactor coolant system

inventory occurred. This issue was entered into the licensee's corrective action

program as Condition Report ANO-2-2006-1464.

The finding was determined to be more than minor because it affected the

configuration control attribute of the initiating events cornerstone objective to limit

the likelihood of those events that upset plant stability and challenge critical

safety functions during shutdown as well as power operations. Using the

shutdown operations significance determination process, the finding was

determined to have very low safety significance because the finding did not

result in a loss of 2 feet or more of reactor coolant system inventory and did not

result in a loss of reactor coolant system inventory while in reduced inventory.

The cause of the finding is related to the crosscutting element of human

performance associated with work practices because the operator failed to use

error prevention techniques like self checking and peer checking which would

have prevented the event (Section 1R20).

Green. A self-revealing finding was identified associated with the licensees

practice of using a hammer to remove the main hook pin on the Unit 2 polar

crane. Specifically, the license failure to provide clear guidance and training

resulted in station personnel cold working by the main hook and load cell pins

and this practice resulted in both pins being deformed and not usable with

reactor vessel level lowered to just below reactor vessel flange level. As a result,

Unit 2 was exposed to an increased period of elevated likelihood of a loss of

decay heat removal while the unit remained in a lowered vessel level condition

for an additional unplanned 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br />. This issue was entered into the licensee's

corrective action program as Condition Report ANO-2-2006-1553.

The finding was determined to be more than minor because it affected the

equipment performance attribute of the initiating events cornerstone objective to

limit the likelihood of those events that upset plant stability and challenge critical

safety functions during shutdown as well as power operations. This finding was

determined to be a finding of very low safety significance using the shutdown

operations significance determination process because the event did not involve

a loss of shutdown control or a reduction in mitigation capability which would

have increased the frequency of occurrence of a loss of decay heat removal.

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Enclosure

The cause of this finding is related to the crosscutting element of human

performance associated with resources because the training of personnel and

procedural guidance available was adequate (Section 1R20).

Green. A self-revealing finding was identified when the Unit 1 main feedwater

Pump A tripped, resulting in a plant run back to 40 percent reactor power. The

trip occurred due to electromagnetic interference from an air conditioning unit

recently installed on top of the main feedwater pump cabinet. This interference

caused an overspeed trip signal on the digital speed monitor for the main

feedwater pump turbine when no such actual condition occurred. This issue was

entered into the licensee's corrective action program as Condition

Report ANO-1-2006-1399.

The finding was determined to be more than minor because it affected the

design control attribute of the initiating events cornerstone objective to limit the

likelihood of those events that upset plant stability and challenge critical safety

functions during shutdown as well as power operations. Using Manual

Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the

finding is determined to have very low safety significance because the condition

only affected the initiating events cornerstone and did not contribute to both the

likelihood of a reactor trip and the likelihood that mitigation equipment or

functions will not be available. The finding had crosscutting aspects in the area

of problem identification and resolution associated with operating experience

because the licensees failure to implement and institutionalize OE through

changes to station processes and procedures (Section 4OA3).

Cornerstone: Mitigating Systems

Green. A self-revealing noncited violation of ANO Unit 2 License

Condition 2.C.(3)(b), Fire Protection, was identified for failure of the licensee to

maintain the lube oil collection system for Reactor Coolant Pumps C and D in an

operable condition. Specifically, the licensee failed to perform a modification on

the motor installed on Reactor Coolant Pump C which resulted in the oil

collection tank and its associated overfill berm being filled with water from the

component cooling water system. This issue was entered into the licensee's

corrective action program as Condition Report ANO-2-2006-1407.

The finding was determined to be more than minor because it affected the

protection against external factors attribute of the mitigating systems cornerstone

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

respond to initiating events to prevent undesirable consequences. Using the fire

protection significance determination process, the finding is determined to have

very low safety significance because the condition constituted a low degradation

of a fire prevention and administrative controls feature (Section 1R15).

B.

Licensee-Identified Violations

None.

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Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent rated thermal power (RTP) and remained

there until November 9, 2006, when a trip of the Main Feedwater Pump A occurred due to a

malfunction associated with the electronic overspeed trip device. The trip resulted in an

automatic runback to 40 percent RTP. Unit 1 returned to 100 percent RTP on

November 10 and remained there for the remainder of the inspection period.

Unit 2 began the inspection period with the reactor shut down for Refueling Outage 2R18.

Following the refueling outage, the Unit 2 reactor achieved criticality on October 27 and main

generator output breakers were closed on October 28. Approximately 67 percent RTP was

achieved on October 30 when the unit performed a Technical Specification (TS) required

shutdown to hot standby in response to a fire in 480-volt Motor-Control Center 2B-53. Unit 2

was restarted, and main generator output breakers were closed on November 1. The unit

achieved 100 percent RTP on November 3 and remained there for the remainder of the

inspection period.

1.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01

Adverse Weather Protection (71111.01)

.1

Readiness for Impending Adverse Weather Conditions

On November 30 the inspectors completed a review of the licensee's readiness for

impending adverse weather involving icy weather. The inspectors: (1) reviewed plant

procedures, the Updated Final Safety Analysis Reports (UFSAR), and TSs to ensure

that operator actions defined in adverse weather procedures maintained the readiness

of essential systems; (2) walked down portions of the below listed two systems to

ensure that adverse weather protection features (heat tracing, space heaters,

weatherized enclosures, temporary chillers) were sufficient to support operability,

including the ability to perform safe shutdown functions; (3) reviewed maintenance

records to determine that applicable surveillance requirements were current before the

anticipated ice storm developed; and (4) reviewed plant modifications, procedure

revisions, and operator work arounds to determine if recent facility changes challenged

plant operation.

C

November 30, 2006, Units 1 and 2, offsite electrical distribution systems

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

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Enclosure

1R02

Evaluation of Changes, Tests, or Experiments (71111.02)

a.

Inspection Scope

The inspectors reviewed the effectiveness of the licensees implementation of changes

to the facility structures, systems, and components (SSCs); risk-significant normal and

emergency operating procedures; test programs; and the UFSAR in accordance with

10 CFR 50.59, Changes, Tests, and Experiments. The inspectors reviewed the safety

evaluations performed by the licensee dealing with the Unit 2 pressurizer replacement.

The evaluations were reviewed to verify that licensee personnel had appropriately

considered the conditions under which the licensee may make changes to the facility or

procedures or conduct tests or experiments without prior NRC approval. Procedures,

evaluations, screenings, and applicability determinations reviewed are listed in the

attachment to this report.

b.

Findings

No findings of significance were identified.

1R04

Equipment Alignment (71111.04)

.1

Partial Walkdown

The inspectors: (1) walked down portions of the two below listed risk important systems

and reviewed plant procedures and documents to verify that critical portions of the

selected systems were correctly aligned, and (2) compared deficiencies identified during

the walkdown to the licensees UFSAR and corrective action program (CAP) to ensure

problems were being identified and corrected.

October 3, 2006, Unit 1, Emergency Diesel Generator (EDG) K-4A

December 13, 2006, Unit 1, reactor building spray system Train A

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b.

Findings

No findings of significance were identified.

1R05

Fire Protection (71111.05)

.1

Quarterly Inspection

The inspectors walked down the six below listed plant areas to assess the material

condition of active and passive fire protection features and their operational lineup and

readiness. The inspectors: (1) verified that transient combustibles and hot work

activities were controlled in accordance with plant procedures; (2) observed the

condition of fire detection devices to verify they remained functional; (3) observed fire

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Enclosure

suppression systems to verify they remained functional and that access to manual

actuators was unobstructed; (4) verified that fire extinguishers and hose stations were

provided at their designated locations and that they were in a satisfactory condition;

(5) verified that passive fire protection features (electrical raceway barriers, fire doors,

fire dampers steel fire proofing, penetration seals, and oil collection systems) were in a

satisfactory material condition; (6) verified that adequate compensatory measures were

established for degraded or inoperable fire protection features and that the

compensatory measures were commensurate with the significance of the deficiency;

and (7) reviewed the UFSAR to determine if the licensee identified and corrected fire

protection problems.

September 25, 2006, Unit 2, Fire Zone 2032-K, containment building (south side)

October 17, 2006, Unit 1, Fire Zone 98-J, EDG access corridor

December 13, 2006, Unit 1, Fire Zones 4-EE, 12-EE, and 14-EE, Elevation 317

feet of the auxiliary building, west decay heat removal pump room

December 26, 2006, Unit 2, Fire Zone 2040-JJ, access corridor; charging pump;

radwaste and boron management system area

December 27, 2006, Unit 1, Fire Zone 67-U, lab and demineralizer access area

December 27, 2006, Unit 1, Fire Zone 79-U, upper north piping penetration room

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b.

