ML040330908

IR 05000382-03-007, on 09/21/2003 - 12/27/2003; Waterford Steam Electric Station, Unit 3; Postmaintenance Testing, Access Control to Radiological Significant Areas, Identification and Resolution of Problems, and Event Followup

ML040330908
Person / Time
Site:	Waterford
Issue date:	02/02/2004
From:	Howell A NRC/RGN-IV/DRP
To:	Venable J Entergy Operations
References
EA-03-230 IR-03-007
Download: ML040330908 (55)

See also: IR 05000382/2003007

Text

February 2, 2004

EA 03-230

Joseph E. Venable

Vice President Operations

Waterford 3

Entergy Operations, Inc.

17265 River Road

Killona, Louisiana 70066-0751

SUBJECT: WATERFORD STEAM ELECTRIC STATION, UNIT 3 - NRC INTEGRATED

INSPECTION REPORT 05000382/2003007

Dear Mr. Venable:

On December 31, 2003, the NRC completed an inspection at your Waterford Steam Electric

Station, Unit 3. The enclosed report documents the inspection findings which were discussed

on January 5, 2003, with you and other members of your staff. This inspection examined

activities conducted under your license as they relate to safety and compliance with the

Commissions rules and regulations and with the conditions of your license. Within these areas,

the inspection consisted of selected examination of procedures and representative records,

observations of activities, and interviews with personnel.

The report discusses a finding that appears to have Greater than Green safety significance. As

described in Section 4OA3.1 of this report, the issue involved the failure to establish appropriate

instructions and accomplish those instructions for installation of a fuel line for Train A

emergency diesel generator in May of 2003. This failure resulted in uneven and excessive

scoring of the tubing that ultimately led to a complete 360 degree failure of the fuel supply line

on September 29, 2003, during a monthly surveillance test, which rendered the Train A

emergency diesel generator inoperable. This finding was assessed based on the best available

information, including influential assumptions, using the applicable Significance Determination

Process and was preliminarily determined to be a Greater than Green Finding. The final

resolution of this finding will convey the increment in the importance to safety by assigning the

corresponding color i.e, White (a finding with some increased importance to safety, which may

require additional NRC inspection), Yellow (a finding with substantial importance to safety that

will result in additional NRC inspection and potentially other NRC action) or Red (a finding of

high importance to safety that will result in increased NRC inspection and other NRC action).

Because the preliminary safety significance is greater than Green, the NRC requests that

additional information be provided regarding the nonrecovery probability for the Train A

emergency diesel generator and any other considerations you have identified as impacting the

safety significance determination.

Entergy Operations, Inc. -2-

This finding does not present an immediate safety concern based on your immediate and long

term corrective actions. These actions included a complete re-design and installation of the

fuel line that had prematurely failed.

This finding is also an apparent violation of NRC requirements and is being considered for

escalated enforcement action in accordance with the General Statement of Policy and

Procedure for NRC Enforcement Actions (Enforcement Policy), NUREG-1600. The current

enforcement policy is included on the NRCs website at

http://www.nrc.gov/what-we-do/regulatory/enforcement.html.

Before the NRC makes a final decision on this matter, we are providing you an opportunity

(1) to present to the NRC your perspectives on the facts and assumptions, used by the NRC to

arrive at the finding and its significance, at a Regulatory Conference or (2) submit your position

on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held

within 30 days of the receipt of this letter and we encourage you to submit supporting

documentation at least one week prior to the conference in an effort to make the conference

more efficient and effective. If a Regulatory Conference is held, it will be open for public

observation. If you decide to submit only a written response, such submittal should be sent to

the NRC within 30 days of the receipt of this letter.

Please contact Mr. William Jones at (817) 860-8147 within 10 days of the date of this letter to

notify the NRC of your intentions. If we have not heard from you within 10 days, we will

continue with our significance determination and enforcement decision and you will be advised

by separate correspondence of the results of our deliberations on this matter.

Since the NRC has not made a final determination in this matter, no Notice of Violation is being

issued for the inspection finding at this time. In addition, please be advised that the

characterization of the apparent violation described in the enclosed inspection report may

change as a result of further NRC review.

In addition, the enclosed report documents four NRC-identified findings of very low safety

significance (Green). 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 four findings as non-cited

violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. These NCVs

are described in the subject inspection report. If you contest the violations or significance of

these NCVs, 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; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington,

DC 20555-0001; and the NRC Resident Inspector at the Waterford Steam Electric Station,

Unit 3 facility.

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure(s), and your response will be made available electronically for public inspection in the

Entergy Operations, Inc. -3-

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).

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

with you.

Sincerely,

/RA/

Arthur T. Howell III, Director

Division of Reactor Projects

Docket: 50-382

License: NPF-38

Enclosure:

NRC Inspection Report

050000382/2003007

w/attachment: Supplemental Information

cc w/enclosure:

Senior Vice President and

Chief Operating Officer

Entergy Operations, Inc.

P.O. Box 31995

Jackson, MS 39286-1995

Vice President, Operations Support

Entergy Operations, Inc.

P.O. Box 31995

Jackson, MS 39286-1995

Wise, Carter, Child & Caraway

P.O. Box 651

Jackson, MS 39205

General Manager, Plant Operations

Waterford 3 SES

Entergy Operations, Inc.

17265 River Road

Killona, LA 70066-0751

Entergy Operations, Inc. -4-

Manager - Licensing Manager

Waterford 3 SES

Entergy Operations, Inc.

17265 River Road

Killona, LA 70066-0751

Chairman

Louisiana Public Service Commission

P.O. Box 91154

Baton Rouge, LA 70821-9154

Director, Nuclear Safety &

Regulatory Affairs

Waterford 3 SES

Entergy Operations, Inc.

17265 River Road

Killona, LA 70066-0751

Michael E. Henry, State Liaison Officer

Department of Environmental Quality

Permits Division

P.O. Box 4313

Baton Rouge, LA 70821-4313

Parish President

St. Charles Parish

P.O. Box 302

Hahnville, LA 70057

Winston & Strawn

1400 L Street, N.W.

Washington, DC 20005-3502

Entergy Operations, Inc. -5-

Electronic distribution by RIV:

Regional Administrator (BSM1)

DRP Director (ATH)

DRS Director (DDC)

Senior Resident Inspector (MCH)

Branch Chief, DRP/E (WBJ)

Senior Project Engineer, DRP/E (VGG)

Staff Chief, DRP/TSS (PHH)

RITS Coordinator (NBH)

Debby Jackson, OEDO RIV Coordinator (DAJ1)

WAT Site Secretary (AHY)

Dale Thatcher (DFT)

G. F. Sanborn, D:ACES (GFS)

K. D. Smith, RC (KDS1)

F. J. Congel, OE (FJC)

OE:EA File (RidsOeMailCenter)

ADAMS: W Yes G No Initials: __wbj____

W Publicly Available G Non-Publicly Available G Sensitive W Non-Sensitive

R:\_WAT\2003\WT2003-07RP-MCH.wpd

RIV:RI:DRP/E SRI:DRP/E C:DRS/PSB C:DRS/OB

GFLarkin MCHay TWPruett ATGody

T - WBJones T - WBJones E - WBJones /RA/

1/28/04 1/28/04 1/28/04 1/27/04

C:DRS/EB SRA C:DRP/E D:DRP

CSMarschall MFRunyan WBJones ATHowell

/RA/ /RA/ /RA/ /RA/

1/28/04 2/2/04 1/28/04 2/2/04

OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 50-382

License: NPF-38

Report: 05000382/2003007

Licensee: Entergy Operations, Inc.

Facility: Waterford Steam Electric Station, Unit 3

Location: Hwy. 18

Killona, Louisiana

Dates: September 21 through December 31, 2003

Inspectors: M. C. Hay, Senior Resident Inspector

G. F. Larkin, Resident Inspector

M. P. Shannon, Senior Health Physicist

P. C. Gage, Senior Operations Engineer

T. O. McKernon, Senior Operations Engineer

J. F. Drake, Operations Engineer

V.G. Gaddy, Senior Project Engineer

D. R. Carter, Health Physicist

W. C. Sifre, Reactor Inspector, Engineering Branch

T. McConnell, Reactor Inspector, Engineering Branch

Accompanying V. X. Thomas, Intern, NRC Headquarters

Personnel:

Approved By: A. T. Howell III, Director, Division of Reactor Projects

ATTACHMENT: Supplemental Information

Enclosure

CONTENTS

SUMMARY OF FINDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

REACTOR SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1R01 Adverse Weather Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1R04 Equipment Alignment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1R05 Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

1R07 Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1R08 Inservice Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1R11 Licensed Operator Requalification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

1R12 Maintenance Rule Implementation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

1R13 Maintenance Risk Assessments and Emergent Work Evaluation . . . . . . . . . . . 9

1R15 Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

1R16 Operator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

1R19 Postmaintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

1R20 Refueling and Outage Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

1R22 Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

2OS1 Access Control to Radiological Significant Areas . . . . . . . . . . . . . . . . . . . . . . . 14

2OS2 ALARA Planning and Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

OTHER ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

4OA1 Performance Indicator Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

4OA3 Event Followup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4OA4 Crosscutting Aspects of Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

4OA6 Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

4OA7 Licensee Identified Violations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

ATTACHMENT: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Key Points of Contact . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

Items Opened, Closed, and Discussed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

List of Documents Reviewed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

List of Acronyms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-8

SUMMARY OF FINDINGS

IR05000382/2003-007; 09/21/2003-12/27/2003; Waterford Steam Electric Station, Unit 3;

Postmaintenance Testing, Access Control to Radiological Significant Areas, Identification and

Resolution of Problems, and Event Followup.

The report covered a 15-week period of inspection by resident inspectors, a senior health

physicist, a health physicist, two senior operations engineers, an operations engineer, a senior

project engineer, and a reactor engineer. The inspection identified one potential greater than

green finding and four green findings. The significance of most findings is indicated by their

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

Determination Process. Findings for which the Significance determination process does not

apply may be Green or be assigned a severity level after NRC management review. The

NRCs program for overseeing the safe operation of commercial nuclear power reactors is

described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

• TBD. A self-revealing apparent violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, was identified for the

failure to establish appropriate instructions and accomplish those instructions for

installation of a fuel line for Train A emergency diesel generator in May 2003.

This failure resulted in uneven and excessive scoring of the tubing that ultimately

led to a complete 360 degree failure of the fuel supply line on September 29,

2003, during a monthly surveillance test.

This finding is unresolved pending completion of a significance determination.

The finding was greater than minor because it directly impacted the availability

and reliability of an emergency diesel generator which is used to mitigate the

loss of AC power to the respective safety related bus. The finding was

determined to have a potential safety significance greater than very low

significance because the failure resulted in an actual loss of the safety function

of the Train A emergency diesel generator for an extended period of time

(Section 4OA3).

• Green. The inspectors identified a noncited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, for the failure to establish adequate corrective actions

to prevent recurrence of voiding conditions affecting the operability of the low

pressure safety injection system following shutdown cooling operations.

This finding is greater than minor because it affected the mitigating system

objective to ensure the reliability and availability of the low pressure safety

injection system to respond to an initiating event. The problem if left uncorrected

would become a more significant safety concern. The significance of this finding

was determined to be of very low safety significance because low pressure

safety injection Train B was inoperable for less than the Technical Specification

Enclosure

-2-

allowed outage time and Train A was determined to be degraded but operable in

accordance with Generic Letter 91-18 guidance (Section 4OA2).

Cornerstone: Barrier Integrity

• Green. The inspectors identified a noncited violation of 10 CFR Part 50,

Appendix B,Section XI, "Test Control," for the failure to establish adequate test

controls for leak testing main steam isolation Valves 1 and 2. This performance

deficiency contributed to both valves being declared inoperable due to system

leaks creating a low pressure condition in the valve actuating systems.

This finding is more than minor because it affected the Barrier Integrity

Cornerstone objective of providing reasonable assurance of the functionality of

containment. The finding was only of very low safety significance because it did

not represent an actual reduction of the atmospheric pressure control function of

the reactor containment, it did not result in an actual open pathway affecting the

physical integrity of reactor containment, and the main steam isolation valves

were inoperable for less time than the allowed Technical Specification outage

time (Section 1R19).

