ML042240275

IR 05000247-04-006; 04/1/04 - 06/30/04; Indian Point Nuclear Generating Unit No. 2; Fire Protection; Personnel Performance During Non-Routine Events; Maintenance Effectiveness; and Problem Identification and Resolution

ML042240275
Person / Time
Site:	Indian Point
Issue date:	08/11/2004
From:	Brian Mcdermott Division Reactor Projects I
To:	Dacimo F Entergy Nuclear Operations
McDermott
References
IR-04-006
Download: ML042240275 (41)

See also: IR 05000247/2004006

Text

August 11, 2004

Mr. Fred Dacimo

Site Vice President

Entergy Nuclear Operations, Inc.

Indian Point Energy Center

295 Broadway, Suite 1

P.O. Box 249

Buchanan, NY 10511-0249

SUBJECT:

INDIAN POINT NUCLEAR GENERATING UNIT No. 2 - NRC INTEGRATED

INSPECTION REPORT 05000247/2004006

Dear Mr. Dacimo:

On June 30, 2004, the US Nuclear Regulatory Commission (NRC) completed an inspection at

the Indian Point Nuclear Generating Unit No. 2. The enclosed integrated inspection report

documents the inspection results, which were discussed on July 22, 2004, with Mr. C. Schwarz

and other members of your staff.

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

compliance with the Commissions rules and regulations, and with the conditions of your license.

Within these areas, the inspection consisted of a selected examination of procedures and

representative records, observations of activities, and interviews with personnel.

Based on the results of this inspection, the inspectors identified five findings of very low safety

significance (Green). Four of the findings were determined to be violations of NRC

requirements. However, because of the very low safety significance and because the issues

have been entered into your corrective action program (CAP), the NRC is treating the findings as

non-cited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you

deny these NCVs, you should provide a response with the basis for your denial within 30 days of

the date of this letter, to the Nuclear Regulatory Commission, ATTN: Document Control Desk,

Washington, D.C. 20555-001; with copies to the Regional Administrator, Region 1; the Director,

Office of Enforcement; and the NRC Resident Inspector at Indian Point 2.

Mr. Fred Dacimo

2

In accordance with 10 CFR 2.390 of the NRCs "Rules of Practice," a copy of this letter and its

enclosure will be available electronically for public inspection in the NRC Public Document Room

or from the Publicly Available Records (PARS) component of the NRCs document system

(ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-

rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Brian J. McDermott, Chief

Projects Branch 2

Division of Reactor Projects

Docket No.50-247

License No. DPR-26

Enclosure: Inspection Report 05000247/2004006

w/Attachment: Supplemental Information

cc w/encl:

G. J. Taylor, Chief Executive Officer, Entergy Operations, Inc.

M. R. Kansler, President - Entergy Nuclear Operations, Inc.

J. T. Herron, Senior Vice President and Chief Operating Officer

C. Schwarz, General Manager - Plant Operations

D. L. Pace, Vice President, Engineering

B. OGrady, Vice President, Operations Support

J. McCann, Director, Licensing

C. D. Faison, Manager, Licensing, Entergy Nuclear Operations, Inc.

P. Conroy, Manager, Licensing, Entergy Nuclear Operations, Inc.

M. Colomb, Director of Oversight, Entergy Nuclear Operations, Inc.

J. Comiotes, Director, Nuclear Safety Assurance

J. M. Fulton, Assistant General Counsel, Entergy Nuclear Operations, Inc.

P. R. Smith, President, New York State Energy, Research

and Development Authority

J. Spath, Program Director, New York State Energy Research and Development Authority

P. Eddy, Electric Division, New York State Department of Public Service

C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law

T. Walsh, Secretary, NFSC, Entergy Nuclear Operations, Inc.

D. ONeill, Mayor, Village of Buchanan

J. G. Testa, Mayor, City of Peekskill

R. Albanese, Executive Chair, Four County Nuclear Safety Committee

S. Lousteau, Treasury Department, Entergy Services, Inc.

Chairman, Standing Committee on Energy, NYS Assembly

Chairman, Standing Committee on Environmental Conservation, NYS Assembly

Chairman, Committee on Corporations, Authorities, and Commissions

M. Slobodien, Director, Emergency Planning

Mr. Fred Dacimo

3

B. Brandenburg, Assistant General Counsel

P. Rubin, Manager of Planning, Scheduling & Outage Services

Assemblywoman Sandra Galef, NYS Assembly

County Clerk, Westchester County Legislature

A. Spano, Westchester County Executive

R. Bondi, Putnam County Executive

C. Vanderhoef, Rockland County Executive

E. A. Diana, Orange County Executive

T. Judson, Central NY Citizens Awareness Network

M. Elie, Citizens Awareness Network

D. Lochbaum, Nuclear Safety Engineer, Union of Concerned Scientists

Public Citizens Critical Mass Energy Project

M. Mariotte, Nuclear Information & Resources Service

F. Zalcman, Pace Law School, Energy Project

L. Puglisi, Supervisor, Town of Cortlandt

Congresswoman Sue W. Kelly

Congresswoman Nita Lowey

Senator Hillary Rodham Clinton

Senator Charles Schumer

J. Riccio, Greenpeace

A. Matthiessen, Executive Director, Riverkeeper, Inc.

M. Kapolwitz, Chairman of County Environment & Health Committee

A. Reynolds, Environmental Advocates

M. Jacobs, Director, Longview School

D. Katz, Executive Director, Citizens Awareness Network

P. Gunter, Nuclear Information & Resource Service

P. Leventhal, The Nuclear Control Institute

K. Coplan, Pace Environmental Litigation Clinic

R. Witherspoon, The Journal News

W. DiProfio, PWR SRC Consultant

D. C. Poole, PWR SRC Consultant

W. Russell, PWR SRC Consultant

W. Little, Associate Attorney, NYSDEC

Mr. Fred Dacimo

4

Distribution w/encl:

(via E-mail)

S. Collins, RA

J. Wiggins, DRA

C. Miller, RI EDO Coordinator

R. Laufer, NRR

P. Milano, PM, NRR

D. Skay, PM, NRR (Backup)

B. McDermott, DRP

W. Cook, DRP

C. Long, DRP

P. Habighorst, DRP, Senior Resident Inspector - Indian Point 2

M. Cox, DRP, Resident Inspector - Indian Point 2

R. Martin, DRP, Resident OA

Region I Docket Room (w/concurrences)

DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML042240275.wpd

After declaring this document An Official Agency Record it will be released to the Public.

To receive a copy of this document, indicate in the box: "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy

OFFICE

RI/DRP

RI/DRP

RI/DRP

NAME

PJHabighorst/WAC for WCook/WAC

BJMcDermott/BJM

DATE

08/11/04

08/11/04

08/11/04

OFFICIAL RECORD COPY

Enclosure

i

U.S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No.

50-247

License No.

DPR-26

Report No.

05000247/2004006

Licensee:

Entergy Nuclear Northeast

Facility:

Indian Point Nuclear Generating Unit No. 2

Location:

Buchanan, New York 10511

Dates:

April 1, 2004 - June 30, 2004

Inspectors:

P. Drysdale, Senior Resident Inspector

M. Cox, Resident Inspector

W. Cook, Senior Project Engineer

M. Snell, Reactor Inspector

J. Noggle, Senior Radiation Specialist

P. Habighorst, Senior Resident Inspector

S. Barr, Senior Reactor Engineer

J. Schoppy, Senior Reactor Engineer

Approved by: Brian J. McDermott, Chief

Projects Branch 2

Division of Reactor Projects

Enclosure

ii

CONTENTS

Summary of Plant Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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

1R04

Equipment Alignments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1R05

Fire Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

1R06 Flood Protection Measures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1R07

Heat Sink Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

1R11

Licensed Operator Requalification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

1R12

Maintenance Effectiveness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

1R13

Maintenance Risk Assessment and Emergent Work Activities . . . . . . . . . . . . . 12

1R14

Personnel Performance During Non-Routine Plant Evolutions and Events . . . 12

1R15

Operability Evaluations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

1R19

Post Maintenance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1R22

Surveillance Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

1R23

Temporary Plant Modifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

1EP6

Emergency Plan Drill

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

RADIATION SAFETY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2OS3 Radiation Monitoring Instrumentation and Protective Equipment . . . . . . . . . . . 19

OTHER ACTIVITIES (OA) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

4OA1 Performance Indicator (PI) Verification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

4OA2 Identification and Resolution of Problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

4OA3 Event Followup

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

4OA5 Other Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

4OA6 Meetings, Including Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

4OA7 Licensee-Identified Violation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

ATTACHMENT: SUPPLEMENTAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

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

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . A-2

LIST OF BASELINE INSPECTIONS PERFORMED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3

LIST OF DOCUMENTS REVIEWED

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-3

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

Enclosure

iii

SUMMARY OF FINDINGS

IR 05000247/2004006; 04/1/04 - 06/30/04; Indian Point Nuclear Generating Unit No. 2; Fire

Protection; Personnel Performance During Non-Routine Events; Maintenance Effectiveness;

and Problem Identification and Resolution.