Findings

Introduction. A self-revealing, Green noncited violation of TS 6.4.1.c was identified for

the licensees failure to adequately implement their procedure for the control of hot work

and ignition sources while performing hot work activities.

Description. On September 25, 2006, hot work activities were being performed on the

Unit 2 containment sump strainer. A plastic bag was being utilized at a nearby step-off

pad at the high contamination area boundary as a receptacle for used protective

clothing. While torch cutting on the west containment sump strainer door was in

progress, sparks from the activity caused the plastic bag to ignite. The inspectors

identified the fire to the firewatch, who was in the vicinity. The bag was extinguished by

smothering soon thereafter by the workers that were involved in the hot work activity.

Procedure EN-DC-127, Control of Hot Work and Ignition Sources, Revision 2, requires

that combustible material within 35 feet of the work area that could become ignited from

the hot work shall be removed or protected. Procedure EN-DC-127, Attachment 9.1,

Hot Work Permit, was issued for this activity and showed that this requirement to be

checked off by the hot work supervisor as being completed. The inspectors noted that

the bag was within 35 feet of the work area and had not been removed.

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Enclosure

Corrective actions that were taken by the licensee in response to this event to prevent

recurrence included: moving the step-off pad farther away from the work area, clearing

the area near the door of unnecessary equipment and materials, coaching the firewatch

and his supervisor concerning the responsibility of the firewatch and how to deal with

distractions, discussing alternatives to more effectively contain sparks from the cutting

operation, discussing the event with craft personnel, and conducting more frequent area

inspections.

A number of additional deficiencies were identified through a review of recent licensee

performance in the conduct of related hot work activities. Section 4OA2 of this

enclosure contains some details of other instances that occurred during the Unit 2

Refueling Outage 2R18. Also, three examples involving circumstances similar to the

subject of this finding occurred during the prior refueling outages for each of the two

units. On March 25, 2005, fallen welding slag caused the smoldering of debris below

Containment Cooler D inside the Unit 2 containment building. On September 29 torch

cutting resulted in falling hot metal and slag that caused combustible materials in the

work area to catch on fire. On October 14 three small fires of trash bags containing

combustible materials in the Unit 1 turbine building basement were caused by hot work

activities that were being performed on the levels above. There was no firewatch posted

on the basement level.

Each of these instances was entered into the licensees CAP. These occurrences

represent instances of inadequate implementation of applicable hot work control

procedures. The inspectors concluded that the recent increase in the number of related

findings when compared to past occurrences represented a trend which, if left

uncorrected, could become a more significant safety concern in that it could result in a

fire in or near risk important equipment.

Analysis. The performance deficiency associated with this finding involved the failure of

maintenance personnel to adequately implement the licensees procedure for control of

hot work and ignition sources. The finding is greater than minor because it is

associated with the protection against external factors attribute 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 during shutdown as well

as power operations. Additionally, if left uncorrected, the practice of conducting hot

work in a manner that results in unintended combustion of nearby materials would

become a more significant safety concern in that it could result in a fire in or near risk

important equipment. Manual Chapter (MC) 0609, Significance Determination

Process, Appendix F, Fire Protection Significance Determination Process, does not

address the potential risk significance of shutdown fire protection findings. Additionally,

MC 0609, Appendix G, Shutdown Operations Significance Determination Process,

does not address fire protection findings. Thus, the finding is not suitable for

significance determination process evaluation, but has been reviewed by NRC

management and is determined to be of very low safety significance because the finding

occurred while the unit was already in a cold shutdown condition; and the operability of

equipment necessary to maintain safe shutdown was not challenged. The cause of the

finding is related to the crosscutting element of human performance in that maintenance

personnel failed to follow procedures.

-10-

Enclosure

Enforcement. Unit 2 TS 6.4, Procedures, requires that written procedures be

established, implemented, and maintained covering fire protection program

implementation. Procedure EN-DC-127, Control of Hot Work and Ignition Sources, is

one of those procedures and requires that combustible material within 35 feet of the

work area that could become ignited from the hot work shall be removed or protected.

Contrary to this, on September 25, 2006, maintenance personnel failed to remove or

protect combustible material within 35 feet of the work area. Because the finding is of

very low safety significance and has been entered into the licensees CAP as Condition

Reports (CRs) ANO-2-2006-1565 and CR ANO-2-2006-1701, this violation is being

treated as an NCV consistent with Section VIA of the Enforcement Policy:

NCV 05000368/2006005-01, Fire During Hot Work Activities on the Containment Sump

Strainer.

1R07

Heat Sink Performance (71111.07)

a.

Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry

standards, and reviewed critical operating parameters and maintenance records for the

Unit 1 EDG A cooling water heat exchanger. The inspectors verified that:

(1) performance tests were satisfactorily conducted for heat enchanters/heat sinks and

reviewed for problems or errors; (2) the licensee utilized the periodic maintenance

method outlined in EPRI NP-7552, Heat Exchanger Performance Monitoring

Guidelines; (3) the licensee properly utilized befalling controls; (4) the licensees heat

exchanger inspections adequately assessed the state of cleanliness of their tubes; and

(5) the heat exchanger was correctly categorized under the Maintenance Rule.

September 5, 2006, Unit 1 EDG A cooling water heat exchanger

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b.

Findings

No findings of significance were identified.

1R08

Inservice Inspection Activities (71111.08)

Inspection Procedure 71111.08 requires four samples size as identified in

Sections 02.01, 02.02, 02.03, and 02.04.

-11-

Enclosure

a.

Inspection Scope

.1

Performance of Nondestructive Examination (NDE) Activities Other than Steam

Generator Tube Inspections, Pressurized Water Reactor (PWR) Vessel Upper Head

Penetration Inspections, Boric Acid Corrosion Control

The inspection procedure requires the review of NDE activities consisting of two or three

different types (i.e., volumetric, surface, or visual). The inspectors observed the

performance of three ultrasonic examinations (volumetric) (one on a section of service

water piping for wall thickness and two on field welds in the pressurizer spray line). The

inspectors also reviewed the radiographic examinations (volumetric) of the two spray

line welds. (The welds are identified in the attachment to this report.)

For each of the observed NDE activities, the inspectors verified that the examinations

were performed in accordance with the specific site procedures and the applicable

American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME

Code) requirements.

During review of each examination, the inspectors verified that appropriate

NDE procedures were used, examinations and conditions were as specified in the

procedure, and test instrumentation or equipment was properly calibrated and within the

allowable calibration period. The inspectors also verified the NDE certifications of the

personnel who performed the above volumetric examinations. Finally, the inspectors

observed that indications identified during the radiographic examinations were

dispositioned in accordance with the ASME Code-qualified NDE procedures used to

perform the examinations.

The inspection procedure requires review of one or two examinations with recordable

indications that were accepted for continued service to ensure that the disposition was

made in accordance with the ASME Code. The inspectors were informed that no

indications exceeding ASME Code allowables were known to be in service.

The inspection procedure further requires verification of one to three welds on Class 1

or 2 pressure boundary piping to ensure that the welding process and welding

examinations were performed in accordance with the ASME Code. The inspectors

observed welding performed on a safety injection system valve in the prefabrication

shop. The inspectors verified that the welding was performed in accordance with

Sections IX and XI of the ASME Code. This included review of welding material issue

slips to establish that the appropriate welding materials had been used and verification

that the welding procedure specification (WPS E-P8-T-A8,Ar, Manual Gas Tungsten

Arc Welding (GTAW) of P-No. 8 Stainless Steels, Revision 0) had been properly

qualified.

The inspectors completed the one sample required by Section 02.01.

.2

Reactor Vessel Upper Head Penetration Inspection Activities

The inspection requirements for this section parallel the inspection requirement steps in

Section 02.01. The inspectors observed the NDEs on nine reactor vessel upper head

-12-

Enclosure

penetrations. There were eight control element drive mechanism penetrations (Nos. 12,

21, 58, 59, 60, 61, 72, and 79) and one incore instrumentation penetration (No. 82).

The inspectors verified that the nondestructive activities were performed in accordance

with the requirements of NRC Order EA-03-009. The NDEs performed during the NRC

inspection did not reveal any defects or indications.

The inspectors completed the one sample required by Section 02.02.

.3

Boric Acid Corrosion Control Inspection Activities (PWRs)

The inspectors evaluated the implementation of the licensees boric acid corrosion

control program for monitoring degradation of those systems that could be deleteriously

affected by boric acid corrosion. The inspection procedure requires review of a sample

of boric acid corrosion control walkdown visual examination activities through either

direct observation or record review. The inspectors reviewed the documentation

associated with the licensees boric acid corrosion control walkdown. Additionally, the

inspectors performed independent observations of piping containing boric acid during

walkdowns of the containment building and the auxiliary building.