• Green. The inspectors identified a noncited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, for the failure to implement effective corrective actions

resulting in recurrences of pressure boundary leakage due to primary water

stress corrosion cracking of Alloy 600 reactor coolant system nozzles.

This finding was greater than minor because it affected the reactor safety barrier

integrity cornerstone objective for providing reasonable assurance that the

physical design barriers protect the public from radionuclide releases caused by

accidents or events. Using NRC Manual Chapter 0609 Significance

determination process Phase 1 Screening Worksheet this performance

deficiency affected the reactor coolant system barrier function requiring a

Phase 2 analysis. The results of the Phase 2 and 3 analysis determined that this

finding was of very low safety significance based on the cracks being axial in

nature (does not contribute substantially to a loss of coolant accident) and the

leaks resulted in a build up of only minor boric acid residue indicative of only

trace amounts of through wall leakage. The leak rates identified were well within

the capacity of a single charging pump (4OA2).

Cornerstone: Occupational Radiation Safety

• Green. The inspector identified a noncited violation of Technical

Specification 6.12.1 because Entergy failed to barricade a high radiation area.

Specifically, on October 27, 2003, the inspector observed that the high radiation

area rope barricading the regenitive heat exchanger room was stretched across

the entrance way at a height of approximately 79 inches, which would not

obstruct the entry of station workers. General area radiation levels within the

Enclosure

-3-

room were as high as 420 millirem per hour. The finding is in Entergys

corrective action program as Condition Report CR-WF3-2003-03164.

The finding is greater than minor because it affected the Occupational Radiation

Safety cornerstone objective to ensure adequate protection of worker health and

safety from exposure to radiation and the finding is associated with the

cornerstone attribute (Program & Process). The finding involved an individuals

potential for unplanned or unintended dose. When processed through the

Occupational Radiation Safety Significance Determination Process the finding

was determined to be of very low safety significance because the finding was not

associated with ALARA planning or work controls, there was no overexposure or

a substantial potential for overexposure, and the ability to assess dose was not

compromised (Section 2SO1).

B. Licensee-Identified Violations

Violations of very low safety significance, which were identified by Entergy have been

reviewed by the inspectors. Corrective actions taken or planned by Entergy have been

entered into Entergy's corrective action program. These violations and corrective action

tracking numbers are listed in Section 4OA7 of this report.

Enclosure

Report Details

Summary of Plant Status: The plant began the period on September 21, 2003, at 97 percent

power and coasted down to 75 percent power on October 20, 2003. The plant was shutdown

for a scheduled refueling outage on October 20, 2003. On November 20, 2003, operators

commenced a reactor startup to perform low power physics testing. The main turbine

generator was placed online on November 22, 2003, and the refueling outage ended on

November 24, 2003. Power was increased and reached approximately 100 percent on

November 25, 2003. Power remained at that level until December 19, 2003, when power was

reduced to 95 percent power for moderator temperature coefficient testing. Following testing,

power was increased to 100 percent.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection (71111.01)

a. Inspection Scope

The inspectors completed one adverse weather protection inspection during this

inspection period. On December 19, 2003, the inspectors completed a walkdown of

components and systems susceptible to freezing using Procedure OP-002-007, Freeze

Protection and Temperature Maintenance, Revision 10, to verify that the onset of cold

weather would not affect the mitigating systems. This inspection included a review of

condition reports associated with heat tracing and other cold weather protection

measures to determine their impact on the systems. Additionally, the inspectors

discussed adverse weather preparations with various Entergy Operations, Inc. (Entergy)

personnel.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed the following two partial system equipment alignment

inspections during this inspection period:

• On November 3, 2003, the inspectors walked down the accessible portions of

the spent fuel pool cooling system, Train A. The walkdown was completed

following a full core offload to verify that cooling water flow to the spent fuel pool

was adequate to maintain adequate cooling for the spent fuel. The inspectors

performed the walkdown using Procedure OP-002-006, Fuel Pool Cooling and

Purification, Revision 15. The inspectors had reviewed the ability of the spent

Enclosure

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fuel pool cooling system to remove the decay heat of the spent fuel during

refueling outages involving a full core offload during the previous inspection

period (NRC Inspection Report 05000382/2003006) and as documented in

Section 1R07 to this report.

• On December 18, 2003, the inspectors performed a partial equipment alignment

inspection of the reactor auxiliary building cable vault area and switchgear area

ventilation system Train B while the switchgear area ventilation system Train A

was inoperable. A review of selected maintenance work orders and corrective

action documents was performed to assess the material condition and

performance of the system. System configuration was assessed using

Operating Procedure OP-003-026, Cable Vault and Switchgear HVAC,

Revision 7. A walkdown of accessible portions of the system was performed to

assess material condition, such as system leaks and housekeeping issues, that

could adversely affect system operability.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdowns

a. Inspection Scope

The inspectors performed a complete alignment inspection of the safety related nitrogen

system. A walkdown of the mechanical and electrical components in the system was

performed to verify that the system was configured and operated in accordance with

Operating Procedure OP-003-019, Nitrogen System, Revision 12. The inspectors

reviewed the nitrogen system design requirements in the Updated Final Safety Analysis

Report to verify the systems ability to provide back up source of compressed gas for

various safety-related valves was adequate. The inspectors reviewed Engineering

Request ER-W3-97-0547-000 and select condition reports written on the nitrogen

system since October 1, 2000, to verify that degraded conditions were identified at the

appropriate threshold and that corrective actions were implemented in a timely manner.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

a. Inspection Scope

The inspectors conducted six inspections to assess whether Entergy had implemented a

fire protection program that adequately controlled combustibles and ignition sources

Enclosure

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within the plant, effectively maintained fire detection and suppression capabilities, and

maintained passive fire protection features in good material condition.

The following areas were inspected:

• Fire Zone RAB 2, 15, 16, 17 and 18 on October 1, 2003

• Fire Zone RAB 1A, 1B, 5, 6 and 7 on October 6, 2003

• Fire Zone RAB 35, 36, 37, 38 and 39 on November 20, 2003

• Fire Zone RAB 1A, 8, 11, 12 and 13 on November 28, 2003

• Fire Zone RAB 1A, 5, 6, 7 and 8 on December 18, 2003

• Fire Zone RAB 35, 36, 37, 38, and 39 on December 30, 2003

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

As discussed in NRC Inspection Report 05000382/200306, Section 1R07, the

inspectors previously reviewed documentation, analysis, and design basis

documentation relative to the ability of the spent fuel pool cooling system to remove

decay heat of the spent fuel during refueling outages involving a full core offload.

During this inspection period (as discussed in Section 1R04 of this report) on

November 3, 2003, the inspectors walked down the accessible portions of the spent fuel

pool cooling system Train A. The walkdown was completed following a full core offload

to verify that cooling flow to the spent fuel pool was adequate to maintain spent fuel pool

temperature.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities (71111.08)

.1 Nondestructive Examination Activities

The inspectors observed the ultrasonic system calibration and observed ultrasonic and

magnetic particle examinations. The inspectors observed 13 examinations, which are

listed below.

Enclosure

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System Component/Weld Examination Method

Identification

RCS cold leg 07-013 Ultrasonic

RCS cold leg 07-013 Magnetic Particle

RCS cold leg 07-016 Ultrasonic

RCS cold leg 07-016 Magnetic Particle

RCS Hot leg 06-010 Magnetic Particle

RCS Hot leg 06-010 Ultrasonic

RCS Hot leg 06-011 Magnetic Particle

RCS Hot leg 06-011 Ultrasonic

Main Feed Header B 46-011 Ultrasonic

Main Feed Header B 46-012 Ultrasonic

Main Feed Header B 46-020 Ultrasonic

1. 2 Steam Generator 04-030 Magnetic Particle

Nozzle

Containment 55-050 Ultrasonic

Penetration

During the review of these examinations, the inspectors verified that the correct

nondestructive examination (NDE) procedure was 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 reviewed the

documentation to determine if the indications revealed by the examinations were

compared against the American Society of Mechanical Engineers (ASME) Code

specified acceptance standards, and that the indications were appropriately

dispositioned. The nondestructive examination certifications of those personnel

observed performing examinations or identified during review of completed examination

packages were reviewed by the inspectors.

Enclosure

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The inspectors also observed the ultrasonic and eddy current examination of two leaking

pressurizer heater sleeves. In each case the flaws were clearly identified as short axial

flaws near the sleeve/pressurizer interface. The two pressurizer heater sleeves were

repaired using a MNSA-2 clamp.

b. Findings

No findings of significance were identified.

.2 Steam Generator Tube Inspection Activities

a. Inspection Scope

The inspection procedure specified, with respect to in situ pressure testing, performance

of an assessment of in situ screening criteria to assure consistency between assumed

NDE flaw sizing accuracy and data from the Electric Power Research Institute (EPRI)

examination technique specification sheets. It further specified assessment of

appropriateness of tubes selected for in situ pressure testing, observation of in situ

pressure testing, and review of in situ pressure test results.

The inspectors selected and reviewed the acquisition technique sheets and their

qualifying EPRI examination technique specification sheets to verify that the essential

variables regarding flaw sizing accuracy had been identified and qualified through

demonstration.

The inspection procedure specified comparing the estimated size and number of tube

flaws detected during the current outage against the previous outage operational

assessment predictions to assess Entergys prediction capability. The inspectors

reviewed Report ER-W3-2003-0534-000, Steam Degradation Assessment and Repair

Criteria for RF12. The purposes of the report were: (1) to provide a comprehensive

review and overall plan for detection and assessment of degradation to be addressed

during Refueling Outage RF12; and, (2) to provide predictions as to the type and extent

of degradation expected to be found.

The inspection procedure specified confirmation be made that the steam generator tube

eddy current testing (ECT) scope and expansion criteria meet technical specification

requirements, EPRI guidelines, and commitments made to the NRC. The inspectors

review determined that the steam generator tube ECT scope and expansion criteria

were being met.

The inspection procedure also specified that, if Entergy identified new degradation

mechanisms, then verify that Entergy had fully enveloped the problem in an analysis

and had taken appropriate corrective actions before plant startup. At the time of this

inspection, no new degradation mechanisms had been identified.

Enclosure

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The inspection procedure also required confirmation that all areas of potential

degradation were being inspected, especially areas which were known to represent

potential ECT challenges (e.g., top-of-tubesheet, tube support plates, and U-bends).

The inspectors confirmed that all known areas of potential degradation, including

ECT challenged areas, were included in the scope of inspection and were being

inspected.

The inspection procedure further required that repair processes being used were

approved in the technical specifications for use at the site. At the time of this inspection,

Entergy had not performed or used the designated Technical Specification approved

repair processes, thus there was no opportunity to observe implementation of any

potential repairs (e.g., plugging operations) or in-situ pressure testing.

The inspection procedure also required confirmation that the Technical Specification

plugging limit was being adhered to, and determination whether depth sizing repair

criteria were being applied for indications other than wear or axial primary water stress

corrosion cracking in dented tube support plate intersections. The inspectors confirmed

that Entergy was adhering to these specifications. The inspectors also determined that

Entergy, in response to Information Notice 2002-21, did account for crack-like

indications in dented tube support plate intersections by including these parameters in

their ECT computer programming, and the acquisition and analysis technique sheets.

Further, the ECT data analysts had been presented with specialized training associated

with this type of indication.

The inspection procedure stated that if steam generator leakage greater that three

gallons per day was identified during operations or during postshutdown visual

inspections of the tubesheet face, then assess whether Entergy had identified a

reasonable cause and corrective actions for the leakage based on inspection results.

The inspectors did not conduct any assessment because this condition did not exist.

The inspection procedure required confirmation that the ECT probes and equipment

were qualified for the expected types of tube degradation and assessment of the site

specific qualification of one or more techniques. The inspectors observed portions of all

ECT performed. During these examinations, the inspectors verified that: (1) the probes

appropriate for identifying the expected types of indications were being used; (2) probe

position location verification was performed; (3) calibration requirements were adhered

to; and, (4) probe travel speed was in accordance with procedural requirements. The

assessment of site specific qualifications of the techniques being used, including a

listing of the specific techniques and qualifications reviewed, is addressed and identified

in the table above.

Finally, the inspection procedure specified the review of one to five samples of ECT data

if questions arose regarding the adequacy of ECT data analyses. The inspectors did

not identify any results where ECT data analyses adequacy was questionable.