The report covers a three month period of inspection by resident and region-based inspectors.

Four Green non-cited violations (NCVs) and one Green finding were identified. The

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

Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings

for which the SDP 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

Green. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, for Entergys failure to translate the

emergency core cooling system (ECCS) design basis into recirculation sump

modification instructions. Specifically, Entergy added penetration cover plates

and alignment collars around several small pipes that penetrated the sump deck

plating, and the annular gap between the collars and pipes exceeded the sump

screen size.

This finding is more than minor because it potentially affected the mitigating

systems cornerstone objective of ensuring the availability, reliability, and

capability of ECCS. This finding is considered to be of very low safety

significance, because ECCS remained operable and there was no loss of safety

function. (Section 1R07.1)

Green. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, for Entergys failure to promptly

identify and take actions to address conditions adverse to quality associated with

the ECCS recirculation sump. Specifically, Entergy did not identify debris in

containment and recirculation sump bypass pathways that had the potential to

adversely impact ECCS during containment recirculation.

This finding is more than minor because it potentially affected the mitigating

systems cornerstone objective of ensuring the availability, reliability, and

capability of ECCS. This finding is considered to be of very low safety

significance, because ECCS remained operable and there was no loss of safety

function. (Section 1R07.2)

Summary of Findings (contd)

Enclosure

iv

Green. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, for Entergys failure to promptly

identify and take actions to address a condition adverse to quality concerning

emergency diesel generator (EDG) heat exchanger (HX) fouling.

This finding was more than minor because it potentially affected the mitigating

systems cornerstone objective of ensuring the availability and reliability of the

EDG HXs to perform their intended safety function. This finding was associated

with the equipment performance attribute of the mitigating systems cornerstone.

However, this finding was determined to have very low safety significance

because the EDG HXs remained operable and capable of performing their

intended safety function. (Section 1R07.3)

Green. The inspectors identified a finding due to ineffective and untimely

corrective actions associated with the 13.8 KV system during reduced voltage

conditions.

This finding was determined to be greater than minor since it impacts the

mitigating systems cornerstone objective of ensuring system reliability and

capability as associated with the procedure quality attribute of that cornerstone.

This finding was of very low safety significance since there was no loss of the

normal offsite power supplies and the 13.8 KV system was not providing power

to any safety-related loads during the degraded condition. (Section 1R15)

Green. The inspectors identified a non-cited violation of Technical Specification

Surveillance Requirement SR 3.3.1.1. that requires, in part, that a channel check

be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> on the feedwater flow instrumentation in the central

control room. This requirement had not been met since Entergy implemented

the Improved Technical Specifications in December of 2003.

This finding is greater than minor because it represents a condition similar to

example 1.c in Appendix E, IMC 0612, in that the Technical Specification

surveillance was not performed over an extended period (December 12, 2003

through June 8, 2004). The finding is of very low safety significance because the

feedwater flow instruments met the surveillance criteria when subsequently

performed, and did not render the mitigating equipment inoperable. (Section

1R22)

B.

Licensee-Identified Violation

A violation of very low safety significance, which was identified by the licensee has been

reviewed by the inspectors. Corrective actions taken or planned by the licensee have

been entered into the licensees Corrective Action Program. This violation and

corrective actions is listed in Section 4OA7 of this report.

Enclosure

REPORT DETAILS

Summary of Plant Status

The Indian Point Nuclear Generating Unit No. 2 (IP2) reactor was at 100% power at the

beginning of the inspection period and remained at that level through the inspection period.

1.

REACTOR SAFETY

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

Planning

1R04

Equipment Alignments

a.

Inspection Scope

Partial System Walkdowns (71111.04 - 3 samples)

The inspectors performed system walkdowns during periods of equipment unavailability

in order to verify that the alignment of the available train was proper to support the

associated safety functions and to ensure Entergy had identified equipment

discrepancies that could potentially impair the functional capability of the available train.

The inspectors reviewed applicable system drawings and check-off lists to verify proper

alignment and observed the physical condition of the equipment during the verification.

The following walkdowns were performed.

Gas Turbine 3 (GT-3) while GT-1 was out of service for scheduled maintenance.

Safety Injection Trains 21 & 23; safety injection pump 22 was out of service

during preventive maintenance on MOV-851A/B and -887A/B.

Essential and non-essential service water headers after the quarterly header

swap.