The inspection procedure requires verification that visual inspections emphasize

locations where boric acid leaks can cause degradation of safety significant

components. The inspectors verified through direct observation and program/record

review that the licensees boric acid corrosion control inspection efforts are directed

towards locations where boric acid leaks can cause degradation of safety-related

components.

The inspection procedure requires both a review of one to three engineering evaluations

performed for boric acid leaks found on reactor coolant system (RCS) piping and

components and one to three corrective actions performed for identified boric acid

leaks. The licensee had identified a boric acid leak on the containment spray header

during an inspection for materials that could come loose and clog the sump screens

during a loss-of-coolant accident or steam line rupture inside containment. The

inspectors reviewed the licensees analysis of the condition to evaluate the assessment

of the condition and proposed corrective actions.

The inspectors completed the one sample required by Section 02.03.

.4

Steam Generator Tube Inspection Activities

There were no steam generator tube inspections performed during this outage. The

inspectors reviewed Evaluation ER-2005-0469-001, Operational Assessment of ANO-2

Steam Generator Tubing for Cycles 18-20, dated August 31, 2006. The evaluation

concluded that no tube examinations were required to be performed during

Cycles 18-20. The inspectors noted that the basis was the condition of the tubes from

the previous inspections that were performed after the steam generators were replaced.

This sample was not completed because there was no activity to observe.

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Enclosure

.5

Identification and Resolution of Problems

The inspection procedure requires review of a sample of problems associated with

inservice inspections documented by the licensee in the CAP for appropriateness of the

corrective actions. The inspectors reviewed three CRs, which dealt with inservice

inspection and welding activities. From this review, the inspectors concluded that the

licensee has 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.

1R11

Licensed Operator Requalification Program (71111.11)

a.

Inspection Scope

On December 14, 2006, the inspectors observed testing and training of Unit 1 senior

reactor operators and reactor operators to identify deficiencies and discrepancies in the

training, to assess operator performance, and to assess the evaluator's critique. The

training was a simulator training scenario.

Documents reviewed by the inspectors included:

ANO Unit 1 Dynamic Exam Scenario SES-1-008, Revision 5

The inspectors completed one sample.

b.

Findings

No findings of significance were identified.

1R12

Maintenance Effectiveness (71111.12)

a.

Inspection Scope

The inspectors reviewed the two below listed maintenance activities to: (1) verify the

appropriate handling of SSCs performance or condition problems; (2) verify the

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

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

issues reviewed under the requirements of the Maintenance Rule, 10 CFR Part 50,

Appendix B, and TSs.

November 28, 2006, Unit 1, turbine building ventilation

December 5, 2006, Unit 2, 480-volt electrical distribution

Documents reviewed by the inspectors are listed in the attachment.

-14-

Enclosure

The inspectors completed two samples.

b.

Findings

No findings of significance were identified.

1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13)

.1

Risk Assessment and Management of Risk

a.

Inspection Scope

Risk Assessment and Management of Risk

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

(1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and

licensee procedures prior to changes in plant configuration for maintenance activities

and plant operations; (2) the accuracy, adequacy, and completeness of the information

considered in the risk assessment; (3) that the licensee recognizes, and/or enters as

applicable, the appropriate licensee-established risk category according to the risk

assessment results and licensee procedures; and (4) that the licensee identified and

corrected problems related to maintenance risk assessments.

September 19 through October 27, 2006, Unit 2, pressurizer replacement

September 19 through October 27, 2006, Unit 2, containment sump modification

November 13-17, 2006, Unit 1, planned maintenance for the week

November 27 through December 1, 2006, Unit 1, planned maintenance for the

week

December 4-8, 2006, Unit 2, planned maintenance for the week

December 11-15, 2006, Unit 1, planned maintenance for the week

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b.

Findings

No findings of significance were identified.

-15-

Enclosure

1R15

Operability Evaluations (71111.15)

a.

Inspection Scope

The inspectors: (1) reviewed plants status documents, such as operator shift logs,

emergent work documentation, deferred modifications, and standing orders, to

determine if an operability evaluation was warranted for degraded components;

(2) referred to the UFSAR and design basis documents to review the technical

adequacy of licensee operability evaluations; (3) evaluated compensatory measures

associated with operability evaluations; (4) determined degraded component impact on

any TSs; (5) used the significance determination process to evaluate the risk

significance of degraded or inoperable equipment; and (6) verified that the licensee has

identified and implemented appropriate corrective actions associated with degraded

components.

September 22, 2006, Unit 2, reactor coolant pump (RCP) oil collection system

October 3, 2006, Unit 2, Electrical Bus 2B-5

October 28, 2006, Unit 2, containment spray header

December 19, 2006, Unit 2, containment sump

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b.

Findings

Introduction. A Green self-revealing noncited violation of the Unit 2 license condition for

fire protection was identified for failure of the licensee to maintain the RCP oil collection

system for RCPs C and D in an operable condition. Specifically, the licensee failed to

perform a modification on the motor installed on RCP C, which resulted in the oil

collection tank and its associated overfill berm filling up and overflowing with water from

the component cooling water (CCW) system.

Description. On September 20, 2006, while the licensee was conducting a hot

shutdown walkdown in containment during the start of Refueling Outage 2R18, the

licensee discovered that the RCP oil collection system drain tank for RCPs C and D,

(2T-110) and its associated overfill berm were filled and overflowing with water. The

licensee determined that the drain tank and associated berm were inoperable because

the licensee could not perform their intended function of providing a collection and

holding point for possible oil leakage from RCPs C and D.

The licensee obtained a sample of the water and determined that it was from the CCW

system. Based on this, the licensee then identified and performed inspections of all

interface points of the CCW system with the RCP oil collection system. During this

inspection, two leakage points were identified: the outlet flange of lube oil

Cooler 2E-25D, and the interface of the threaded supply and return piping nipples for

the lower bearing oil cooler on RCP C. The leakage from the lower bearing oil cooler

was determined to be the source that was leaking into the oil collection system through

the drip pans below the motor.

-16-

Enclosure

During their investigation to determine the cause of this failure, the licensee identified

the cause of the leakage to be fatigue at the root diameter of the threaded schedule

40 pipe nipple. They also determined that this type of failure had previously occurred on

the motor installed on RCP B in December of 1995. This failure was documented in

CR ANO-2-1995-0555 and was also determined to be due to fatigue at the root diameter

of the threaded schedule 40 pipe nipple. The licensee determined, during their review

of the RCP B failure of December 1995, that Modification PEAR 9-0330, Revision 1, had

been developed and implemented to replace the schedule 40 threaded pipe nipple on

the RCPs with schedule 80 threaded pipe nipples. This modification was performed on

the motors of all installed RCPs but not the Unit 2 spare motor. Completion of the

modification on the spare RCP motor was to be accomplished during motor

refurbishment; however, the modification was never performed. In 2005 during

Refueling Outage 2R17, the spare RCP motor was installed as the RPC C motor without

the modification.

In reviewing this issue, the inspectors noted that the licensee had trend data for the

volume of oil in RCPs C and D which indicated that oil volume in RCPs C and D had

gone down over the cycle. The inspectors determined through interviews that this oil

was not contained in the oil collection system or the overflow berm as per design but

had most likely overflowed the berm and gone to the containment sump via the floor

drain system. During the operating cycle, the sump had been pumped to the auxiliary

building for processing.

Analysis. The inspectors determined that the failure to maintain the oil collection system

drain tank for RCPs C and D in an operable condition was a performance deficiency.

The finding was determined to be more than minor because it affected the protection

against external factors attribute of the mitigating systems cornerstone objective to

ensure the availability, reliability, and capability of systems that respond to initiating

events to prevent undesirable consequences. Using MC 0609, Significance

Determination Process, Phase 1 Worksheet, the finding is assumed to degrade fire

protection defense-in-depth strategies involving barriers; therefore, the significance of

the finding is determined by using Appendix F, Fire Protection Significance

Determination Process, of MC 0609. Using the Phase 1 Worksheet of Appendix F, the

inspectors assumed the condition represented a low degradation of the fire prevention

and administrative controls category since the oil collection would have kept oil from

contacting hot surfaces in the containment building. Additionally, the inspectors

assumed that no intervening combustibles were present between the overflow path and

adjacent fire areas and that the containment sump, to which the floor drains installed in

the area of the berm transported any oil that overflowed, lacked a significant ignition

source.