Enclosure

-7-

b. Findings

No findings of significance were identified.

.3 Identification and Resolution of Problems

a. Inspection Scope

The inspectors reviewed inservice inspection related condition reports issued during the

current and past refueling outage, and verified that Entergy identified, evaluated,

corrected, and trended problems. In this effort, the inspectors evaluated the

effectiveness of Entergys corrective action process, including the adequacy of the

technical resolutions.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

.1 Biennial Inspection

a. Inspection Scope

The inspectors: (1) evaluated examination security measures and procedures for

compliance with 10 CFR 55.49; (2) evaluated Entergys sample plan of the written

examinations for compliance with 10 CFR 55.59 and NUREG-1021, as referenced in the

facility requalification program procedures; and (3) evaluated maintenance of license

conditions for compliance with 10 CFR 55.53 by review of facility records (medical and

administrative), procedures, and tracking systems for licensed operator training,

qualification, and watchstanding. In addition, the inspectors reviewed remedial training

for examination failures for compliance with facility procedures and responsiveness to

address areas failed.

Furthermore, the inspectors: (1) interviewed 12 personnel, including operators,

instructors/evaluators, and training supervisors, regarding the policies and practices for

administering requalification examinations; (2) observed the administration of two

dynamic simulator scenarios to one requalification crew; and (3) observed four

evaluators administer six job performance measures, including three in the control room

simulator in a dynamic mode and two in the plant under simulated conditions.

The inspectors also reviewed the remediation process for two individuals. The

inspectors also reviewed the results of the annual licensed operator requalification

operating examination for 2002 and 2003. The biennial written examinations that were

administered in September and October 2003 were also reviewed. The results of the

examinations were assessed to determine Entergys appraisal of operator performance

Enclosure

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and the feedback of performance analysis to the requalification training program. The

inspectors interviewed members of the training department and operating crews to

assess the responsiveness of the licensed operator requalification program. The

inspectors also observed the examination security maintenance for the operating tests

during the examination week.

Additionally, the inspectors assessed the Waterford 3 plant referenced simulator for

compliance with 10 CFR 55.46 using Baseline Inspection Procedure IP 71111.11

(Section 03.11). The inspectors assessed the adequacy of Entergys simulation facility

for use in operator licensing examinations and for satisfying experience requirements as

prescribed in 10 CFR 55.46. The inspectors reviewed a sample of simulator

performance test records (transient tests, surveillance tests, malfunction tests, and

scenario-based tests), simulator work request records, and processes for ensuring

simulator fidelity commensurate with 10 CFR 55.46. The inspectors also interviewed

members of Entergys simulator configuration control group as part of this review.

b. Findings

No findings of significance were identified.

.2 Quarterly Inspection

a. Inspection Scope

On October 7, 2003, the inspectors observed a licensed operator simulator training

exercise. During the exercise the inspectors evaluated the operators ability to

recognize, diagnose, and respond to a steam generator tube leak followed by tube

rupture. Additional challenges included loss of component cooling water Pump B,

containment spray Pump B failing to start, failure of pressure level Channel X, reactor

coolant Pump 2B lower seal failure, two stuck control element assemblies, and high

pressure safety injection Pump A failure to start. The inspectors observed and

evaluated the following areas:

• Understanding and interpreting annunciator and alarm signals

• Diagnosing events and conditions based on signals or readings

• Understanding plant systems

• Use and adherence of Technical Specifications

• Crew communications including command and control

• The crews and evaluators critiques

b. Findings

No findings of significance were identified.

Enclosure

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1R12 Maintenance Rule Implementation (71111.12)

a. Inspection Scope

During the inspection period, the inspectors reviewed Entergys implementation of the

Maintenance Rule. The inspectors considered the characterization, safety significance,

performance criteria, and the appropriateness of goals and corrective actions. The

inspectors assessed Entergys implementation of the Maintenance Rule to the

requirements outlined in 10 CFR 50.65, and Regulatory Guide 1.160, Monitoring the

Effectiveness of Maintenance at Nuclear Power Plants, Revision 2. The inspectors

reviewed the following system that displayed performance problems:

• 4kV AC System

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation (71111.13)

a. Inspection Scope

The inspectors reviewed risk assessments for planned or emergent maintenance

activities to determine if Entergy met the requirements of 10 CFR 50.65(a)(4) for

assessing and managing any increase in risk from these activities. The following two

risk evaluations were reviewed:

• On October 3, 2003, and December 11, 2003, planned maintenance was

performed on the digital fault recorders and protective relays in the 230 kV

switchyard associated with offsite power to the Waterford 3 nuclear plant.

• On September 29 through September 30, 2003, during emergent repairs

performed on emergency diesel generator, Train A. Repairs consisted of

replacing a failed fuel line as discussed in Section 4OA3 of this report.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors reviewed the technical adequacy of two operability evaluations to verify

that they were sufficient to justify continued operation of a system or component. The

inspectors considered that, although equipment was potentially degraded, the operability

Enclosure

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evaluation provided adequate justification that the equipment could still meet its

Technical Specification, Updated Final Safety Analysis Report, and design-bases

requirements and that the potential risk increase contributed by the degraded equipment

was thoroughly evaluated. The following evaluations were reviewed:

• Operability evaluation addressing dye penetrant indications on the reactor vessel

head incore instruments nozzles (Condition Report CR-WF3-2003-3307)

• Operability evaluation addressing degraded shutdown cooling suction inside

containment isolation valve (Condition Report CR-WF3-2003-2991)

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds (71111.16)

a. Inspection Scope

The inspectors performed two reviews of operator workarounds. One review was

performed prior to the plant being shutdown for a refueling outage that began

October 20, 2003. The second review was performed immediately following the

refueling outage during full power operations. The reviews evaluated the individual and

cumulative effects of current operator workarounds to assess the associated impact

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

transients and accidents.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed 3 postmaintenance tests for selected risk-significant systems to

verify their operability and functional capabilities. The inspectors considered whether

testing met design and licensing bases, Technical Specifications, and licensee

procedural requirements. The inspectors reviewed the testing results for the following

three components:

• Nitrogen Gas Pressure Indicating Switch NG IPIS0941B following emergent

repairs on September 16, 2003, due to the failure of Nitrogen Accumulator 2

Outlet Valve NG-610 to properly cycle

Enclosure

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• Emergency diesel generator, Train A, following a failed fuel oil tubing line on

September 30, 2003

• Main steam isolation Valves (MSIVs) 1 and 2 actuating system leak tests

performed following system modifications in November 2003

b. Findings

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

Appendix B,Section XI, "Test Control," for the failure to establish adequate test controls

for leak testing MSIVs 1 and 2. This performance deficiency contributed to both valves

being declared inoperable due to system leaks creating a low pressure condition in the

valve actuating systems.

Description. On December 6, 2003, control room operators declared MSIV 1 inoperable

after identifying that the valve actuating system nitrogen pressure was less than the

acceptance criteria of 2520 psig. The inspectors reviewed operator logs and noted that

MSIV 2 had previously been declared inoperable for the same reason at 1:29 a.m. on

November 20, 2003. Entergy had completed a refueling outage and control room

operators declared MSIV 1 operable November 19, 2003, at 11:10 p.m., and MSIV 2

operable November 20, 2003, at 12:01 a.m. The inspectors reviewed work orders and

noted that MSIV 1 valve actuating nitrogen system had been recharged due to low

system pressure on December 1, 2003.

The inspectors reviewed the work history of the MSIVs and noted that both valves had

received a modification that installed a high accuracy pressure instrument in the

nitrogen actuating system. The nitrogen actuating system is a safety related system

having a safety function to close each MSIV within 7 seconds following a main steam

line isolation signal. The inspectors reviewed the postmaintenance test instructions and

noted that the work order specified a leak test of the modified system be performed at

normal system operating pressure. After reviewing operator logs and discussions with

maintenance personnel that performed the leak tests, the inspectors determined that the

leak tests were not performed at normal system pressure. Normal system nitrogen

pressure is approximately 2600 psig and the inspectors determined that the leak tests

were performed at approximately 1200 psig for MSIV 1and 930 psig for MSIV 2. The

individual that performed the test did not recall the pressure that the leak tests were

performed at nor did the individual recall the normal system operating pressure. The

inspectors determined that Entergy had failed to establish adequate test controls for

leak testing the piping connections following the modification. This resulted in the failure

to identify system leaks that eventually resulted in both valves being declared

inoperable.

Analysis. The deficiency associated with this finding was inadequate testing controls.

The inadequate test controls failed to ensure that leak tests of the nitrogen actuating

systems for the MSIVs were performed at normal system pressure (2600 psig)

following modification to the systems. This performance deficiency resulted in the

Enclosure

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failure to identify system leaks which contributed to the valves being declared

inoperable. This finding is more than minor because it affected the Barrier Integrity

Cornerstone objective of providing reasonable assurance of the functionality of

containment. The finding was evaluated using the Phase 1 significance determination

process worksheet. The finding was only of very low safety significance because it did

not represent an actual reduction of the atmospheric pressure control function of the

reactor containment, it did not result in an actual open pathway affecting the physical

integrity of reactor containment, and the main steam isolation valves were inoperable for

less time than the allowed Technical Specification outage time.

Enforcement. 10 CFR Part 50, Appendix B, Criterion XI, "Test Control," states, in part,

that a test program shall be established to assure that all testing required to

demonstrate that structures, systems, and components will perform satisfactorily in

service. The failure to establish testing controls to ensure the MSIVs would perform

satisfactorily in service is a violation of 10 CFR Part 50, Appendix B, Criterion XI.

Because the failure to establish adequate testing controls was of very low safety

significance and has been entered into Entergys corrective action program as Condition

Reports 2003-3716 and 2003-3837, this violation is being treated as a noncited

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

NCV 50-382/2003007-01, Inadequate Test Controls of MSIVs.

1R20 Refueling and Outage Activities (71111.20)

a. Inspection Scope

Refueling Outage 12 began on October 20, 2003, and ended on November 24, 2003.

During the outage, the inspectors observed shutdown, cooldown, refueling, startup, and

maintenance activities to verify that Entergy maintained the plant capabilities within the

applicable Technical Specification requirements and within the scope of the outage risk

plan. Specific performance activities evaluated included:

• Clearance Activities - ensured tags were properly hung and equipment

appropriately configured to support the function of the clearance

• Reactor Water Inventory Controls - verified that flow paths, equipment

configurations, and alternative means for inventory addition were appropriate to

prevent inventory loss

• Reactivity Controls - ensured compliance with Technical Specifications and

verified that activities, which could affect reactivity, were reviewed for proper

control within the outage risk plan

• Refueling Activities - assessed compliance with Technical Specifications, verified

proper tracking of fuel assemblies from the spent fuel pool to the core, and

confirmed that foreign material exclusion was maintained

Enclosure

-13-

• Reduced Inventory and Midloop Conditions - verified that commitments to

Generic Letter 88-17 were in place, that plant configuration was in accordance

with those commitments, and that distractions from unexpected conditions or

emergent work did not affect operator ability to maintain the required reactor

vessel level

• Monitored Shutdown Cooling System - verified that operating parameters were

established and maintained within the required range

• Reactor Coolant System Instrumentation Indication - verified that reactor coolant

system pressure, level, and temperature instrumentation were installed and

configured to provide accurate indication

• Spent Fuel Pool Cooling System Operation - assessed outage work for potential

impact on the ability of the operations staff to operate the spent pool cooling

system during and after core offload

• Containment Closure - reviewed control of containment penetrations to ensure

that containment closure could be achieved within required times during various

portions of the outage Reduced Inventory

• Heatup and Startup Activities - ensured that Technical Specifications and

administrative procedure prerequisites for mode changes were met prior to

changing modes or plant configurations

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors observed or reviewed the following surveillance test to ensure the

system was capable of performing its safety function and to assess its operational

readiness. Specifically, the inspectors considered whether the following surveillance

test met Technical Specifications, the Updated Final Safety Analysis Report, and

licensee procedural requirements:

• Surveillance Procedure OP-903-026, Emergency Core Cooling System Valve

Lineup Verification, Revision 12, performed on November 21, 2003. This

surveillance verified that the appropriate valve lineup was established for low

pressure safety injection system and verified the system was vented and filled

with water.