Complete System Walkdown (71111.04S - 1 sample)

The inspectors performed an extensive walkdown of the 480 Volt system. The

inspectors walked down the entire system, with the exception of those components

located in the vapor containment, using revision 22 of procedure 2-COL 27.1.5, 480V

AC Distribution. The inspectors verified that components were in the proper position

per the checkoff list (COL) and verified that any position discrepancies were properly

documented. The inspectors also verified that the field configuration was consistent

with the current revision of the COL. The inspectors reviewed condition reports CR-IP2-

2004-1870, 1909 and 1911 which were written to address discrepancies between the

field configuration and current COL that were identified by the inspectors. The

inspectors verified that the associated corrective actions were appropriate. The

inspectors also evaluated the physical condition of the equipment during the walkdown.

2

Enclosure

b.

Findings

No findings of significance were identified.

1R05

Fire Protection

a.

Inspection Scope (71111.05Q - 7 samples)

The inspector toured areas that were identified as important to plant safety and risk

significant. The inspector consulted Section 4.0, Internal Fires Analysis, and the top

risk significant fire zones in Table 4.6-2, Summary of Core Damage Frequency

Contributions from Fire Zones, within the Indian Point 2 Individual Plant Examination for

External Events (IPEEE). The objective of this inspection was to determine if Entergy

had adequately controlled combustibles and ignition sources within the plant, effectively

maintained fire detection and suppression capability, and had adequately established

compensatory measures for degraded fire protection equipment. The inspector

evaluated conditions related to: 1) control of transient combustibles and ignition sources;

2) the material condition, operational status, and operational lineup of fire protection

systems, equipment and features; and 3) the fire barriers used to prevent fire damage or

fire propagation. The areas reviewed were:

Zone 23, Auxiliary Boiler Feedwater Pump Room

Zone 21, Main Turbine Hydrogen Seal Oil Unit

Zones 55A, 56A, 57A, 58A, 21 & 22 Main Transformers, Unit Auxiliary

Transformer and Station Auxiliary Transformer

Zone 140, Ventilation Equipment Room

Zone 86A, 95 ft. Vapor Containment (VC) Refueling Floor

Zones 72A, 75A, 76A, and 77A, 46 ft. Vapor Containment, Outer Annulus Areas

Zones 80A, 81A, 82A, 83A, and 84A, 68 ft. Vapor containment, Containment fan

Cooler Areas

Reference material used by the inspector to determine the acceptability of the observed

condition of the fire areas included: the Fire Protection Implementation Plan; Pre-Fire

Plan; Station Administrative Order (SAO)-700, Fire Protection and Prevention Policy;

ENN-DC-161, Transient Combustible Program; SAO-703, Fire Protection Impairment

Criteria and Surveillance; and Calculation PGI-00433, Combustible Loading

Calculation.

b.

Findings

No findings of significance were identified.

3

Enclosure

1R06 Flood Protection Measures

a.

Inspection Scope (71111.06 - 1 sample)

The inspectors toured all elevations in the primary auxiliary building (PAB) that

contained equipment used to detect and mitigate an internal flood, and components

required for safe plant shutdown, with particular emphasis on the component cooling

water (CCW) pump and residual heat removal (RHR) pump areas. The areas selected

contained risk significant equipment based on the Individual Plant Examination for

External Events (IPEEE), Section 5, Internal Flooding. Internal flooding induced from

fire protection line breaks inside or just outside the PAB were predicted at mean

frequencies of 7.9E-5/year in the CCW pump area and 1.3E-4/year in the RHR pump

area. The inspectors verified the accuracy of the descriptive text in the IPEEE,

compared it with the actual conditions in the PAB, and assessed the physical condition

of the fire protection piping and components in those areas. Licensee-identified

equipment deficiencies awaiting corrective action were discussed with the fire protection

system engineer to confirm these conditions had been adequately evaluated.

b.

Findings

No findings of significance were identified.

1R07

Heat Sink Performance

a.

Inspection Scope (71111.07B - 1 sample)

Based on risk significance, resident inspector input, and the last biennial inspection, the

inspectors selected the RHR heat exchangers (HXs), the safety injection (SI) pump oil

coolers, and the EDG lube oil and jacket water (JW) HXs for this biennial review. The

EDG HXs transfer their heat loads directly to the service water (SW) system. The RHR

HXs and the SI pump coolers transfer their heat loads indirectly to the SW system

through an intermediate system (the component cooling water system). The SW

system was designed to supply cooling water from the Hudson River (the ultimate heat

sink) to various heat loads to ensure a continuous flow of cooling water to systems and

components necessary for plant safety during normal operation and under abnormal or

accident conditions.