Enforcement. ANO Unit 2 License Condition 2.C.(3)(b), Fire Protection, states, in part,

that the licensee shall implement and maintain all provisions of the approved fire

protection program. ANO Unit 1 and Unit 2 - Fire Hazards Analysis, Revision 9, is part

of the ANO Unit 2 fire protection program. Section 6.4.5, Fire Barriers, Seals, and

Penetrations, of the Fire Hazards Analysis states, in part, that the fire barrier system at

ANO has been designed to ensure that fires will be confined or adequately retarded

from spreading to adjacent portions of the facility. Contrary to this, the filling to overflow

of the oil collection system tank and overflow berm with water from the CCW system

-17-

Enclosure

during Operating Cycle 18 prevented a potential RCP oil fire in the containment

basement from being confined per the fire protection program. Because the finding is of

very low safety significance and has been entered into the licensees CAP as

CR ANO-2-2006-1407, this violation is being treated as an NCV consistent with

Section VIA of the Enforcement Policy: NCV 05000368/2006005-02, Failure to Perform

Modification Resulted in an Inoperable RCP Oil Collection System.

1R17

Permanent Plant Modifications (71111.17)

.1

Annual Review

The inspectors reviewed key affected parameters associated with energy needs,

materials/replacement components, timing, heat removal, control signals, equipment

protection from hazards, operations, flowpaths, pressure boundary, ventilation

boundary, structural, process medium properties, licensing basis, and failure modes for

the modification listed below. The inspectors verified that: (1) modification preparation,

staging, and implementation does not impair emergency/abnormal operating procedure

actions, key safety functions, or operator response to loss of key safety functions;

(2) postmodification testing maintained the plant in a safe configuration during testing by

verifying that unintended system interactions will not occur, SSC performance

characteristics still meet the design basis, the appropriateness of modification design

assumptions, and the modification test acceptance criteria has been met; and (3) the

licensee has identified and implemented appropriate corrective actions associated with

permanent plant modifications.

September 19 through October 26, 2006, Unit 2, pressurizer replacement

1R19

Postmaintenance Testing (71111.19)

a.

Inspection Scope

The inspectors selected the six below listed postmaintenance test activities of risk

significant systems or components. For each item, the inspectors: (1) reviewed the

applicable licensing basis and/or design-basis documents to determine the safety

functions; (2) evaluated the safety functions that may have been affected by the

maintenance activity; and (3) reviewed the test procedure to ensure it adequately tested

the safety function that may have been affected. The inspectors either witnessed or

reviewed test data to verify that acceptance criteria were met, plant impacts were

evaluated, test equipment was calibrated, procedures were followed, jumpers were

properly controlled, the test data results were complete and accurate, the test

equipment was removed, the system was properly realigned, and deficiencies during

testing were documented. The inspectors also reviewed the UFSAR to determine if the

licensee identified and corrected problems related to postmaintenance testing.

October 17, 2006, Unit 1, Emergency Feedwater Pump P-7A

October 22, 2006, Unit 2, pressurizer heater capacity

October 24, 2006, Unit 2, replacement pressurizer relief valve monitor test

-18-

Enclosure

October 25, 2006, Unit 2, containment spray header repairs

October 27, 2006, Unit 2, replacement pressurizer leakage

November 1, 2006, Unit 2, containment building personnel hatch leakage rate

testing

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b.

Findings

No findings of significance were identified.

1R20

Refueling and Outage Activities (71111.20)

1.

Unit 2 Forced Outage Caused by Fire in Motor Control Center 2B-53

a.

Inspection Scope

The inspectors reviewed the following risk significant outage activities to verify defense

in depth commensurate with the outage risk control plan and compliance with the TSs:

(1) the risk control plan, (2) tagging/clearance activities, (3) heatup and cooldown

activities, and (4) restart activities.

The inspectors completed one sample.

b.

Findings

No findings of significance were identified.

2.

Refueling and Pressurizer Replacement Outage 2R18

a.

Inspection Scope

The inspectors reviewed the following risk significant refueling items or outage activities

to verify defense in depth commensurate with the outage risk control plan, compliance

with the TSs, and adherence to commitments in response to Generic Letter 88-17, Loss

of Decay Heat Removal: (1) the risk control plan, (2) tagging/clearance activities,

(3) RCS instrumentation, (4) electrical power, (5) decay heat removal, (6) spent fuel pool

cooling, (7) inventory control, (8) reactivity control, (9) containment closure, (10) reduced

inventory conditions, (11) refueling activities, (12) heatup and cooldown activities,

(13) restart activities, and (14) licensee identification and implementation of appropriate

corrective actions associated with refueling and outage activities. The inspectors

containment inspections included observation of the containment sump for damage and

debris, supports, braces, and snubbers for evidence of excessive stress, water hammer,

or aging.

-19-

Enclosure

The inspectors completed one sample.

b.

Findings

.1

Inadvertent RCS Draining While in Mode 5

Introduction. A Green self-revealing noncited violation of the licensees TS requirement

for procedures was identified when an operator failed to close a resin sluice header

drain valve as required by procedure. Later, while operators were aligning the unit for

alternate reactor coolant purification, a loss of approximately 230 gallons of RCS

inventory occurred.

Description. On September 14, 2006, operations personnel performed

Procedure OP-2104.019, Clean Resin Transfer, to add clean resin to Purification Ion

Exchanger 2T-36B. During this procedure, Valve 2DCH-11 was opened as part of the

system lineup. Subsequently, when the evolution was completed and the plant lineup

was being restored, station personnel failed to properly perform Step 22.2 of the

procedure leaving Valve 2DCH-11 in the open position.

Subsequently, on September 21, 2006, with Unit 2 in Mode 5, the licensee was in the

process of aligning alternate purification in accordance with Procedure OP-2104.004,

Shutdown Cooling System, Attachment J, Alternate Purification. When Step 2.11 of

this procedure was performed, the control room operators noted that pressurizer level

began to lower. The evolution was stopped and the lineup was secured. At this point,

pressurizer level stopped lowering. Station personnel performed a system walkdown

and discovered that Valve 2DCH-11 was in the open position. Operations personnel

determined that approximately 230 gallons were drained from the RCS through the open

valve.

During their review, the inspectors noted that Procedure OP-2104.004, Attachment J,

directed personnel to prepare a caution tag for components to prevent the loss of RCS

inventory. However, the procedure contained a note that preceded Step 1.11 which

directed the caution tag be hung on the room door instead of Valve 2DCH-11 and two

other valves. This tag stated that, since the valves were normally closed, any

misalignment would be detected by system abnormalities. The inspectors determined

that this note contributed to Valve 2DCH-11 not being discovered out of position prior to

initiating alternate purification since the licensee did not perform a valve lineup

verification.

Analysis. The failure of station personnel to manipulate Valve 2DCH-11 in accordance

with station procedure was determined to be a performance deficiency. The finding was

determined to be more than minor because it affected the configuration control attribute

of the initiating events cornerstone objective to limit the likelihood of those events that

upset plant stability and challenge critical safety functions during shutdown as well as

power operations. The inspectors used MC 0609, Significance Determination Process,

Appendix G, Shutdown Operations Significance Determination Process, and assumed

that the administrative controls implemented to avoid operations that could lead to

perturbations in RCS level control attribute was affected. The finding was determined to

have very low safety significance because the finding did not result in a loss of 2 feet or

-20-

Enclosure

more of RCS inventory and did not result in a loss of RCS inventory while the unit was in

reduced inventory. The cause of the finding is related to the crosscutting aspect of

human performance associated with work practices because the operator failed to use

error prevention techniques like self checking and peer checking which would have

prevented the event.

Enforcement. Unit 2 TS, Section 6.4.1.a, Procedures, requires, in part, that written

procedures shall be established, implemented, and maintained covering the applicable

procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,

February 1978. Procedure OP-2104.019, Clean Resin Transfer, is a procedure

required by Regulatory Guide 1.33. Contrary to the above, on September 14, 2006, the

licensee failed to fully implement Procedure OP-2104.019, Clean Resin Transfer,

when the licensee failed to close Valve 2DCH-11. Because this finding is of very low

safety significance and has been entered into the CAP as CR ANO-2-2006-1464, this

violation is being treated as an NCV, consistent with Section VIA of the NRC

Enforcement Policy: NCV 05000368/2006005-03, Inadvertent RCS Draining While in

Mode 5.

.2

Unplanned Increase in Time with Reactor Vessel Water Level at Flange Level

Introduction. A Green self-revealing finding was identified associated with the licensees

use of a hammer to remove and reinstall both the main hook pin and the load cell pin on

the Unit 2 polar crane. Unit 2 was maintained in a condition with reactor vessel water

level being maintained just below the reactor vessel flange for an additional unplanned

27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> when the pins could not be used due to deformation by the hammer.