Enclosure

-14-

b. Findings

As discussed in Section 4OA2 of this report, the inspectors identified a noncited

violation of 10 CFR Part 50, Appendix B, Criterion XVI, for the failure to establish

adequate corrective actions to prevent recurrence of voiding conditions affecting the

operability of the low-pressure safety injection system following shutdown cooling

operations.

2. RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiological Significant Areas (71121.01)

a. Inspection Scope

To review and assess Entergy's performance in implementing physical and

administrative controls for airborne radioactivity areas, radiation areas, high radiation

areas, the inspector interviewed supervisors, radiation workers, and radiation protection

personnel involved in high dose rate and high exposure jobs during the 2003 refueling

outage. The inspector discussed changes to the access control program with the

Radiation Protection Manager. The inspector also conducted plant walkdowns within

the controlled access area and conducted independent radiation surveys of selected

work areas. The following items were reviewed and compared with regulatory

requirements:

• Area postings, radiation work permits (RWPs), radiological surveys, and other

controls for airborne radioactivity areas, radiation areas, and high radiation areas

• High radiation area key control

• Setting, use, and response of electronic personnel dosimeter alarms

• Prejob briefings for the pressurizer heater replacement and upper guide

structure movement work activities

• Conduct of work by radiation protection technicians and radiation workers in

areas with the potential for high radiation dose work associated with refueling

outage activities

• Dosimetry placement when work involved a significant dose gradient (primary

steam generator and reactor head detensioning activities)

• Controls involved with the storage of highly radioactive items in the spent fuel

pool

Enclosure

-15-

• Audits and self-assessments involving high radiation area controls and staff

performance

• Summary of corrective action documents written since the last inspection and

selected documents relating to high radiation area incidents, radiation protection

technician and radiation worker errors, repetitive, and significant individual

deficiencies

• Controls in place to ensure compliance with 10 CFR 20.1703(f)

There were no internal dose events which exceeded 50 millirem committed effective

dose equivalent during this inspection period; therefore, this aspect to the inspection

procedure could not be completed. Performance indicator reviews associated with

occupational exposure control effectiveness are documented in Section 4OA1 of this

report. No licensee event reports or special reports were required in this inspectable

area since the previous inspection. The inspector completed all 21 of the required

samples.

b. Findings

Introduction. The inspector identified a Green, noncited violation of Technical

Specification 6.12.1 because Entergy failed to barricade a high radiation area to prevent

inadvertent entry.

Description. On October 27, 2003, during tours of the reactor containment building the

inspector noted that the high radiation area rope barricading the regenitive heat

exchanger room located on the 21-foot elevation was stretched across the entrance way

at a height of approximately 79 inches, which would not obstruct the entry of station

workers. General area radiation levels were as high as 420 millirem per hour.

Analysis. The inspector determined that Entergys failure to properly barricade a high

radiation area as required by Technical Specification 6.12.1 is a performance deficiency.

Traditional enforcement does not apply because the issue did not have any actual safety

consequences or potential for impacting the NRCs regulatory function and was not the

result of any willful violation of NRC requirements or licensees procedures. The finding

is greater than minor because it is associated with the Occupational Radiation Safety

Cornerstone attribute: program and process, and affected the cornerstone objective to

provide adequate protection to workers health and safety from exposure to radiation.

When the issue was processed through the Occupational Radiation Safety Significance

Determination Process it was determined to be a Green finding because it was not an

ALARA planning and control issue, there was no overexposure or substantial potential

for an overexposure and the ability to assess dose was not compromised.

Enforcement. Technical Specification 6.12.1. states, in part, that each high radiation

area in which the intensity of radiation is greater than 100 millirem per hour but less than

1000 millirem per hour shall be barricaded.

Enclosure

-16-

The failure to place a high radiation barricade to obstruct entry to the regenitive heat

exchanger room is a violation of Technical Specification 6.12.1. Because the finding is

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

Condition Report CR-WF3-2003-03164, this violation was treated as a noncited

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

NCV 50-382/2003007-02, Failure to barricade a high radiation area.

2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

To assess Entergys program to maintain occupational exposures as low as is

reasonably achievable (ALARA), the inspector reviewed work activities conducted during

Refueling Outage 12, and attended the pre-job ALARA brief and observed radiological

work associated with the replacement of the chemical volume control system filter.

The inspector interviewed radiation protection staff members and other radiation

workers to determine the level of planning, communication, ALARA practices, and

supervisory oversight integrated into work planning and work activities. In addition, the

following items were reviewed and compared with procedural and regulatory

requirements:

• Current 3-year rolling average collective exposure

• Six ALARA prejob, in progress, and postjob reviews and associated radiation

work permit packages from Refueling Outage 12 which resulted in some of the

highest personnel collective exposures

• Site specific trends in collective exposures, historical data, and source-term

measurements

• Site specific ALARA program procedures

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

requirements

• Work activity intended dose against actual dose received and the reasons for

any inconsistencies

• Assumptions and basis for annual collective exposure estimates, the

methodology for estimating work activity exposures, and intended dose

outcomes

• Method for adjusting exposure estimates, or re-planning work, when unexpected

changes in job scope or emergent work were encountered

Enclosure

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• Use of engineering controls to achieve dose reductions and the benefits afforded

by using shielding

• Historical trends and current status of tracked plant source terms and

contingency plans due to changes in fuel performance or primary plant chemistry

• Radiation worker performance during work activities in radiation, high radiation or

airborne radioactivity areas

• Declared pregnant workers declared during the assessment period and

monitoring controls and exposure result

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

inspection

• Resolution through the corrective action process of problems identified through

postjob reviews and postoutage report critiques

• The effectiveness of self-assessment activities with respect to identifying and

addressing repetitive deficiencies or significant individual deficiencies

• Summary of corrective action documents written since the last inspection and

selected documents relating to exposure tracking, higher than planned exposure

levels, radiation worker practices, repetitive, and significant individual

deficiencies against the corrective action program

The inspector completed 16 sample requirements.

b. Findings

No findings of significance were identified.

4. OTHER ACTIVITIES

4OA1 Performance Indicator Verification (71151)

a. Inspection Scope

The inspectors sampled licensee submittals for the performance indicators listed below

for the period from April 2002 through September 2003. To verify the accuracy of the

performance indicator data reported during that period, performance indicator definitions

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

Revision 2, were used to verify the basis in reporting for each data element.

Enclosure

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Occupational Radiation Safety Cornerstone

• Occupational Exposure Control Effectiveness Performance Indicator

Licensee records reviewed included corrective action documentation that identified

occurrences of locked high radiation areas (as defined in Technical

Specification 6.12.2), very high radiation areas (as defined in 10 CFR 20.1003), and

unplanned personnel exposures (as defined in NEI 99-02). Additional documents

reviewed included ALARA records and whole body counts of selected individual

exposures. The inspector interviewed licensee personnel that were accountable for

collecting and evaluating the performance indicator data. In addition, the inspector

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

radiation areas were properly controlled. The inspector completed one of the required

inspection samples.

Public Radiation Safety Cornerstone

• Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

Licensee documents reviewed included radiological effluent release corrective action

records and annual effluent release reports during the past four quarters (no licensee

event or special reports were submitted) to determine if any doses resulting from liquid

or gaseous effluent releases exceeded performance indicator thresholds. The

inspectors interviewed licensee personnel that were accountable for collecting and

evaluating the performance indicator data. The inspector completed one of the required

inspection samples.

Barrier Integrity Cornerstone

• Unplanned Scrams

Licensee documents reviewed included control room logs, reactor power profile

obtained from the plant computers, and licensee quarterly operating reports. The

inspector completed one of the required inspection samples.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

Section 2OS2 evaluated the effectiveness of Entergy's problem identification and

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

and radiation worker practices. Section 1RO8.3 evaluated the effectiveness of

Enclosure

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Entergys problem identification and resolution process regarding inservice inspection-

related condition reports issued during the current and past refueling outages. No

findings of significance were identified.

.1 Voiding in the Low Pressure Safety Injection System

a. Inspection Scope

On December 19, 2003, the inspectors completed a review of Entergys actions

regarding voiding in the low pressure safety injection system. Entergys previous

actions to address voiding conditions affecting the emergency core cooling systems for

a number of years are documented in NRC Inspection Report 05000382/2002005. The

long-term voiding issues have contributed to equipment failures along with operations,

engineering, and radiological challenges. The inspectors conducted interviews with

responsible engineers, operators, and managers and reviewed relevant documents and

drawings.

b. Findings

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

Appendix B, Criterion XVI, for the failure to establish adequate corrective actions to

prevent recurrence of voiding conditions affecting the operability of the low pressure

safety injection system following shutdown cooling operations.

Description. On November 21, 2003, following restart from Refueling Outage 12,

Entergy performed ultrasonic testing on low pressure safety injection system, Trains A

and B, per Procedure OP-903-026, Emergency Core Cooling System Valve Lineup

Verification, Revision 12, to determine if the piping was water solid. The ultrasonic

testing identified gas voids at Containment Penetration 38 and Vent Valve SI-134A that

resulted in the low pressure safety injection system Train A being inoperable in

accordance with the procedural acceptance criteria. Subsequently, ultrasonic testing

identified gas voids in the low pressure safety injection system, Train B, at Vent

Valves SI-133B and SI-134B and at Containment Penetrations 36 and 37. The gas void

at Vent Valve SI-134B rendered low pressure safety injection system Train B inoperable.

The inspectors noted that one day following Refueling Outage 11, a gas void was

identified in low pressure safety injection system Train B, which required Train B to be

declared inoperable (Documented in NRC Inspection Reports 05000382/2002002 and

05000-382/2002005). Entergy determined that the root cause for gas voiding in the low

pressure safety injection system was an inadequate plan to vent the gas following the

low pressure safety injection system realignment from shutdown cooling to the safety

injection mode. Entergy placed this degraded condition into their corrective action

process as Condition Report 2002-00818. Corrective actions assigned were to vent and

sweep the low pressure safety injection system with less gas saturated water from the

Enclosure

-20-

refueling water storage pool. Additionally, procedural guidance requiring operators to

ensure work orders were generated to vent and fill the low pressure safety injection

system following shutdown cooling operations was implemented.

Following the identification of gas voids on November 21, 2003, engineering and

operations personnel stated that although work orders were written, operations failed to

accomplish the vent and fill tasks in a timely manner resulting in the accumulation of

voids that rendered the systems inoperable per the proceduralized acceptance criteria.

The inspectors determined that the failure to effectively implement the corrective actions

directed by Condition Report 2002-00818 resulted in unacceptable voids in the low

pressure safety injection system. This failure resulted in a recurrence of a significant

condition adverse to quality and was determined to be a violation of 10 CFR Part 50,

Appendix B, Corrective Action.

Analysis. The deficiency associated with this finding was the failure to establish

corrective measures to prevent recurrence of a significant condition adverse to quality.

Specifically, corrective actions established to address unacceptable gas voids identified

in the low pressure safety injection system following Refueling Outage 11 were not

effectively implemented and failed to prevent recurrence following Refueling Outage 12.

This finding is greater than minor because it affected the mitigating system objective to

ensure the reliability and availability of the low pressure safety injection system to

respond to an initiating event. The problem if left uncorrected would become a more

significant safety concern. The significance of this finding was determined to be of very

low safety significance because Train B was inoperable for less than the Technical

Specification allowed outage time and Train A was determined to be degraded but

operable in accordance with Generic Letter 91-18 guidance.

Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires,

in part, that measures be established to assure that conditions adverse to quality are

promptly identified and corrected. In the case of significant conditions adverse to

quality, the measures shall assure that the cause of the condition is determined and

corrective action taken to preclude repetition. The failure to establish corrective

measures to prevent recurrence of unacceptable void accumulations in the low pressure

safety injection system following shutdown cooling operations is a violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action." Because this finding is of very

low safety significance and has been entered into Entergys corrective action program

as Condition Reports 2003-3740, -3858, and -3901, this violation is being treated as a

noncited violation consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000382/2003007-03, Ineffective Corrective Actions to Prevent Recurrence of Voiding

Conditions.