The inspectors reviewed Entergys inspection, cleaning, chemical control, and

performance monitoring methods and frequency for the selected components to ensure

alignment with Entergys response to Generic Letter 89-13, Service Water System

Problems Affecting Safety-Related Equipment. The inspectors compared surveillance

test and inspection data to the established acceptance criteria to verify that the results

were acceptable and that operation was consistent with design. The inspectors walked

down the selected HXs, the sodium hypochlorite system, and the SW system to assess

the material condition of these systems and components. In addition, the inspectors

evaluated the containment fan cooler unit cooling coils and the containment sump for

4

Enclosure

indications of boric acid residue (indicative of potential reactor coolant system leakage)

during a containment walkdown to inspect the RHR HXs.

The inspectors also reviewed a sample of condition reports (CRs) related to the selected

HXs and the SW system to ensure that Entergy was appropriately identifying,

characterizing, and correcting problems related to these essential systems and

components. (The attachment to this report for Supplementary Information contains a

complete listing of documents reviewed.)

b.

Findings

1.

Recirculation Sump Deck Plate Design Deficiency

Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, for Entergys failure to translate the emergency

core cooling system (ECCS) design basis into recirculation sump modification

instructions. This finding is considered to be of very low safety significance because

there was no loss of safety function.

Description. The IP2 recirculation sump is designed with a course grating (1" x 4") and

a fine mesh screen (1/8" x1/8"). A solid deck plate at containment floor level is designed

as a barrier to preclude debris from entering the recirculation pump suction without

passing through the grating and the mesh screen. Entergy had previously modified the

sump to add penetration cover plates and alignment collars to cover existing gaps

around several small bore pipes that penetrate the sump deck plating.

During a containment walkdown on April 13, the inspectors noted several issues not

previously identified by Entergy. The inspectors identified loose sump deck plate

penetration cover plates and missing deck plate anchor bolts (see Section 1R07.2

below). Upon further review, the inspectors questioned the gap between the alignment

collars and the pipes penetrating the sump. During a subsequent sump inspection,

engineering determined that the annular gap between the alignment collars and the

pipes all exceeded 1/8". Entergy initiated condition reports to address these

deficiencies (CR-IP2-2004-01781, 2004-01820, 2004-01948, and 2004-01951). On

April 22, Entergy installed a temporary alteration (TA-04-2-078) to close the gap

between the collar and the piping and to hold the collars and cover plates in place to

preclude them from lifting or being dislodged during a LOCA blowdown.

Entergy evaluated the forces acting on the penetration cover plates and the solid deck

plate and determined that the plates would not have lifted or been dislodged during a

LOCA blowdown. Entergy also performed an operability evaluation for the pre-existing

annular gaps between the collars and the penetrating piping. Entergy determined that

these screen bypass flowpaths did not adversely affect the operability of the ECCS

components or the containment spray (CS) system. Entergys determination was based

primarily on: (1) calculation FMX-00142-00, Study the Effect of LOCA Generated

Debris on ECCS Performance; (2) the relatively low recirculation flow velocity (< 0.5

fps); (3) recirculation sump area layout (missile shield and other structures block larger

5

Enclosure

debris); (4) time to switch over to recirculation; (5) ECCS, fuel assembly, and CS system

flow path clearances; and (6) the relative size of the bypass paths compared to the

recirculation sump floor grating surface area (six square inches total compared to 48

square feet). The inspectors reviewed Entergys operability determination and the

applicable UFSAR sections to ensure that operability was justified and that potentially

affected ECCS components and CS remained available and capable of performing their

respective design functions.

Analysis. This issue was a performance deficiency because Entergy failed to

incorporate the recirculation design basis information in a modification which added

penetration cover plates and alignment collars around several small bore pipes that

penetrated the sump deck plating. Given the NRC correspondence and industry OE

relative to containment sump issues, the deficiency was reasonably within Entergys

ability to foresee and correct prior to April 2004.

The inspectors determined that this finding was more than minor because it potentially

affected the mitigating systems cornerstone objective of ensuring the availability,

reliability, and capability of ECCS sump recirculation to provide long-term heat removal.

This finding was associated with the design control and human performance attributes.

The inspectors determined that the finding was of very low safety significance (Green)

by the SDP Phase 1 screening worksheet for Mitigating Systems because the

containment sump screen qualification deficiency was evaluated in accordance with

NRC Generic Letter 91-18 (CR-IP2-2004-1948) and was confirmed not to result in a loss

of the long-term heat removal function.