Description. On September 24, 2006, station personnel were preparing the Unit 2 polar

crane for the reactor vessel closure head removal. This involved removing the normally

installed main hook, installing a load cell, and then reinstalling the main hook. During

performance of Procedure OP-2504.005, Reactor Vessel Closure Head Removal,

Revision 12, Step 7.22, licensee personnel were unable to easily remove the polar crane

main hook pin. After the pin was removed, it was examined by the licensee and

discovered to be mushroomed at one end. When the licensee inspected the pin used to

secure the load cell into place, it was discovered to be in the same condition. The

licensee determined this condition to be caused by the practice of using a hammer, as

necessary, to both remove and install the pins during previous refueling outages.

The inspectors noted that the licensee did not have a formal procedure that controlled

the removal and installation of the pins, and that station personnel were controlling this

evolution as a skill-of-the-craft process. A review of the applicable procedures by the

inspectors revealed that Procedure OP-2504.005, Step 7.22, Reactor Vessel Closure

Head Removal, simply states, Verify that the load cell is attached to the polar crane.

The inspectors also determined that the use of hammers was a common practice being

used to remove and reinstall the pins on the polar crane, and there was no existing

evaluation for the effects of this on the integrity of the pins. The inspectors determined

that the lack of adequate procedural direction and the practice of hammering the pins in

and out directly contributed to the deformation of the pins. Finally, the inspectors were

informed by licensee personnel that the practice of using hammers to remove the pins

-21-

Enclosure

was not part of the formal training received by maintenance personnel; however, in at

least one instance, a discussion between instructors and maintenance personnel

outside the formal lesson plan had occurred describing the practice of using hammers

as being acceptable.

Analysis. The inspectors determined that the licensees failure to provide clear guidance

and training on how to remove the main hook and load cell pins without causing damage

was a performance deficiency. The finding was determined to be more than minor

because it affected the equipment performance attribute of the initiating events

cornerstone objective to limit the likelihood of those events that upset plant stability and

challenge critical safety functions during shutdown as well as power operations. The

inspectors evaluated the finding using MC 0609, Significance Determination Process,

Appendix G, Shutdown Operations Significance Determination Process. The

inspectors determined that the finding was not a loss of shutdown control as defined by

MC 0609, Appendix G, Table 1, and then evaluated the issue using Checklist 3 of

MC 0609, Appendix G, Attachment 1. The inspectors determined that a quantitative

analysis was not required because the event did not represent a reduction in mitigation

capability which would have increased the frequency of occurrence of a loss of decay

heat removal. Therefore, the finding was determined to have very low safety

significance. The cause of the finding is related to the crosscutting element of human

performance associated with resources because the training of personnel and

procedural guidance available was adequate.

Enforcement. While a performance deficiency was identified, there were no violations of

NRC requirements identified during the review of this issue. The licensee has entered

this issue into the CAP as CR ANO-2-2006-1553: Finding (FIN)05000368/2006005-04,

Unplanned Increase in Time with Reactor Vessel Water Level at Flange Level.

1R22

Surveillance Testing (71111.22)

a.

Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that

the four below listed surveillance activities demonstrated that the SSCs tested were

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

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

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

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

controls; (7) test data; (8) testing frequency and method demonstrated TS operability;

(9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of ASME

Code requirements; (12) updating of performance indicator (PI) data; (13) engineering

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

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

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

implemented any needed corrective actions associated with the surveillance testing.

August 4, 2006, Unit 1, makeup system Valve MU-36A local leak rate test

October 5, 2006, Unit 2, main steam safety valve lifts (inservice test)

October 15, 2006, Unit 2, Valve 2SV-8271-2 local leak rate test

-22-

Enclosure

October 23, 2006, Unit 2, Containment Cooler A

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b.

Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

1EP4

Emergency Action Level and Emergency Plan Changes (71114.04)

a.

Inspection Scope

The inspector performed an in-office review of Revision 037-05-0 to Emergency Plan

Implementing Procedure OP-1903.010, Emergency Action Level Classification. The

revision was submitted in October 2006. The revision corrected emergency plan

guidance for transient event classification and notification practices at Arkansas Nuclear

One and was a corrective action for the NCV 05000313,368/2006003-02, Failure to

Meet Immediate Notification Requirements during Transient Events.

The revision was compared to the previous revision, to the criteria of NUREG-0654,

Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and

Preparedness in Support of Nuclear Power Plants, Revision 1; and NEI 99-01,

Methodology for Development of Emergency Action Levels, Revision 2; and to the

standards in 10 CFR 50.47(b) to determine if the revision was adequately conducted

following the requirements of 10 CFR 50.54(q). This review was not documented in a

safety evaluation report and did not constitute approval of licensee changes, therefore,

the revision is subject to future inspection.

The inspector completed one sample during the inspection.

b.

Findings

No findings of significance were identified.

1EP6

Drill Evaluation (71114.06)

a.

Inspection Scope

For the one below listed simulator-based training evolutions contributing to drill/exercise

performance, emergency response organization, and PIs, the inspectors: (1) observed

the training evolution to identify any weaknesses and deficiencies in classification,

notification, and protective action requirements (PAR) development activities;

(2) compared the identified weaknesses and deficiencies against licensee identified

-23-

Enclosure

findings to determine whether the licensee is properly identifying failures;

and (3) determined whether licensee performance is in accordance with the guidance of

the NEI 99-02, Voluntary Submission of Performance Indicator Data, acceptance

criteria.

December 7, 2006, Unit 2, simulator-based exercise requiring notice of unusual

event and alert declarations

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b.

Findings

No findings of significance were identified.

2.

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. The inspectors performed independent radiation dose rate

measurements and reviewed the following items:

PI 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

Adequacy of the licensees internal dose assessment for any actual internal

exposure greater than 50 millirem committed effective dose equivalent

-24-

Enclosure

Physical and programmatic controls for highly activated or contaminated

materials (nonfuel) stored within spent fuel and other storage pools

Self-assessments related to the access control program since the last

inspection; there were no audits, licensee event reports, and special reports

documented.

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 controls 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 inspectors completed 21 of the required 21 samples.

b.

Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA1 PI Verification (71151)

.1

Occupational Radiation Safety Cornerstone

a.

Inspection Scope

The inspectors reviewed licensee documents from April through September 2006. The

review included corrective action documentation that identified occurrences in locked high

radiation areas (as defined in the licensees TSs, very high radiation areas (as defined in

10 CFR 20.1003), and unplanned personnel exposures (as defined in NEI 99-02).

Additional records reviewed included as low as reasonably achievable records and whole

body counts of selected individual exposures. The inspectors interviewed licensee

-25-

Enclosure

personnel that were accountable for collecting and evaluating the PI data. In addition, the

inspector toured plant areas to verify that high radiation, locked high radiation, and very

high radiation areas were properly controlled. PI definitions and guidance contained in

NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 4, were used to verify

the basis in reporting for each data element.

Occupational Exposure Control Effectiveness

The inspectors completed the required sample (1) in this cornerstone

b.

Findings

No findings of significance were identified.

.2

Public Radiation Safety Cornerstone

a.

Inspection Scope

The inspectors reviewed licensee documents from April through September 2006.

Licensee records reviewed included corrective action documentation that identified

occurrences for liquid or gaseous effluent releases that exceeded PI thresholds and those

reported to the NRC. The inspectors interviewed licensee personnel that were

accountable for collecting and evaluating the PI data. PI definitions and guidance

contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 4, were

used to verify the basis in reporting for each data element.

Radiological Effluent TS/Offsite Dose Calculation Manual Radiological Effluent

Occurrences

The inspectors completed the required sample (1) in this cornerstone

b.

Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

.1

Routine Review of Identification and Resolution of Problems

The inspectors performed a daily screening of items entered into the licensees CAP.

This assessment was accomplished by reviewing CRs and attending corrective action

review and work control meetings. The inspectors: (1) verified that equipment, human

performance, and program issues were being identified by the licensee at an appropriate

threshold and that the issues were entered into the CAP; (2) verified that corrective

actions were commensurate with the significance of the issue; and (3) identified conditions

that might warrant additional follow-up through other baseline inspection procedures.

.2

Selected Issue Follow-up Inspection

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

more in-depth review. The inspectors considered the following during the review of the

licensees actions: (1) complete and accurate identification of the problem in a timely

-26-

Enclosure

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.