Enclosure

-21-

.2 Alloy 600 Nozzle Cracking

a. Inspection Scope

During refueling Outage 12 (October 20, 2003, through November 24, 2003) Entergy

identified pressure boundary leakage emanating from three Alloy 600 reactor coolant

system nozzles. The inspectors reviewed Entergys corrective actions associated with

the multiple nozzle failures. Additionally, the inspectors reviewed the corrective and

preventive maintenance history of the reactor coolant system Alloy 600 nozzles. The

inspectors also reviewed previous corrective actions addressing pressure boundary

leakage to evaluate their effectiveness in preventing recurrence.

b. Findings

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

Appendix B, Criterion XVI, for the failure to implement effective corrective actions

resulting in recurrences of pressure boundary leakage due to primary water stress

corrosion cracking of Alloy 600 reactor coolant system nozzles.

Discussion. Entergy identified three reactor coolant system Alloy 600 nozzle leaks

during Refueling Outage 12. The nozzles affected were the reactor coolant system hot

Leg 2 Instrument Nozzle RC-IPT-0106B and two pressurizer heater sleeve Nozzles C-1

and C-3. Each nozzle leak was determined by Entergy to be the result of primary water

stress corrosion cracking. Each nozzle leak was repaired prior to the end of the

refueling outage.

The inspectors reviewed the history of the Alloy 600 nozzles at Waterford 3 and noted

that multiple failures had previously occurred due to primary water stress corrosion

cracking. In Refueling Outage 9, three hot leg nozzles and two pressurizer top nozzles

were found leaking. In Refueling Outage 10, one pressurizer heater sleeve nozzle was

found leaking. The inspectors reviewed Condition Reports 1999-00204, 1999-00232,

1999-00234, 2000-1250, 2003-03130, and 2003-03110. Review of these corrective

action documents revealed that no replacement plans had been established by Entergy

to repair or replace the Alloy 600 nozzles throughout the reactor coolant system that

were susceptible to primary water stress corrosion cracking. The inspectors noted that

Condition Report 2000-1250 stated, Due to the nature of primary water stress corrosion

cracking and the use of Inconel 600 at Waterford 3, recurrence of similar leaks is

considered beyond Waterford 3 control. The inspectors noted that with the current

materials and ongoing actions, that Waterford 3 would be susceptible to future pressure

boundary leakage caused by primary water stress corrosion cracking of Alloy 600 nozzle

material. Operation of Waterford 3 with reactor coolant system boundary leakage is a

condition prohibited by plant Technical Specification 3.4.5.2.a during Modes 1, 2, 3, and

4.

The inspectors noted that Entergy had not initiated actions to prevent the occurrence of

pressure boundary leakage, through the Inconel 600 material nozzles, during either

Enclosure

-22-

Refueling Outages 11 or 12. The inspectors also noted that no inspections other than

visual examinations to find leakage were being performed by Entergy to detect

degradation of the nozzles that would allow for repairs or replacement prior to reactor

coolant system pressure boundary leakage occurring. The inspectors determined that

Entergy had not established adequate measures to prevent recurrence of reactor

coolant system pressure boundary leakage, due to primary water stress corrosion

cracking of Alloy 600 nozzles, a significant condition adverse to quality.

Analysis. The deficiency associated with this finding was the failure to establish

corrective measures to prevent recurrence of a significant condition adverse to quality.

Specifically, Entergy had not established corrective measures to preclude multiple

occurrences of reactor coolant system pressure boundary leakage, during an operating

cycle, due to primary water stress corrosion cracking of Alloy 600 nozzle material. This

finding was greater than minor because it affected the reactor safety barrier integrity

cornerstone objective for providing reasonable assurance that the physical design

barriers protect the public from radionuclide releases caused by accidents or events.

Using NRC Manual Chapter 0609 significance determination process Phase 1

Screening Worksheet this performance deficiency affected the reactor coolant system

barrier function requiring a Phase 2 analysis. The results of the Phase 2 and 3 analysis

determined that this finding was of very low safety significance based on the cracks

being axial in nature (does not contribute substantially to a loss of coolant accident) and

the leaks resulted in a buildup of only minor boric acid residue indicative of only trace

amounts of through wall leakage. The leak rates identified were well within the capacity

of a single charging pump.

Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires,

in part, that measures be established to assure that conditions adverse to quality are

promptly identified and corrected. In the case of significant conditions adverse to

quality, the measures shall assure that the cause of the condition is determined and

corrective action taken to preclude repetition. The failure to establish corrective

measures to prevent recurrence of reactor coolant system pressure boundary leakage

due to primary water stress corrosion cracking of Alloy 600 nozzle material is considered

a violation of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action." Because

this finding is of very low safety significance and has been entered into Entergys

corrective action program as Condition Reports 2003-03130 and 2003-03110, this

violation is being treated as a noncited violation consistent with Section VI.A of the NRC

Enforcement Policy: NCV 05000382/2003007-04, Ineffective Corrective Actions to

Prevent Recurrence of PWSCC of Alloy 600 material.

Enclosure

-23-

4OA3 Event Followup (71153)

.1 Failure of the Train A Emergency Diesel Generator

Description of Event

On September 29, 2003, during the performance of a monthly surveillance run, the

Train A emergency diesel generator experienced a fuel line failure. Approximately

3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> into the surveillance an operator in the Train A diesel room observed the fuel

line break and immediately shutdown the diesel locally in approximately 15 seconds.

The operator reported seeing a solid stream of fuel oil being discharged from the fuel

line break located on the left cylinder bank side of the diesel generator. Approximately

70 gallons of fuel oil was discharged from the line break. Waterford personnel

performed a field inspection and identified that the 3/4 inch stainless steel fuel supply

tube had sheared 360 degrees where the tube inserted into a Swagelok compression

fitting.

Entergy assembled a root cause analysis team to investigate the cause of the failure

and develop a corrective action plan. Plant personnel replaced the failed tubing,

retested the Train A emergency diesel, and restored the diesel to operable status on

September 30, 2003. Examination of the failed tubing indicated that fatigue failure

resulted in the break where the tip of the back ferrule of the compression fitting

contacted the tubing. Entergy determined the Train B emergency diesel generator was

not susceptible to the same failure mechanism since the fuel lines were the original lines

having never been replaced by Entergy.

a. Inspection Scope

The inspector reviewed the sequence of events related to the emergency diesel

generator fuel oil line failure.

The inspector assessed Entergys immediate actions and subsequent evaluation of the

Train A emergency diesel generator failure that occurred on September 29, 2003.

The inspector evaluated pertinent industry operating experience and potential

precursors to the failure of emergency diesel generator fuel oil line at the Swagelock

fitting.

The inspector reviewed and assessed Entergys corrective actions to verify that they

have adequately evaluated and addressed the extent of condition including generic

implications.

The inspector reviewed Entergys root cause evaluation determination for

independence, completeness, and accuracy.

Enclosure

-24-

The inspector, along with a senior reactor analyst inspector, assessed the safety

significance associated with the Train A emergency diesel generator failure.

b. Findings

Introduction. A self-revealing apparent violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, was identified for the failure to

establish appropriate instructions and accomplish those instructions for proper

installation of a fuel line for Train A emergency diesel generator in May of 2003. This

failure resulted in uneven and excessive scoring of the tubing that ultimately led to a

complete 360 degree failure of the fuel supply line on September 29, 2003, during a

monthly surveillance test.

Description. In May of 2003, Entergy performed an overhaul on the Train A emergency

diesel generator. During this overhaul the fuel oil header left/right bank cross connect

tubing and associated fittings were replaced to repair a small fuel oil leak that had been

discovered previously. The tubing was 316 grade stainless steel, 3/4 inch outer

diameter, with a nominal wall thickness of 0.049 inches. The tubing was bent by

mechanical craft personnel at four locations and spanned approximately 5 feet. The

replacement compression fittings were manufactured by Swagelok. After approximately

28.7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of runtime, following the May overhaul, failure of the replaced fuel oil line

occurred on September 29, 2003 during a monthly surveillance test. Entergy noted that

a complete 360 degree failure of the tubing occurred at the compression fitting that

attached the fuel line to the diesel engine left cylinder bank.

Entergy sent the failed specimen to two laboratories for examination to determine the

root cause of the failure. Both labs concluded that fatigue failure of the tubing occurred

at the point where the back ferrule of the compression fitting contacted the outer tubing

surface. It was noted that the tube failure was along the front edge of the back ferrule

and that the outer circumference of the tubing along the fracture was unevenly scored,

up to 30 percent of the tubing thickness. According to Swagelok, a correct installation

would result in an evenly scored tube, approximately 10 percent of the tubing thickness.

Entergy determined that improper alignment of the tubing in the compression fitting and

potential over tightening of the compression fitting resulted in the uneven and excessive

scoring. With these conditions established, the vibrational stresses subjected to the

flawed tubing connection experienced during operation of the diesel generator resulted

in fatigue failure of the tubing on September 29, 2003.

The inspectors reviewed Entergys analysis of the event contained in document CR-

WF3-2003-02759. Entergy concluded that the installation of the replacement tubing

offered minimal margin for error when considering the following design attributes:

• Specified material is thin walled (0.049 inches)

• Large bore tubing $ 1/2 inch

• Configuration is complex containing multiple tube bends

Enclosure

-25-

• Swagelok fittings produce tube scoring

• Vibration is present

Entergy determined that all these factors played a role in causing the tubing failure when

coupled with the tubing not being correctly installed into the Swagelok compression

fitting. Entergy determined that the extent of condition for this type of failure mechanism

was isolated to the Train A emergency diesel generator. A review of past events

revealed that there had been isolated tubing leaks or failures located at Swagelok

fittings that had all occurred greater than three years previous to the failure on

September 29, 2003. The inspectors reviewed these instances and found that there

were slight differences between the identified failure mechanisms, but did note that one

common corrective action was to provide additional training to mechanical maintenance

personnel on how to appropriately install a Swagelok compression fitting application.

The inspectors noted that Entergy relied on skill of the craft to install the fittings with no

detailed instructions or quality control checks provided to ensure the fittings were made

correctly. The inspectors noted that the Swagelok manual contained detailed

instructions for installing the fitting and also recommended the use of a depth marking

tool that could be used to ensure proper tube alignment within the compression fitting.

In review of the training materials and discussions with maintenance department

personnel the inspectors noted that not all Swagelok recommended installation practices

were being implemented by Entergy, including use of the depth marking tool. The

inspectors discussed these observations with licensee senior management who

indicated that they were evaluating enhancements that included more detailed

instructions.

Analysis. The deficiency associated with this event was the failure to establish

appropriate measures to ensure proper installation of a replacement fuel oil line on the

Train A emergency diesel generator in May of 2003. This failure resulted in uneven and

excessive scoring of the tubing that ultimately led to a complete 360 degree failure of

the fuel supply line on September 29, 2003. The finding was greater than minor

because it directly impacted the availability and reliability of an emergency diesel

generator which is used to mitigate the loss of AC power to the respective safety related

bus. The finding was determined to be potentially greater than Green based on a

Phase 1, Phase 2, and Phase 3 analysis.

Significance determination process Phase 1:

In accordance with NRC Inspection Manual Chapter 0609, Appendix A,

Significance Determination of Reactor Inspection Findings for At-Power

Situations, the inspectors conducted a significance determination Phase 1

screening and determined that the finding resulted in loss of the safety function

of the Train A emergency diesel generator for greater than the Technical

Specification allowed outage time. Therefore, a Significance determination

process Phase 2 evaluation was required.

Enclosure

-26-

Significance determination process Phase 2:

The Risk-Informed Inspection Notebook for Waterford Nuclear Plant Unit 3,

Revision 1, September 2, 2003, was utilized for the Phase 2 evaluation of the

inoperable Train A emergency diesel generator. The following steps and the

associated findings are listed below:

• Select or define the applicable initiating event scenarios:

Table 2, Initiators and System Dependency for Waterford Nuclear Plant,

Unit 3, was reviewed to determine that the loss of offsite power (LOOP)

initiating event scenario was the only scenario that needed to be

analyzed due to the failure of the Train A emergency diesel generator.