Enforcement. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that

measures shall be established to assure that applicable regulatory requirements and the

design basis are correctly translated into specifications, drawings, procedures, and

instructions. Contrary to this requirement, Entergy failed to correctly translate the ECCS

design basis (sump screen dimensions) into the recirculation sump modification

instructions, thus potentially impacting long-term heat removal function. However,

because of the very low safety significance and because the issue was entered into

Entergys Corrective Action Program (CAP) (CRs 2004-01781, 2004-01820, 2004-

01948, and 2004-01951), this finding is being treated as a non-cited violation, consistent

with Section VI.A of the Enforcement Policy, issued May 1, 2000 (65FR25368).

(NCV 50-247/04-06-01; Failure to implement appropriate design controls during

modifications to the recirculation sump)

2.

Recirculation Sump Bypass Path and Debris

Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, for Entergys failure to promptly identify

and take actions to address a condition adverse to quality concerning debris in

containment and a recirculation sump bypass path. This finding is considered to be of

very low safety significance because there was no loss of safety function.

6

Enclosure

Description. During a containment walkdown on April 13, the inspectors noted several

recirculation sump related issues not previously identified by Entergy. Debris inside

containment consisted of: a solid metal piece (2.5" in length, 3/8" diameter tapered to

1/8") located atop the sump deck plate cover (46 elevation); a putty knife (5" in length

with a wooden handle) located beneath RHR piping (68 elevation) directly above the

recirculation sump; and, an AA battery in the RHR HX room (68 elevation). Entergy

personnel also found a 5" pencil located on the floor outside the crane wall (46

elevation) and a small plastic bag (6" square) located on the floor (68 elevation). The

inspectors also identified a gap (approximately 1" x 3") between adjacent penetration

cover plates. During the walkdown, Entergy personnel removed the debris and

repositioned the loose penetration cover plate to close the gap. Entergy initiated CR-

IP2-2004-01781 to address these deficiencies.

Entergy performed an operability evaluation for the bypass path and the debris. Entergy

determined that this screen bypass flowpath and debris did not adversely affect the

operability of the ECCS components or the CS system. The inspectors reviewed

Entergys operability determination and the applicable UFSAR sections to ensure that

operability was justified and that potentially affected ECCS components and CS

remained available and capable of performing their respective design functions.

Entergy procedure SAO-213, Containment Entry, Egress and Inspection, Revision 4,

Attachment V, requires personnel to verify recirculation sump grating and floor in place

and pipe collars in place and to verify ALL debris removed. Entergy last implemented

Attachment V during their containment closeout in August 2003. The inspectors

considered this a missed opportunity as Entergy should have identified these

deficiencies prior to reactor startup in August 2003. Failure to do so represents a

weakness in Entergys attention-to-detail and problem identification during containment

closeout inspections. The August 2003 IP2 startup was also a missed opportunity to

apply IP3 operating experience related to containment sump deficiencies identified by

the NRC in April 2003. Although the inspectors could not determine with complete

certainty that the IP2 bypass path and containment debris existed at the time of

Entergys containment closeout inspection in August 2003, Entergy was not able to

identify any work activity performed in the recirculation sump area since that time.

Moreover, Entergy personnel offered that the misaligned deck cover plate and debris

may have existed since their Fall 2002 refueling outage due to the limited work in

containment during their August 2003 outage. In addition, the inspectors noted that

Entergy's monthly containment building inspections were missed opportunities to identify

these deficiencies.

Analysis. Entergys failure to identify degraded conditions with the potential to impact

operability of the recirculation sump is a performance deficiency. Given the NRC

correspondence and industry OE relative to containment sump issues, these

deficiencies were reasonably within Entergys ability to identify and correct prior to April

2004.

The inspectors determined that this finding was more than minor because it potentially

affected the mitigating systems cornerstone objective of ensuring the availability,

7

Enclosure

reliability, and capability of ECCS to respond to initiating events (LOCAs) to prevent

undesirable conditions. This finding was associated with the procedure quality and

human performance attributes as well as the cross-cutting issue of problem identification

and resolution. The inspectors determined that the finding was of very low safety

significance (Green) by the SDP Phase 1 screening worksheet for mitigating systems

because ECCS and CS remained operable and there was no loss of safety function.