September 20, 2006, Unit 2, repeat occurrence of containment purge isolation

October 30, 2006, Unit 2, repeat occurrence of improper electrical connections in

motor-control centers

When evaluating the effectiveness of the licensees corrective actions for these issues,

the following attributes were considered:

Complete and accurate identification of the problem in a timely manner

commensurate with its significance and ease of discovery

Evaluation and disposition of operability and reportability issues

Consideration of extent of condition, generic implications, common cause, and

previous occurrences

Classification and prioritization of the resolution of the problem commensurate with

its safety significance

Identification of root and contributing causes of the problem for significant

conditions adverse to quality

Identification of corrective actions which are appropriately focused to correct the

problem

Completion of corrective actions in a timely manner commensurate with the safety

significance of the issue

Documents reviewed by the inspectors are listed in the attachment

.3

Semiannual Trend Review

a.

Inspection Scope

The inspectors completed a semi-annual trend review of repetitive or closely related

issues that were documented in corrective action documents to identify trends that might

indicate the existence of more safety-significant issues. The inspectors' review consisted

of the 6-month period of June 24 through December 31, 2006. When warranted, some of

the samples expanded beyond those dates to fully assess the issue. The inspectors also

reviewed CAP items associated with deficiencies in the conduct of activities involving hot

work. The inspectors compared and contrasted their results with the results contained in

the licensees quarterly trend reports. Corrective actions associated with a sample of the

issues identified in the licensees trend report were reviewed for adequacy. Documents

reviewed by the inspectors are listed in the attachment.

-27-

Enclosure

b.

Findings

During the Unit 2 pressurizer replacement Refueling Outage 2R18 from September 19

through October 28, 2006, several deficiencies were noted involving the conduct of hot

work. Licensee Procedure EN-DC-127, Control of Hot Work and Ignition Sources,

contains the governing guidelines for the conduct of hot work, including Hot Work

Permit, Attachment 8.1, which serves to document that the applicable requirements for

each activity involving hot work are met. Examples of instances resulting from failures to

adequately implement the control of hot work procedure included:

On September 24, 2006, welding activities being conducted on the Unit 2 main

condenser manway cover resulted in paint/crud smoldering that was extinguished

with a portable fire extinguisher.

On September 25, 2006, sparks from torch cutting of the Unit 2 containment sump

strainer ignited a nearby plastic bag containing used anti-contamination clothing.

On September 26, 2006, a substantial amount of slag from the containment sump

strainer torch cutting flowed down onto a fire blanket that was protecting the floor

and caused the fire blanket to ignite.

On September 27, 2006, slag from the containment sump strainer torch cutting

flowed down through a fire blanket and landed on Valve 2BS-38 in the containment

sump. The slag came in contact with debris buildup on the valve locking chain and

began to smoke and smolder. A portable fire extinguisher was discharged to

extinguish the smoldering.

On September 28, 2006, the firewatch posted for the containment sump strainer

hot work could not get to his designated fire extinguisher. The firewatch had

moved to the east side of the sump and the extinguisher remained on the west

side of the sump.

On October 5, 2006, a small fire in the Unit 2 containment building basement

below the pressurizer was extinguished by the assigned firewatch using a portable

extinguisher.

On October 16, 2006, welding and grinding activities above the replacement

pressurizer were being performed without proper protection to prevent sparks from

traveling down the cavity below.

The licensee entered each of these occurrences into their CAP.

.4

Access Control to Radiologically Significant Areas

Section 2OS1 evaluated the effectiveness of the licensee's problem identification and

resolution processes regarding access controls to radiologically significant areas and

radiation worker practices. The inspectors reviewed corrective action documents for root

cause/apparent cause analysis against the licensees problem identification and resolution

process. No findings of significance were identified.

-28-

Enclosure

4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)

a.

Inspection Scope

The inspectors: (1) reviewed operator logs, plant computer data, and/or strip charts for

the below listed evolutions to evaluate operator performance in coping with nonroutine

events and transients; (2) verified that operator actions were in accordance with the

response required by plant procedures and training; and (3) verified that the licensee has

identified and implemented appropriate corrective actions associated with personnel

performance problems that occurred during the nonroutine evolutions sampled.

October 26, 2006, Unit 1, fish intrusion into the circulating water system

October 30, 2006, Unit 2, fire in Motor-Control Center 2B-53

November 9, 2006, Unit 1, unplanned loss of Main Feedwater Pump P-2A

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b.

Findings

Introduction. A Green self-revealing finding was identified when the licensee replaced an

air conditioning unit for the Unit 1 Main Feedwater Pump (MFP) A control cabinet without

considering the effects of electromagnetic interference (EMI) on the digital speed

monitor (DSM) housed in the cabinet. Consequently, MFP A tripped, resulting in an

unplanned automatic plant power reduction from 100 percent to 40 percent RTP.

Description. In September 2006 the air conditioning unit for the Unit 1 MFP A cabinet

failed. During the procurement phase of replacement efforts, the station discovered that

the current air conditioning unit was no longer available because it had become obsolete.

The licensee contacted the cabinet manufacturer who recommended to the licensee a

replacement unit. On October 12 the licensee replaced the air conditioning unit with the

recommended replacement after evaluating it as being an equivalent unit in accordance

with Procedure EN-DC-313, Procurement Engineering Process, Revision 0.

Subsequently, on November 9, 2006, while Unit 1 was operating at 100 percent RTP

MFP A tripped, which caused the integrated control system to initiate and perform an

unplanned automatic power reduction to 40 percent RTP. Operators surveyed the

indications and concluded that the cause of the MFP trip was an overspeed condition;

however, at the time of the trip, there were no indications that the MFP had actually

experienced an overspeed.

After extensive troubleshooting, the licensee suspected that EMI from the air conditioning

unit was the cause of the faults. The licensee performed a review of the new air

conditioning unit and identified that the bottom section of the new unit was molded plastic

and not metal like the previous unit. They also discovered the configuration of this new

unit placed the blower fan directly above, and in closer proximity to, the DSM than did that

of the previous air conditioning unit. The licensee decided to remove power to the air

conditioning unit to verify that it was the initiator of the faults in the DSM. With power to

the air conditioning unit removed, the faults and trips did not recur.

-29-

Enclosure

The inspectors reviewed the licensees root cause evaluation of this event, documented in

CR ANO-1-2006-1399, which determined the root cause to be that the procurement

engineering equivalency guidelines did not consider EMI as a potential failure mode.

During this review, the inspectors noted that the licensee had not questioned or

investigated any of the differences between the old and the new air conditioning units.

Instead, the licensee had relied on the manufacturers designation that the new unit was

an equivalent replacement for the old unit.

Also, during their review of the root cause analysis, the inspectors noted that there had

been previous experiences with the MFP A control system involving EMI, as well as a

substantial amount of industry operating experience concerning the topic of EMI and

digital components. During interviews with station personnel, the inspectors also

determined that station engineers received specific training on EMI related to digital

components.

Analysis. The inspectors determined that the failure of the licensee to adequately

evaluate the new air conditioning unit with respect to design differences and possible

EMI interactions was a performance deficiency. The finding was determined to be more

than minor because it affected the design control attribute of the initiating events

cornerstone objective to limit the likelihood of those events that upset plant stability and

challenge critical safety functions during shutdown as well as power operations. Using the

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

determined to have very low safety significance because the condition only affected the

initiating events cornerstone and did not contribute to both the likelihood of a reactor trip

and the likelihood that mitigation equipment or functions will not be available. The cause

of the finding is related to the crosscutting element of problem identification and resolution

associated with operating experience because the licensees failure to implement and

institutionalize OE through changes to station processes and procedures.

Enforcement. While a performance deficiency was identified with regard to the trip of the

MFP A, there were no violations identified during the review of this issue. The licensee

has entered this issue into the CAP as CR ANO-1-2006-1399: FIN 05000313/2006005-5,

Trip of a MFP Due to Inadequate Design Control.

4OA5 Other Activities

.1

(Closed) Temporary Instruction (TI) 2515/169, Mitigating Systems Performance

Index (MSPI) Verification

a.

Inspection Scope

During this inspection period, the inspectors completed a review of the licensees

implementation of the MSPI in accordance with the guidance provided in TI 2515/169.

The review examined the licensees MSPI Basis Documents (ANO1-A-6-0001, Revision 1,

and ANO2-SA-06-00001, Revision 0) and verified the established system boundaries and

monitored components were consistent with guidance provided in NEI 99-02, Reactor

Oversight Process Performance Indicators, Revision 4. The inspectors verified that the

licensee did not include credit for unavailability hours for short term unavailability or

operator recovery actions to restore the risk-significant function as is allowed by

NEI 99-02.