• Estimate the likelihood of scenario initiating events and conditions:

The performance deficiency was assumed to exist for greater than

30 days based on the failure of the diesel generator being expected to

occur within its mission time. The mechanism leading to the fuel line

break was fatigue failure caused by vibration that only occurred while the

engine was running. No degradation was assumed to occur while the

engine was idle. Therefore, the diesel was destined to fail approximately

28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> after the fuel line was replaced in May of 2003. Using Table 1,

Categories of Initiating Events for Waterford Nuclear Plant, Unit 3, the

initiating event likelihood for loss of offsite power was determined to be

valued at 2.

• Estimate the remaining mitigation capability:

Using the significance determination process worksheet for loss of offsite

power (Table 3.6, SDP Worksheet for Waterford Nuclear Power Plant,

Unit 3 - Loss of Offsite Power (LOOP)), Sequences 1, 2, and 3, the

following results were assigned for each:

Sequence 1: LOOP-EFW - 6

Sequence 2: LOOP-EDG-REC8 - 6

Sequence 3: LOOP-EDG-TDEFW-REC1 - 6

Estimate the risk significance of the inspection finding:

NRC Inspection Manual Chapter 0609, Significance Determination

Process, Appendix A, Attachment 1, Counting Rule Worksheet, was

utilized using three sequences that resulted in values of 6. Since Step 10

was greater than zero, the risk significance of the inspection finding was

determined to be at low to moderate safety significance (White).

Enclosure

-27-

As a result of the White finding in the Phase 2 evaluation, a Phase 3 evaluation

was performed.

Significance Determination Process Phase 3 Analysis

The following table presents the running history of the A emergency diesel

generator from the time of the maintenance until the run failure.

Date Event Run Time Run Time Total Run

(PMT) (Surveillance) Time for

Day

May 16-17, EDG A 39 min 4:15 4:54

2003 Maintenance

Outage

June 9, 2003 Monthly 4:46 4:46

Surveillance

July 8, 2003 Monthly 5:23 5:23

Surveillance

August 4, 2003 Monthly 4:36 4:36

Surveillance

September 2, PMT 20 0:20

2003

September 2, Monthly 5:02 5:02

2003 Surveillance

September 29, Monthly 2:48 (fuel oil 2:48

2003 Surveillance line break)

Cumulative run 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br />

time since 49 minutes

tubing total run

replaced. time for

EDG A

Assumptions:

• The mechanism leading to the fuel line leak was fatigue failure caused by

vibration that occurred while the engine was running. No degradation

occurred while the engine was idle. Therefore, the diesel was destined to

fail after 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> of run time, regardless of how this time was accrued.

Enclosure

-28-

• The primary period of risk was the 27 days of standby service while the

EDG had only 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, 48 minutes of run time remaining. Prior to this

period, the EDG had approximately 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> or more of run time

remaining, and a failure after 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of accident recovery would have

been much less important because of the higher probability of recovering

offsite power or the Train B EDG. The analyst evaluated the 27 day high-

risk period and applied an adjustment factor based on information

received from Entergy to account for the other periods of exposure.

• Based on information received from Entergy, a nonrecovery probability of

0.6 was applied to each cutset that contained a Train B EDG fail-to-start

basic event, but no recovery was assumed for fail-to-run or

test/maintenance situations.

• Based on information received from Entergy, a nonrecovery probability of

0.1 was applied for the Train A EDG, after its failure from a fuel line

failure. This assumption was based on a statistical analysis performed by

Entergy and a walk-through simulation, where a maintenance technician

procured the necessary tools and manufactured a replacement fuel line

segment in approximately 25 minutes. Although this assumption was

used in this analysis, the analyst recognized that certain factors such as

stress, lack of procedures, diversion to other tasks, having only

emergency lighting, and the presence of excess fuel oil could make the

fuel line repair more likely to fail than once in every 10 attempts. A

sensitivity analysis was performed that did not provide recovery credit.

• The postprocessing application of the non-recovery probabilities for

EDG A and B were applied only to SBO sequences 2 and 13 in

accordance with the technical advice of Idaho National Engineering and

Environmental Laboratory (INEEL). Other sequences included recoveries

inherent to the model. SBO sequences 2 and 13 comprised

approximately 80 percent of the change in risk.

• The failure mechanism on EDG A was not a susceptible failure for EDG B

as noted above, therefore, to prevent the SPAR model from imputing a

higher failure rate for EDG B, the basic event for EDG A fail-to-run

was set to a probability of 1.0 in lieu of setting it to TRUE.

• Because EDG A would have run for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and 48 minutes during the

final 27 days of the exposure period, the analyst changed the LOOP

initiating event frequency in both the base and evaluation cases to reflect

the probability that offsite power would be restored prior to the diesel

failure. This is based on the first-order assumption that if offsite power is

recovered prior to the diesel failure, the recovery will be successful.

Using the NUREG-5496 for Waterford 3, the frequency weighted average

probability of recovering offsite power in 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, 48 minutes is

Enclosure

-29-

80 percent. Therefore, the LOOP frequency was changed from 5.2E-

6/hr. to 1.04E-6/hr. Inherent to the analysis was the bounding

assumption that if EDG B fails, it will do so before the failure of EDG A.

To be consistent, the basic event OEP-XHE-NOREC-ST (Operator fails

to recover offsite power in the short term) was set to a probability of 1.0 in

both the base and evaluation cases, since this is implied in the

adjustment to the loss of offsite power frequency.

Quantification of the Change in Risk:

The analyst used SAPHIRE 6.79 software and the Waterford SPAR, Revision 3i

model, further revised by INEEL to include updated offsite power recovery

curves and reactor coolant pump seal failure probabilities.

The update was accomplished to make LOOP recovery times consistent with

NUREG-5496, which reported generally longer times of offsite power recovery

than previous studies. As a protocol, the mission time assigned to the

emergency diesel generator was made equal to the time after a LOOP needed to

achieve a 95 percent probability of recovering offsite power. As a consequence,

the mission time assigned to the emergency diesel generators was extended to

15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />, making the fail-to-run emergency diesel generator events more

important in the calculation. The NRC recently used a similar update to evaluate

an event at the Salem plant in Region I.

To update the base model the following change sets were inserted:

• IE LOOP set to a probability of 1.04E-6/hr

• OEP-XHE-NOREC-ST set to a probability of 1.0

The result obtained was 6.84E-9/hr.

This result was further adjusted to account for the 0.6 non-recovery probability of

the EDG B fail-to-start events in SBO sequences 2 and 13. The total CDF of

these cutsets was 1.44E-10/hr. Therefore the adjusted base model result is:

• 6.84E-9/hr. - 1.44E-10/yr. (1 - 0.6) = 6.78E-9/hr.

To evaluate the risk associated with the performance deficiency, the following

change sets were applied:

• IE LOOP set to a probability of 1.04E-6/hr

• OEP-XHE-NOREC-ST set to a probability of 1.0

• EPS-DGN-FR-DG3A (Diesel Generator 3A-S Fails to Run) set to a

probability of 1.0

Enclosure

-30-

The result obtained was 2.62E-8/hr.

Adjustments were made to cutsets containing SBO sequences 2 and 13 with

either an EDG A FTR or EDG B FTS events, as follows:

SBO sequences 2 and 13 exclusively contain the basic event OEP-XHE-

NOREC-BD (Operators fail to recover AC power before battery depletion)

The recovery of both EDGs applies to the total CDF of cutsets containing OEP-

XHE-NOREC-BD and EPS-DGN-FS-DG3B (EDG B fails to start) and EPS-DGN-

FR-DG3A (Diesel Generator 3A-S Fails to Run) =1.23E-9/hr. Application of

0.1 non-recovery probability for EDG A and 0.6 non-recovery probability for

EDG B results in a total CDF reduction of 1.23E-9/hr. (1.0 - (0.1) (0.6)) = 1.16E-

9/hr.

The recovery of EDG A only applies to the total CDF of cutsets that contain

OEP-XHE-NOREC-BD and EPS-DGN-FR-DG3A (EDG A fails to run), excluding

the cutsets in the group above that contain EPS-DGN-FS-DG3B.

The total CDF of this group is 1.48E-8. Application of 0.1 non-recovery

probability for EDG A results in a total CDF reduction of 1.48E-8/hr. (1.0 - 0.1) =

1.33E-8/hr.

Therefore, the revised CDF for the evaluation case is:

• 2.62E-8/hr. - 1.16E-9/hr. - 1.33E-8/hr. = 1.17E-8/hr.

The change in frequency attributable to the performance deficiency is:

• 1.17E-8/hr. - 6.78E-9hr. = 4.92E-9/hr.

The exposure period of 27 days consists of 648 hours0.0075 days <br />0.18 hours <br />0.00107 weeks <br />2.46564e-4 months <br />. Therefore the delta CDF

of the performance deficiency is:

• 4.92E-9/hr. (648 hour0.0075 days <br />0.18 hours <br />0.00107 weeks <br />2.46564e-4 months <br />s/yr.) = 3.19E-6/yr.

Consideration of other periods of exposure

The analyst evaluated only the final 27 days of exposure when EDG A had only

approximately three hours of run time remaining. Some risk was also incurred

when the EDG had additional run time remaining. In Entergys evaluation the

percentage of the total calculated risk associated with the final 27-day exposure

period was 61.2%. The analyst adjusted the CDF result obtained above by this

percentage to approximate the risk incurred during the entire exposure period.

Enclosure

-31-

Adjusted CDF = 3.19E-6/yr (1/0.612) = 5.21E-6/yr

External Initiators:

The analyst concluded that external initiators would have a negligible impact on

the final result.

High winds or other weather conditions that could cause a loss of offsite power

were included in the updated database used to estimate the LOOP frequency,

and equipment important to mitigating the consequences of these occurrences

are adequately protected from these events.

Seismic events at the plant are rare and of low magnitude, and the plant is

isolated by being situated on a floating island. A seismic event is not likely to

cause an earlier failure of the fuel line fitting because the entire skid would move

as a unit and would not be subjected to the differential stresses caused by the

vibrations of a running engine.

Internal flooding would not likely cause a loss of offsite power or failure of the

Train B EDG and would therefore have little impact on the analysis.

Fires that could cause a loss of offsite power were isolated to two fire areas, both

with frequencies more than two orders of magnitude less than the LOOP

frequency. A fire initiating in the Train A EDG room as a consequence of the

as-found fuel spill was very unlikely because of the lack of sufficient ignition

temperatures on surfaces exposed to the spill. Additionally, a fire in this room

would only affect the operation of the Train A EDG and would not impede

operator access to other mitigating system components. The room contained

automatic detection and suppression devices.

In summary, the overall effect of external initiators would be very small compared

to the internal result.

Large early release frequency:

The analyst reviewed the finding for impact on large early release using

Inspection Manual Chapter 0609, Appendix H. On a loss of power, all

containment isolation and purge valves fail closed. There existed no other

conditions involving containment integrity. Therefore LERF, though slightly

increased because of the increase in delta-CDF, was well below the E-7/yr.

threshold. This is because a release would have occurred only in the event of a

concurrent containment boundary failure.

Enclosure

-32-

Sensitivity Considerations:

If recovery of EDG A is not credited, the resulting delta CDF is 2.00E-5/yr. If

recovery is not credited for either EDG, the result is 2.05E-5/yr.

Conclusion:

The condition was of low to moderate safety significance (WHITE). If credit is

not applied for recovery of EDG A, the result is one of substantial safety

significance (YELLOW).

Enforcement. 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and

Drawings, states in part, that Activities affecting quality shall be prescribed by

documented instructions, procedures, or drawings, of a type appropriate to the

circumstances and shall be accomplished in accordance with these instructions,

procedures, or drawings. The failure to establish appropriate instructions and

accomplish those instructions for installation of the fuel line for Train A emergency diesel

generator resulting in the fuel line failure on September 29, 2003, is a violation of

10 CFR Part 50, Appendix B, Criterion V. Pending determination of the findings final

safety significance, this finding is identified as Apparent Violation (AV)05000382/2003007-05, Failure to establish appropriate instructions and implement

those instructions.