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

part, that conditions adverse to quality are promptly identified and corrected. Contrary

to this requirement, Entergy failed to promptly identify and correct deficiencies

associated with the recirculation sump. Specifically, debris inside containment and a

sump screen bypass pathway existed from August 2003 until April 2004. However,

because of the very low safety significance and because the issue was entered into

Entergys CAP (CR-IP2-2004-01781), this finding is being treated as a non-cited

violation, consistent with Section VI.A of the Enforcement Policy, issued May 1, 2000

(65FR25368). (NCV 50-247/04-06-02; Failure to identify and correct deficiencies

associated with the recirculation sump)

3.

Emergency Diesel Generator Heat Exchanger Fouling Evaluation

Introduction. The inspectors identified a non-cited violation of 10 CFR Part 50, Appendix

B, Criterion XVI, Corrective Action, for Entergys failure to promptly identify and take

actions to address a condition adverse to quality concerning emergency diesel

generator (EDG) heat exchanger (HX) fouling. This finding was considered to be of

very low safety significance because there was no loss of safety function.

Description. Based on a review of digital pictures from a February 2003 inspection, the

inspectors noted an excessive buildup of silt, grass, and other small river debris on the

No. 21 EDG lube oil and jacket water (JW) HXs (service water side, tube inlet, upper

return). System engineers had not identified the condition as a negative trend even

though the as-found grass/silt loading was significantly greater than previously found

during EDG HX inspections. The inspectors made this assessment based on the EDG

HX inspection reports available for review.

In addition, the inspectors noted that the following shortcomings contributed to Entergys

ineffective EDG HX trending and weak problem identification:

Lack of detail in the documentation of the as-found condition relative to the

length, width, height, and depth of fouling buildup (SE-330, Attachment III, Visual

Inspection).

No documentation of the in-service time between inspections (SE-330,

Attachment III, Trending).

Previously completed inspection reports did not always contain as-found data

(usually in the form of digital pictures) for both EDG HXs (SE-330, Attachment

III, Visual Inspection).

8

Enclosure

The Heat Exchanger Inspection Report, SE-330, did not provide guidance for the

use of a flashlight to evaluate the acceptability of tube fouling (Entergy personnel

used skill of the craft in using a flashlight to determine if tube blockage existed).

The Heat Exchanger Inspection Report, SE-330, did not provide well-defined

acceptance criteria with respect to fouling buildup.

Engineering determined that the No. 21 EDG had remained operable based on

satisfactory EDG surveillance testing, EDG HX inspection results since February 2003,

and an ultrasonic flow measurement on the No. 23 EDG JW HX service water outlet on

April 21, 2004.

Analysis. The performance deficiency involved inadequate problem identification and

evaluation of a condition adverse to quality associated with increased fouling in the No.

21 EDG HXs. The inspectors determined the finding was more than minor because it

potentially affected the mitigating systems cornerstone objective of ensuring availability,

reliability, and capability of the EDGs to perform their safety function to provide

emergency power to mitigating systems. This finding was associated with the

equipment performance attribute of the mitigating systems cornerstone as well as the

cross-cutting issue of problem identification and resolution. However, this finding was

determined to have very low safety significance (Green) using the SDP Phase 1

screening worksheet because the EDG HXs remained operable and capable of

performing their intended safety function.

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

part, that conditions adverse to quality be promptly identified and corrected. Contrary to

this requirement, Entergy did not identify a condition adverse to quality associated with

EDG HX fouling and take appropriate actions to ensure that the cause was determined

and corrected. However, because the violation is of very low significance (Green) and

Entergy entered this deficiency into their corrective action system (CR IP2-2004-02241),

this finding is being treated as a non-cited violation, consistent with Section VI.A of the

Enforcement Policy, issued May 1, 2000 (65FR25368). (NCV 50-247/04-06-03; Failure

to identify a condition adverse to quality which could impact EDG reliability)

9

Enclosure

1R11

Licensed Operator Requalification Program

1.

Resident Quarterly Review (71111.11Q - 1 sample)

a.

Inspection Scope

The inspector observed the performance of Operating Team 2Z during licensed

operator annual simulator exam training. Specifically, the inspector observed one

simulator session which involved multiple anomalies and entry into the EOPs for

casualty response. The inspection was conducted to assess the adequacy of the

training, licensed operator performance, implementation of the emergency plan and the

adequacy of Entergys critique. The inspector evaluated the scenario to ensure that all

critical tasks were appropriately performed by the operating crew. The inspector also

verified that the training was conducted in accordance with procedures IP-SMM TQ-114,

Continuing Training and Requalification Examinations for Licensed Personnel, and

Training Administrative Directive #202, Conduct of Simulator Training.

b.