-30-

Enclosure

Additionally, the inspectors reviewed the baseline MSPI unavailability time using plant

specific values for the period of 2002 through 2004. The verification included all planned

and unplanned unavailability. For Unit 1, the inspectors reviewed the baseline MSPI

unreliability data using plant specific values for the period of 2002 through 2004. Unit 2

derived its baseline unreliability on industry standard values, as is permitted by NEI 99-02.

The plant specific data for 2005 through 2006 were also reviewed to ensure the licensee

properly accounted for the actual unavailability hours of MSPI systems. For the same

period, the MSPI component unreliability data was examined to ensure the licensee

identified all failures of monitored components. The accuracy and completeness of the

reported unavailability and unreliability data was verified by reviewing operating logs, CRs,

and work order documents. The unavailability and unreliability data was compared with PI

data submitted to the NRC to ensure that any discrepancies would not result in a change

to the index color.

b.

Findings

No findings of significance were identified. This completes the inspection requirements

for this TI.

.2

Institute of Nuclear Power Operations Plant Assessment Report Review

a.

Inspection Scope

The inspectors reviewed the final report for the Institute of Nuclear Power Operations

plant assessment of Arkansas Nuclear One, Units 1 and 2, conducted in July and

August 2006. The inspectors reviewed the report to ensure that issues identified were

consistent with the NRC perspectives of licensee performance and to verify if any

significant safety issues were identified that required further NRC followup.

b.

Findings

No findings of significance were identified.

.3

(Closed) Unresolved Item (URI)05000313/2006003-01, Failure to Retrieve Required

Records of Activities Affecting Quality

In response to inspectors questioning the seismic capability of the Tendon Surveillance

Cranes L-28 on Unit 1, the licensee could not locate the appropriate documentation. The

licensee evaluated the as found conditions of the cranes against the uniformed building

code. The licensee concluded that the cranes would be able to withstand the design

basis earthquake without affecting mitigating equipment. These evaluations were

reviewed by the inspectors. No findings of significance were identified, and no violations

of NRC requirements were identified. The licensee documented the evaluations

demonstrating the seismic qualification in CR ANO-1-2005-3109. This unresolved

item (URI) is closed.

-31-

Enclosure

.4

NRC TI 2515/166, PWR Containment Sump Blockage

The inspectors reviewed ANOs Unit 2 implementation of plant modifications and

procedure changes committed to in their response to Generic Letter 2004-02, Potential

Impact of Debris on Emergency Recirculation During Design Basis Accidents at

Pressurized Water Reactors.

The inspectors observed installation of the containment recirculation sump strainers,

debris barriers, and interceptors. In addition, the inspectors verified that ANO Unit 2 has

implemented specific procedure changes to control tags, labels, tape, and other objects

inside the containment building.

At the time of the inspection, industry testing for chemical effects on containment

recirculation sumps was not complete. Since the testing was not complete, ANO Unit 2

evaluated the new recirculation sump modifications to the original design basis,

Regulatory Guide 1.82, Water Sources for Long-Term Recirculation Cooling Following a

Loss-of-Coolant Accident, Revision 0. Final review and acceptance of the modification

will be performed by the Office of Nuclear Reactor Regulation at a later date.

4OA6 Meetings, Including Exit

On October 6, 2006, the inspectors presented the access controls inspection results to

Mr. T. Mitchell, General Manager and other members of his staff who acknowledged the

findings. The inspectors confirmed that proprietary information was not provided or

examined during the inspection.

The engineering inspectors presented the results of the inservice inspection review to

Mr. J. Kowalewski, Director, Engineering, on October 10, 2006. Mr. Kowalewski

acknowledged the inspection findings. The engineering inspector conducted a followup

exit with Mr. T. Mitchell, General Manager, Plant Operations, on December 4, 2006, to

provide updated information on the documentation associated with the review of the

containment sump modification. The inspectors identified that they had not reviewed

proprietary information.

On November 1, 2006, the inspector presented the results of the emergency plan change

inspection to Mr. R. Holeyfield, Supervisor, Emergency Preparedness. The inspector

confirmed that proprietary information was not provided or examined during the

inspection.

The resident inspectors presented the inspection results of the resident inspections to

Mr. J. Forbes, Vice President, Operations, and other members of the licensee's

management staff on January 17, 2007. The resident inspectors conducted a followup

exit with Mr. J. Forbes, Vice President, Operations, on February 8, 2007. The licensee

acknowledged the findings presented. The inspectors noted that while proprietary

information was reviewed, none would be included in this report.

ATTACHMENT: SUPPLEMENTAL INFORMATION

A-1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Barnes, Manager, Planning, Scheduling, and Outages

S. Bennett, Project Manager, Licensing

B. Berryman, Manager, Operations Unit 1

J. Browning, Manager, Operations Unit 2

S. Cotton, Manager, Training

B. Daiber, Supervisor, Systems Engineering

J. Eichenberger, Manager, Corrective Actions and Assessments

J. Forbes, Vice President, Operations

R. Fowler, Emergency Planner

R. Freeman, Emergency Planner

J. Giles, Manager, Technical Support

M. Ginsberg, Supervisor, Engineering Programs and Components

R. Gresham, Emergency Planner

D. Harris, Emergency Planner

A. Hawkins, Licensing Specialist

J. Hoffpauir, Manager, Maintenance

R. Holeyfield, Manager, Emergency Planning

M. Huff, Supervisor, Project Engineering

D. James, Manager, Licensing

W. James, Manager, Engineering Projects

J. Kowalewski, Director, Engineering

T. Marlow, Director, Nuclear Safety Assurance

J. Miller, Jr., Manager, System Engineering

T. Mitchell, General Manager, Plant Operations

D. Moore, Manager, Radiation Protection

K. Panther, Nondestructive Examination Site Level III

C. Reasoner, Manager, Engineering Programs and Components

C. Tyrone, Manager, Quality Assurance

F. Van Buskirk, Licensing Specialist

D. White, Emergency Planner

P. Williams, Supervisor, Systems Engineering

M. Woodby, Manager, Design Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000368/2006005-01

NCV

Fire During Hot Work Activities on the Containment Sump

Strainer (Section 1R05)05000368/2006005-02

NCV

Failure to Perform Modification Resulted in an Inoperable

RCP Oil Collection System (Section 1R15)

A-2

Attachment

05000368/2006005-03

NCV

Inadvertent RCS Draining While in Mode 5 (Section 1R20)05000368/2006005-04

FIN

Unplanned Increase in Time with Reactor Vessel Water Level

at Flange Level (Section 1R20)05000313/2006005-05

FIN

Trip of a MFP Due to Inadequate Design Control

(Section 4OA3)

Closed

05000313/2006003-01

URI

Failure to Retrieve Required Records of Activities Affecting

Quality (Section 4OA5)

Discussed

None

LIST OF DOCUMENTS REVIEWED

In addition to the documents referred to in the inspection report, 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 1R01: Adverse Weather Protection

NUMBER

TITLE

REVISION

OP-2203.008

Natural Emergencies

9

OP-1203.025

Natural Emergencies

20

Section 1R02: Evaluation of Changes, Tests, or Experiments

Engineering Requests

NUMBER

TITLE

REVISION

ER-ANO-2002-0836-003

Pressurizer Replacement

1

ER-ANO-2002-0836-004

Original Pressurizer Removal / Replacement

Pressurizer Installation

1

ER-ANO-2002-0836-020

Replacement Pressurizer Heater Electrical Design

Input

0

A-3

Attachment

Section 1R04: Equipment Alignment

Procedures

NUMBER

TITLE

REVISION

OP-1104.036

Emergency Diesel Generator Operations

45

Op-1107.002

ES Electrical System Operations

23

OP-1104.005

Reactor Building Spray System Operation

46

Section 1R05: Fire Protection

Plant Drawings

FZ-1038, Sheet 1, Revision 2

FZ-2018, Sheet 1, Revision 2

Procedures

NUMBER

TITLE

REVISION

Arkansas Nuclear One Fire Hazards Analysis

11

PFP-U1

ANO Prefire Plan (Unit 1) - Section 1B-357-67-U.doc,

Section 1B-354-79-U.doc

2

PFP-U2

ANO Prefire Plan (Unit 2) - Section 2B-335-2040-

JJ.doc

2

EN-DC-127

Control of Hot Work and Ignition Sources

2

CRs

ANO-1-2005-0950

ANO-1-2005-1397

ANO-2-2005-1724

ANO-2-2006-1565

ANO-2-2006-1701

Section 1R07: Heat Sink Performance

NUMBER

TITLE

REVISION

ULD-1-SYS-01

ANO-1 Emergency Diesel Generator (EDG) System

4

ULD-1-SYS-10

ANO-1 Service Water Systems

13

SPEC-6600-M-012

Emergency Diesel Generators for ANO Unit 1

1

ER-ANO-2004-0663-000

2004 Unit 1 EDG Thermal Test Results

0

ER-980310

EDG Coolers, E-20A/B, Service Water Flow

Requirements

CALC-91-R-2013-01

Service Water Performance Testing Methodology

14

A-4

Attachment

OP-1309.018

EDG Cooler Thermal Test

Change 004-02-0

Section 1R08: Inservice Inspection (71111.08P)