.2 (Closed) Licensee Event Report 50-382/2003-001-00: Loose Breaker Fuse Rendered

One Bank of Pressurizer Proportional Heaters Inoperable

On July 24, 2003, Entergy identified that a loose control power fuse for the Control

Element Drive Motor Generator Set B breaker rendered one bank of pressurizer

proportional heaters inoperable beyond the allowed outage time of Technical

Specification 3.4.3.1. This was determined to be a violation of Technical

Specification 3.4.3.1 (See section 40A7 for details). This finding is more than minor

because it had a credible impact on safety, in that if the redundant group of proportional

heaters did not function, reactor coolant system pressure control under natural

circulation conditions could not be ensured. This finding affects the Mitigating Systems

Cornerstone. Using the significance determination process, this issue was determined

to have a very low safety significance, since only one train of proportional heaters is

required to control reactor coolant system pressure under natural circulation conditions

and operators could manually align the heaters to their emergency power source locally

had the automatic transfer failed during a loss of normal power event. This issue was

entered into Entergys corrective action process as Condition

Report CR-WF3-3003-2076.

Enclosure

-33-

.3 (Closed) Licensee Event Report 50-382/2003-003-00: Reactor Coolant System

Boundary Leakage Due to Primary Water Stress Corrosion Cracking

During Refueling Outage 12, Entergy identified three indications of reactor coolant

system pressure boundary leakage. The first indication was identified on

October 24, 2003, on the hot leg #2 instrument nozzle connected to instrument RC-IPT-

0106B. The other two indications of leakage were identified on October 26, 2003.

These indications were identified on pressurizer heater sleeves C-1 and C-3. This issue

is addressed in Section 4OA2.2 of this report.

4OA4 Crosscutting Aspects of Findings

Section 1R19 of the report describes a human performance crosscutting issue where

personnel failed to establish appropriate postmaintenance testing criteria following a

modification to the main steam isolation valve nitrogen actuating system.

Section 4OA3 of the report describes a human performance crosscutting issue where

maintenance personnel performed improper installation of the EDG Train A fuel oil line.

4OA5 Other Activities

.1 Reactor Pressure Vessel Head and Vessel Head penetration Nozzles (Temporary

Instruction 2515/150, Revision 2)

a. Inspection Scope

The inspectors verified that Entergys susceptibility ranking was high based on the

calculated effective degradation years being 16.95 years through Cycle 12. Entergy

used plant specific temperature data in their susceptibility ranking calculation.

The inspectors noted that examinations were performed by contract Westinghouse and

Entergy personnel. Contract personnel had been qualified using licensee qualification

procedures and all personnel had been qualified using procedures that satisfied

applicable requirements of SNT-TC-1A and ASME Section XI. Westinghouse personnel

performed eddy current testing and ultrasonic examinations. Entergy personnel

performed dye penetrant testing.

The reactor vessel had 102 penetrations (1 reactor head vent, 10 incore instrument

nozzles, and 91 control element drive mechanisms). Entergy performed dye penetrant,

ultrasonic, and eddy current examinations on the penetrations to identify flaws. The

reactor head vent was analyzed using eddy current testing. The control element drive

mechanisms were analyzed using ultrasonic testing. The incore instruments were

analyzed using a combination of eddy current testing, ultrasonic testing, and dye

penetrant testing. Entergy also performed a bare metal visual inspection of 83 vessel

head penetrations. A bare metal visual inspection of the remaining 19 could not be

performed due to concerns with damaging the head vent line. However, Entergy did

Enclosure

-34-

perform a complete inspection of the reactor vessel head using a boroscope. The

inspectors observed the accessible areas of the vessel head and observed selected

portions of the videotaped results of the boroscope data. No evidence of boric acid

leakage was noted.

The inspectors reviewed the results of the eddy current testing of the reactor head vent,

the results of 9 ultrasonic tests on control element drive mechanism, and results of eddy

current, dye penetrant, and ultrasonic tests of 2 incore instruments nozzles. All the

examinations were performed in accordance with approved procedures. The inspectors

reviewed testing results for incore Instrument Penetrations 94 and 98. No indications

were identified on incore Instrument Penetration 98. However, dye penetrant

examinations did identify a 1/2-inch rounded indication at the nozzle to toe weld of

Instrument Penetration 94. This indication exceeded the code criteria for allowable

indication size. This indication was removed mechanically. Additional indications were

also identified on incore Instrument Penetrations 92 and 93. Indications on Instrument

Penetration 92 were rounded 3/32-inch indications on the nozzle to weld toe. The

indication on Instrument Penetration 93 was a 3/16-inch linear indication at the nozzle to

weld toe. This indication exceeded the code criteria for allowable indication size. The

indications were also removed by mechanical removal. The indications were believed to

be weld flaws. No evidence of leakage was found. Followup examinations after repair

revealed no relevant indications. Entergy initiated Condition Report 2003-3307 based

on the results of the of the dye penetrant examinations.

The inspectors reviewed eddy current test results of the reactor head vent penetration

and control element driven mechanism (CEDM) Penetrations 18, 21, 30, 44, 52, 53, 56,

66, and 87. No indications or evidence of leakage were identified.

Entergy used ultrasonic examinations data to provide an assessment of leakage into the

interference fit zone. Guidance for performing this assessment was contained in

Procedure WDI-UT-013, CRDM/ICI UT Analysis Guidelines, Revision 3.

Entergy also performed visual inspections of the top of the cooling shroud. These

inspections were performed using a video camera and a boroscope. No indications of

boric acid buildup were noted.

The inspectors reviewed the approved relaxation requests from the NRC

Order EA-03-009, "Establishing Interim Inspection Requirements for Reactor Pressure

Vessel Heads at Pressurized Water Reactors."

• Relaxation request dated July 1, 2003, allowed Entergy to use eddy current

testing to inspect the vent line nozzle and J-groove weld instead of ultrasonic

testing. The relaxation was approved on October 2, 2003.

Enclosure

-35-

• Relaxation request dated September 15, 2003, allowed the control element drive

mechanism nozzles to be inspected using a three-step alternative involving an

analysis technique, ultrasonic testing, and augmented surface examination. This

request was approved November 12, 2003.

• Relaxation request dated October 24, 2003, allowed ultrasonic testing and

surface examinations of the incore instrument nozzles. This relaxation request

was approved on November 7, 2003.

b. Findings

No findings of significance were identified.

.2 Reactor Containment Sump Blockage (Temporary Instruction 2515/153, Revision 0)

a. Inspection Scope

On November 17, 2003, the inspectors completed a detailed walkdown of the safety

injection sump, drainage paths to the safety injection sump, and evaluated insulation

and material coatings used in containment that could contribute to sump blockage in a

postaccident scenario. The inspectors verified that the safety injection sump screen

was free of adverse gaps and breaches to prevent debris from entering the safety

injection system suction piping. The inspectors assessed Entergys containment foreign

material management control program and verified that Entergy maintained adequate

cleanliness standards to prevent debris transport that could lead to potential blockage of

the safety injection sumps screens. The safety injection sump design and the

containment drainage arrangement was assessed using applicable sections of the

Updated Final Safety Analysis Report, contractor test modeling of the safety injection

system sump and interviews with civil, mechanical, and system engineers. The

inspectors will complete the inspection of Entergys compensatory measures in

response to degraded containment sump performance following development of training

and procedures scheduled to be completed in April 2004.

b. Findings

No findings of significance were identified.

.3 (Closed URI 05000382/0310-01): Possibility of flooding both emergency diesel

generator fuel oil storage tank rooms in the event of a flood and subsequent loss of

offsite power.

a. Inspection Scope

As discussed in NRC Inspection Report 05000382/2003010 a potential finding was

identified in that both emergency diesel generators could be lost due to potential

flooding in the emergency diesel generator fuel oil storage tank rooms due to leaking

Enclosure

-36-

check valves installed in the industrial waste nonsafety-related drain systems connected

to the rooms. The inspectors reviewed Entergys analysis of this potential condition and

discussed the results of the analysis with the responsible system engineers.

b. Findings

No findings of significance were identified.

4OA6 Meetings

Exit Meeting Summary

On December 5, 2003, the inspector presented the ALARA Planning and Controls

inspection results to Mr. J. Venable, Site Vice-President 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 inspector asked Entergy

whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

The inspectors presented the results of the inservice inspection effort to Mr. R. Fili,

Engineering Program Manager and other members of licensee management on

November 6, 2003. Entergy management acknowledged the inspection findings. The

inspectors asked Entergy whether any materials examined during the inspection should

be considered proprietary. Several documents were proprietary information as identified

by Entergy. The inspectors informed Entergy that these documents would be destroyed

upon completion of their review.

The resident inspectors presented the integrated inspection results to Mr. J. Venable,

Site Vice-President and other members of Entergy management at the conclusion of the

inspection on January 5, 2004. Entergy acknowledged the findings presented. The

inspectors asked Entergy whether any materials examined during the inspection should

be considered proprietary. No proprietary information was identified.

4OA7 Licensee Identified Violations

The following violation of very low safety significance (Green) was identified by Entergy

and is a violation of NRC requirements, which meets the criteria of Section VI of the

NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

Technical Specification 3.4.3.1 requires at least two groups of pressurizer proportional

heaters be operable. With one group of pressurizer proportional heaters inoperable,

Entergy must restore the other group within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or be in Mode 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The proportional heaters remained inoperable for about 4 days while the unit was in

Mode 1. Entergy had failed to meet Technical Specification requirements. This issue

was determined to be more than minor because pressurizer proportional heaters help to

ensure the capability of systems that respond to initiating events and was of very low

Enclosure

-37-

safety significant because only one train of proportional heaters is required to control

reactor coolant system pressure under natural circulation conditions and operators could

manually align the heaters to their emergency power source locally had the automatic

transfer failed during a loss of normal power event. This violation is being treated as a

noncited violation, consistent with Section VI.A of the NRC Enforcement Policy. This

issue was entered into Entergys corrective action process as Condition

Report CR-WF3-3003-2076.

ATTACHMENT: SUPPLEMENTAL INFORMATION

Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

S. Anders, Superintendent, Plant Security

T. Brumfield, Manager Quality Assurance

L. Dauzat, Supervisor, Radiation Protection

J. R. Douet, General Manager, Plant Operations

R. Fili, Engineering Program Manager

R. Fletcher, Operations Training Supervisor

C. Fugate, Assistant Manager, Operations

T. Gaudet, Director, Planning and Scheduling

B. Greeson, Code Program Supervisor, Arkansas Nuclear One

B. Houston, Manager, Radiation Protection

R. Jones, Simulator Support Supervisor

P. Kelly, Supervisor, Radiation Protection

C. Lambert, Director, Engineering

J. Laque, Manager, Maintenance

R. Murillo, Engineer, Licensing

R. Osborne, Manager, System Engineering

W. H. Pendergrass, Assistant Operations Manager (Support)

K. Peters, Director, Nuclear Safety Assurance/Emergency Preparedness

G. Pierce, Chemistry Superintendent

G. Scott, Engineer, Licensing

G. Sen, Manager, Licensing

T. E. Tankersley, Manager, Training

J. Venable, Vice President, Operations

K. T. Walsh, Manager, Operations

D. Weber, Codes Program Steam Generator Engineer

NRC

V. Gaddy, Senior Project Engineer, Region IV

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000382/2003007-01 NCV Inadequate Test Controls of MSIVs (Section 1R19)05000382/2003007-02 NCV Failure to barricade a high radiation area (Section 2OS1)05000382/2003007-03 NCV Ineffective Corrective Actions to Prevent Recurrence of

Voiding Conditions (Section 4OA2.1)05000382/2003007-04 NCV Ineffective Corrective Actions to Prevent Recurrence of

PWSCC of Alloy 600 material (Section 4OA2.2)

A-1 Attachment

05000382/2003007-05 AV Failure to establish appropriate instructions and

implement those instructions (Section 4OA3.1)

Closed

05000382/2003007-01 NCV Inadequate Test Controls of MSIVs (Section 1R19)05000382/2003007-02 NCV Failure to barricade a high radiation area (Section 2OS1)05000382/2003007-03 NCV Ineffective Corrective Actions to Prevent Recurrence of

Voiding Conditions (Section 4OA2.1)05000382/2003007-04 NCV Ineffective Corrective Actions to Prevent Recurrence of

PWSCC of Alloy 600 material (Section 4OA2.2)05000382/2003010-01 URI Possibility of flooding both emergency diesel generator

fuel oil storage tank rooms in the event of a flood and

subsequent loss of offsite power (Section 4OA5.3)