CRs:

ANO-2-2005-0916

ANO-2-2006-1208

ANO-C-2006-1733

NDEs

REPORT

COMPONENT/LOCATION

METHOD

BOP-RT-06-055

FW-50 (WDR-40631) Drawing No. 2CCA-15-1, Sheet 1

Radiographic

BOP-RT-06-056

FW-51 (WDR-40632) Drawing No. 2CCA-15-1, Sheet 1

Radiographic

ISI-UT-06-033

2-73-SWS-R-12B-30R, 2HBC-60-1 between FW-52C &

FW-6C1

Automatic

Ultrasonic

ISI-UT-06-040

FW-50 (WDR-40631) Drawing No. 2CCA-15-1, Sheet 1

Ultrasonic

ISI-UT-06-042

FW-51 (WDR-40632) Drawing No. 2CCA-15-1, Sheet 1

Ultrasonic

Procedures

PROCEDURE

TITLE

REVISION

CEP-NDE-0110

Program Section for Certification of NDE Personnel

2

CEP-NDE-0111

Certification of Ultrasonic Personnel in Accordance

with ASME Section XI, Appendix VII

1

CEP-NDE-0400

Ultrasonic Examination

0

CEP-NDE-0404

Manual Ultrasonic Examination of Ferritic Piping

Welds (ASME XI)

1

CEP-NDE-0423

Manual Ultrasonic Examination of Austenitic Piping

Welds (ASME XI)

1

CEP-NDE-0505

Ultrasonic Thickness Examination

3

A-5

Attachment

Welding Procedures/Qualification Records

NUMBER

TITLE

REVISION/

DATE

PQR 107

Manual Gas Tungsten & Shielded Metal Arc

Welding (GTAW & SMAW), P-No. 8, SA-312 Type

304

1

PQR 170

Manual Gas Tungsten & Shielded Metal Arc

Welding (GTAW & SMAW), P-No. 8, SA-240 Type

304

1

WPS E-P8-T-A8,Ar

Manual Gas Tungsten Arc Welding (GTAW) of

P-No. 8 Stainless Steels

0

WPS E-P8-T(M)-A8,Ar

Machine Gas Tungsten Arc Welding (GTAW) of

P-No. 8 Stainless Steels

0

WP 06-121

2T-1 Surge Line

October 3,

2006

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

COPD-024, Risk Assessment Guidelines, Revision 18

Section 1R15: Operability Evaluations

CRs

ANO-2-1995-0555

ANO-2-2006-1407

ANO-2-2006-1433

ANO-2-2006-1459

ANO-2-2006-1478

ANO-2-2006-1521

ANO-2-2006-1522

ANO-2-2006-1539

ANO-2-2006-1757

ANO-2-2006-1796

ANO-2-2006-1853

ANO-2-2006-1879

Procedure

OP-2305.002, Reactor Coolant System Leak Detection, Revision 14

Engineering Requests

ER-ANO-2000-2528-003, ANO Sump Operability when the RCS Temperature is Above 200 F

ER-ANO-2004-0060-000, ANO-2 Sump Operability for the RCS Temperature above 200 F

Miscellaneous Documents

2CNA108802, Safety Evaluation Report, dated October 26, 1988

0CAN088404, Station Letter to USNRC Requesting Exemption, dated August 15, 1984

A-6

Attachment

Section 1R17: Permanent Plant Modifications

Engineering Requests

NUMBER

TITLE

ER-ANO-2002-0836-003

Pressurizer Replacement

ER-ANO-2002-0836-004

Original Pressurizer Removal / Replacement

Pressurizer Installation

ER-ANO-2002-0836-005

Interference Removal / Reinstallation Inside the

Pressurizer Cubicle

ER-ANO-2002-0836-006

Interference Removal / Reinstallation Outside the

Pressurizer Cubicle

ER-ANO-2002-0836-007

ANO-2 Pressurizer Replacement Rigging and

Handling

ER-ANO-2002-0836-020

Replacement Pressurizer Heater Electrical Design

Input

Section 1R20: Refueling and Outage Activities

Procedures

NUMBER

TITLE

REVISION

OP-2104.004

Shutdown Cooling System

031-00-0

OP-2104.019

Clean Resin Transfer

009-01-0

OP-2504.005

Reactor Vessel Closure Head Removal

012-01-0

Miscellaneous Document

Shutdown Operations Protection Plan, dated August 4, 2005

CRs

ANO-2-2006-1464

ANO-2-2006-1553

ANO-2-2006-1573

ANO-2-2006-1734

ANO-2-2006-2032

ANO-C-2006-1473

ANO-C-2006-1678

Section 2OS1: Access Controls to Radiologically Significant Areas

CRs

ANO-1-2006-0479

ANO-1-2006-0700

ANO-1-2006-1113

ANO-2-2005-1429

ANO-2-2006-1434

ANO-2-2006-1446

ANO-2-2006-1471

ANO-2-2006-1495

ANO-2-2006-1497

ANO-2-2006-1501

ANO-2-2006-1511

ANO-2-2006-1523

ANO-2-2006-1568

ANO-2-2006-1568

ANO-2-2006-1575

ANO-2-2006-1598

A-7

Attachment

ANO-2-2006-1606

ANO-2-2006-1636

ANO-2-2006-1638

ANO-2-2006-1671

ANO-2-2006-1674

ANO-2-2006-1675

ANO-2-2006-1695

ANO-2-2006-1696

ANO-2-2006-1716

ANO-2-2006-1717

ANO-2-2006-1748

ANO-2-2006-1765

ANO-2-2006-1774

ANO-2-2006-1790

ANO-C-2006-1698

Audits and Self-Assessments

Self-Assessment Report, QS-2006-ANO-007, 2R18 Radiation Protection Outage Planning

Review

Radiation Work Permits

NUMBER

TITLE

RWP 2006-2420

Scaffold Activities

RWP 2006-2501

Support Activities for Pressurizer Replacement

RWP 2006-2502

Remove and Replace Pressurizer

RWP 2006-2520

Incore Instrument Thimble Tube Replacement

RWP 2005-2530

Sump Screen Modification

RWP 2006-2540

Hot Leg RTD Replacement

Procedures

NUMBER

TITLE

REVISION

1601.209

Whole Body Counting/Bioassay

CHANGE

009-00

EN-RP-104

Personnel Contamination Events

3

EN-RP-108

Radiation Protection Posting

3

EN-RP-131

Air Sampling

1

EN-RP-203

Dose Assessment

0

EN-RP-208

Whole Body Counting and In-Vitro Bioassay

0

PL-182

Radiation Protection Expectations and Standards

1

Miscellaneous Document

Alpha Monitoring Plan, Revised August 22, 2006

A-8

Attachment

Section 4OA2: Identification and Resolution of Problems

CRs

ANO-2-2006-1535

ANO-2-2006-1625

ANO-2-2006-1655

ANO-2-2006-1693

ANO-2-2006-1891

ANO-2-2006-2174

Section 4OA3: Event Follow-up

Procedures

NUMBER

TITLE

REVISION

EN-DC-141

Design Inputs

2

EN-DC-313

Procurement Engineering Process

0

CRs

ANO-1-2006-1399

ANO-2-2006-1464

ANO-2-2006-2444

ANO-2-2006-2449

Section 4OA5: Other Activities (TI 2515/0166)

Safety Evaluation

FFN-06-008, Unit 2 RBS/ECCS Sump Strainer Replacement

A-9

Attachment

LIST OF ACRONYMS

ANO

Arkansas Nuclear One

ASME

American Society of Mechanical Engineers Boiler and Pressure Vessel Code

CAP

corrective action program

CCW

component cooling water

CFR

Code of Federal Regulations

CR

condition report

DSM

digital speed monitor

EDG

emergency diesel generator

EMI

electromagnetic interference

FIN

finding

MC

manual chapter

MFP

main feedwater pump

MSPI

mitigating systems performance index

NCV

noncited violation

NDE

nondestructive examination

PI

performance indicator

PWR

pressurized water reactor

RCP

reactor coolant pump

RCS

reactor coolant system

RTP

rated thermal power

SSCs

system, structure, and components

TI

temporary instruction

TS

Technical Specification

UFSAR

Updated Final Safety Analysis

URI

unresolved item