05000382/2003-001-00 LER Loose Breaker Fuse Rendered One Bank of Pressurizer

Proportional Heaters Inoperable (Section 4OA3.2)

05000382/2003-003-00 LER Reactor Coolant System Pressure Boundary Leakage

Due to Primary Water Stress Corrosion Cracking

(Section 4.OA3.3)

LIST OF DOCUMENTS REVIEWED

IP 71111.09

Procedures

DC-317, Entergy Steam Generator Administrative Procedure, Revision 1

NOECP-252, Steam Generator Eddy Current Inservice Testing, Revision 8

NOECP-257, Steam Generator Secondary Side Inspection, Revision 3

EPS-001-W, Steam Generator ECT Data Analysis For Waterford 3, Revision 1

QAP-393, Manual Ultrasonic Examination of Welds in Vessels, Revision 3

NDE 9.04, Ultrasonic Examination of Ferritic Piping for ASME Section XI, Revision 3

NDE 9.31, Magnetic Particle Examination (MT) for ASME Section XI, Revision 3

NDE 9.40, Liquid Penetrant Examination (PT), Revision 1

NDE 9.41, Liquid Penetrant Examination (PT) for ASME Section XI, Revision 1

Miscellaneous Documents

ER-W3-2003-0534-000, Steam Degradation Assessment and Repair Criteria for RF12

A-2 Attachment

Eddy Current Acquisition Technique Sheets

WTR-01-03

WTR-A-03

IP 71111.11B

Procedures:

TQ-201, Systematic Approach to Training Process, Revision 1

TQ-202, Simulator Configuration Control, Revision 1

DG-TQ-201, Design and Development Phase, Revision 2

DG-TQ-201, Implementation Phase, Revision 1

DG-TQ-201, Evaluation Phase, Revision 3

DG-TRNW-001, Operator Training Simulator Deskguide, Revision 8

DG-TRNW-003, Operator Training Examination Development and Administration, Revision 6

TDG-SIM-003, Simulator Steady State and Transient Testing, Revision 1

TDG-SIM-016, Configuration Management, Revision 6

TDG-SIM-017, Conducting a Simulator Outage, Revision 1

Simulator Documents:

Simulator Fidelity Report for 2003

Annual Performance Testing Data for 2002

Transient data

Steady State data

Plant Data from Main Turbine Trip on 14 February 2003

Plant Data from Loss of 2B RCP in 1999

Core Performance Data

Miscellaneous:

Licensed operator annual/biennial examination development model

Licensed operator requal sample plan and two-year guide

Biennial exam testable subject matter

Training Review Group Meeting Minutes, June 4, 2002

Training Review Group Meeting Minutes, September 9, 2002

Training Review Group Meeting Minutes, January 7, 2003

Training Review Group Meeting Minutes, February 25, 2003

Training Review Group Meeting Minutes, June 3, 2003

Simulator Scenarios:

E-68

E-70

E-71

E-91

P-76

Job Performance Measures:

SRO-EP-EMERG-1

RO-CPC-NORM-11

RO-CS-EMERG-7

NAO-SDC-NORM

A-3 Attachment

NAO-CED-OFFNORM-2

RO-PPO-OFFNORM-5

Written Examinations:

WWEX-LOR-03061R

WWEX-LOR-03061S

WWEX-LOR-03062R

WWEX-LOR-03062S

Training Evaluation Reviews:

WLP-OPS-SAF00, 2/28/2002

WLP-OPS-REQ22, 2/25/02

WLP-LOR/AOR-REQ21, 2/26/02

WLP-LOR/PPO30, 5/29/02

WSEM-OPS-COACH, 2/28/02

WLP-LOR-LOG00; 8/22/02

WLP-TYH11; 7/8/02

WLP-LOR-PPO020; 5/29/02

WLP-LOR-TYR09; 5/29/02

WLP-LOR-PPE20; 7/1/02

WLP-OPS-CLR00; 2/28/02

WLP-OPS-SP00; 7/10/02

WLP-OPS-CED00; 5/7/03

WLP-LOR-PPO10, PPO40; 2/13/03

WLP-LOR-TYR08; 1/14/03

WLP-OPS-CLR; 7/29/03

WLP-OPS-TS04; 8/21/03

WLP-OPS-RF00; 8/26/03

WLP-OPS-COL; 7/10/03

WLP-OPS-IC01; 6/24/03

Operations Training Coaching Cards for Functional Recovery Procedure Usage:

30097

30119

30331

30353

30354

30808

30836

31068

31767

31800

Management Observation Cards for Technical Specification Recognition:

37335

37456

37496

37612

37614

A-4 Attachment

IP 711111.20

Procedures

Operating Procedure OP-901-521, "Severe Weather and Flooding," Revision 3

Surveillance Procedure OP-903-026, Emergency Core Cooling System Valve Lineup

Verification, Revision 12

Operating Instruction OI-004-000, Operation Shift Logs, Revision 28

Administrative Procedure UNT-007-059, Foreign Material Exclusion, Revision 2

Operating Procedure OP-901-521, "Severe Weather and Flooding," Revision 3

Surveillance Procedure STA-001-005, Leakage Testing of Air and Nitrogen Accumulators for

Safety Related Valves, Revision 6

Surveillance Procedure OP-903-119, Secondary Auxiliaries Quarterly IST Valve Tests,

Revision 7

Surveillance Procedure OP-903-027, Inspection of Containment, Revision 6

Administrative Procedure LI-102, Corrective Action Process, Revision 2

Corrective Action Documents

CR 2003-2076, CR 2003-2089, CR 2003-3858, CR 2003-3911, CR 2003-3901, CR 2003-3729,

CR 2002-0818, CR 1999-0167, CR 1998-1033, CR 2003-3837, CR 2003-3716, CR 2003-3884,

CR 2003-3839, CR 2003-3849, CR 2003-3204, CR 2003-3152, CR 2003-3763, CR 2003-3459,

CR 2003-3458, CR 2003-3536, CR 2003-2674, CR 2003-2900, CR 2003-0201,CR 2003-2615,

CR 2001-0135, CR 2003-0643, CR2003-2589, CR 2003-3515, CR 2003-3897, CR 2003-3379,

CR 2003-3523, CR 2003-3533, CR 2003-3400, CR 2003-3425, CR 2003-3142, CR 2003-3083,

CR 2003-3082, CR 2000-1250, CR 2003-3130, CR 2003-3110, CR 2003-2863, CR 2003-3508,

Other

Engineering Calculation EC-M88-024, Accumulator V, VIII, IX and X Calculation, Revision 3

Engineering Request ER-W3-97-547-00-01, Safety Function of Target Rock Solenoid Valves

and Pressure Regulating Valves in the SC3 Portion of the NG System, Revision 1

Design Engineering Procedure NOECP-451, Conducting Engineering Inspection of Reactor

Containment Building Protective Coatings

Program Section CEP-IST-001, Inservice Testing Plan, Revision 2

Engineering Request ER-W3-00-0890, MSIV Design Basis, Revision 2

A-5 Attachment

NRC Generic Letter 98-04, Potential for Degradation of the Emergency Core Cooling System

and the Containment Spray System After a Loss-Of -Coolant Accident Because of Construction

and Protective Coating Deficiencies and Foreign Material in Containment, dated July 14, 1998

Engineering Calculation EC-S96-012, Si Sump Water Volume and Boron Concentration for

TSP Calculation, Revision A

Engineering Calculation MN(Q)-6-35, Safety Injection System Sump and Screen, Revision 1

NEI 02-01, Condition Assessment Guidelines: Debris Sources Inside PWR Containment,

Revision 1

Engineering Calculation EC-M91-011, NPSH for Safeguard Pumps in Recirculation Mode with

Valve SI-106a(B) Failed Open, Revision 2

NRC Bulletin 2003-01, Potential Impact of Debris Blockade on Emergency Sump Recirculation

at Pressurized-Water Reactors, dated June 9, 2003

Western Canada Hydraulic Laboratories LTD, Model Testing of the Safety Injection System

Sump, dated June 1982

Information Notice 90-10, Primary Water Stress Corrosion Cracking (PWSCC) of INCONEL

600, dated February 23, 1990

Engineering Request ER-W3-99-01-0184-02-12, Weld Repair of Inconel Instrument Nozzles

on the Pressurizer, Revision 12

Work Order Package

31122, 50334786, 13532, 13531, 33801, 33381, 50285047, 32863, 19905, 28970

IP 71121.01

Condition Reports:

CR-WF3-2002-1806, CR-WF3-2002-1851, CR-WF3-2003-322, CR-WF3-2003-814,

CR-WF3-2003-1080, CR-WF3-2003-1290,CR-WF3-2003-1405, CR-WF3-2003-1426,

CR-WF3-2003-1521,CR-WF3-2003-1602, CR-WF3-2003-2268, and CR-WF3-2003-2607

Procedures:

UNT-001-016 Radiation Protection, Revision 1

RP-103 Access Control, Revision 2

RP-105 Radiation Work Permits, Revision 4

RP-108 Radiation Protection Posting, Revision 1

HP-001-107 High Radiation Area Access Control, Revision 16

Radiation Work Permits:

2003-1502 RCP 1B Seal Replacement

2003-1613 Replacement of Pressurizer Heaters

2003-1702 Reactor Disassembly

A-6 Attachment

Self-Assessment and Quality Assurance:

W3F3-2003-0012

QS-2003-W3-002

QS-2003-W3-013

IP 71121.02

Radiation Work Permits

2003-1511 Steam Generator Primary Side Work

2003-1512 Steam Generator Secondary Side Work

2003-1600 Health Physics Surveys and Job Coverage

2003-1610 Erect/Dismantle Scaffolding in RCB

2003-1705 Reactor Re-Assembly

2003-1713 Work involving Non-Destructive Examination under Reactor Head Shield Frame

Procedures

RP-102 Radiological Control, Revision 3

RP-105 Radiation Work Permits, Revision 4

RP-109 Hot Spot Program, Revision 0

RP-110 ALARA Program, Revision 1

RP-205 Prenatal Monitoring, Revision 2

HP-001-101 ALARA Program Implementation, Revision 13

HP-001-114 Installation of Temporary Shielding, Revision 8

Condition Reports

2002-1616, 2002-1759, 2003-0396, 2003-0535, 2003-1853, 2003-1936, 2003-2211, 2003-

2989, 2003-3168, 2003-3253, 2003-3282, 2003-3286, 2003-3361, 2003-3405, 2003-3703,

2003-3718, and ECH-2003-0347

Self-Assessment and Quality Assurance

W3F3-2003-0012 Radiation Protection

W3F3-2003-133 RWP Revisions

QS-2002-W3-092 RWP/ALARA Radiation Practices

WT-ECH-2003-074 RF12 Radiation Protection Outage Readiness

Radiation Protection Assessment dated November 18-22, 2002

TI 2515/150

Procedures:

QAP-410, Reactor Vessel Head VT Examination (Alloy 600), Revision 2

MRS-SSP-1534, Reactor Vessel Head Penetration Inspection Tool Operation, Revision 0

WDI-STD-101, RVHI Vent Tube J-Weld Eddy Current Examination, Revision 2

A-7 Attachment

WDI-ET-003, IntraSpect Eddy Current Imaging Procedure for Inspection of Reactor Vessel

head Penetrations, Revision 5

WDI-ET-004, IntraSpect Eddy Current Analysis Guidelines for Inspection of Reactor Vessel

Head Penetrations, Revision 3

WDI-UT-010, IntraSpect Ultrasonic Procedure for Inspection of Reactor Vessel Head

Penetrations, Time of Flight, Longitudinal Wave & Shear Wave, Revision 6

WDI-UT-011, IntraSpect NDE Procedure for Inspection of Reactor Vessel Head Vent Tubes,

Revision 4

WDI-UT-013, CRDM.ICI Analysis Guidelines, Revision 3

WDI-STD-122, RVHI CEDM Bottom OD Inspection, Revision 0

WCAL-02, Pulser/Receiver Linerarity Procedure, Revision 2

Calculation:

ECM03-010, Calculation of RPV Head Effective Degradation Years

LIST OF ACRONYMS

NRC Nuclear Regulatory Commission

CFR Code of Federal Regulations

ECT eddy current testing

NRR Nuclear Reactor Regulation

MSIV main steam isolation valve

A-8 Attachment