Findings

No findings of significance were identified.

2.

Operator Requalification Biennial Program Inspection (71111.11B - 1 sample)

a.

Inspection Scope

An Operator Requalification Program inspection was conducted by two NRC region-

based inspectors from May 24 - 28, 2004. In addition, on July 7, 2004, an in-office

assessment of the 2004 annual operating exam results was performed using the

guidance of NRC Manual Chapter 0609, Appendix I, Operator Requalification Human

Performance Significance Determination Process (SDP).

The inspection activities were performed using NUREG-1021, Rev. 8, Operator

Licensing Examination Standards for Power Reactors, Inspection Procedure

Attachment 71111.11, Licensed Operator Requalification Program, and NRC Manual

Chapter 0609, Appendix I, Operator Requalification Human Performance Significance

Determination Process (SDP), as acceptance criteria, and 10 CFR 55.46 Simulator

Rule (sampling basis). The inspections were performed predominantly for IP2, although

some reviews did cover IP3 training activities.

The inspectors reviewed documentation of Unit 2 operating history since the last

requalification program inspection. The inspectors also discussed facility operating

events with the resident staff. Documents reviewed included NRC inspection reports

and licensee Condition Reports that involved human performance and Technical

Specification compliance issues.

The inspectors reviewed four comprehensive written exams from this biennial cycle that

were administered in 2004. The inspectors reviewed three sets of simulator scenarios

10

Enclosure

and 30 job performance measures (JPMs) also administered during this current exam

cycle to ensure the quality of these exams met or exceeded the criteria established in

the Examination Standards and 10 CFR 55.59.

The inspectors observed the administration of operating examinations to one crew (i.e.,

Operating Crew 2C). The inspectors observed three simulator scenarios for the

operating crew and one set of four in-plant and 13 control room JPMs administered to

individual crew members. As part of the examination observation, the inspectors

assessed the adequacy of licensee examination security measures.

The inspectors interviewed four evaluators, two training supervisors, three ROs, and five

SROs for feedback regarding the implementation of the licensed operator requalification

program. The inspectors also reviewed Training Review Group meeting minutes and

action items, QA audits, IPEC Focused Self-Assessment Reports on training, and recent

plant and industry events to ensure that the training staff modified the operator training

program, when appropriate, and responded to recommended changes.

Remedial training was assessed through the review of evaluation records for the past

two years, to ensure remediation plans were unique to the individual failures and both

timely and effective.

Conformance with operator license conditions was verified by reviewing the following

records:

Attendance records for the last two year training cycle,

Seven medical records to confirm all records were complete, that restrictions

noted by the doctor were reflected on the individuals license and that the exams

were given within 24 months,

Proficiency watch-standing and reactivation records. Documentation of licensed

operator crew watch-standing was reviewed for the current and prior quarter to

verify currency and conformance with the requirements of 10 CFR 55.

The inspectors observed simulator performance during the conduct of the examinations

but did not conduct any further inspection of the IP2 simulator. The IP2 simulator fidelity

had been questioned as a result of operator performance following the August 3, 2003

loss of off-site power event (see NRC Inspection Report 50-247/2003-013), and Entergy

was still in the process of implementing corrective actions from that discovery. The

inspectors reviewed condition report CR-IP3-2004-01582, and interviewed the IP3

simulator staff, to ensure the issues identified with the IP2 simulator were being

appropriately addressed for the IP3 simulator.

On July 7, 2004, the inspectors conducted an in-office review of licensee requalification

exam results. These results included the annual operating test and the comprehensive

written exam for both IP2 and IP3. The inspection assessed whether pass rates were

consistent with the guidance of NRC Manual Chapter 0609, Appendix I, Operator

Requalification Human Performance Significance Determination Process (SDP). The

inspectors verified that:

11

Enclosure

Crew failure rate on the dynamic simulator was less than 20%. (Failure rate was

0% for both units.)

Individual failure rate on the dynamic simulator test was less than or equal to

20%. (Failure rate was 0% for both units.)

Individual failure rate on the walk-through test (JPMs) was less than or equal to

20%. (Failure rate was 0% for both units.)

Individual failure rate on the comprehensive written exam was less than or equal

to 20%. (Failure rate was 4.3% for IP2 and 0% for IP3.)

More than 75% of the individuals passed all portions of the exam. (96% of the

individuals passed all portions of the exam for IP2 and 100% for IP3.)

b.

Findings

No findings of significance were identified.

1R12

Maintenance Effectiveness

a.

Inspection Scope (71111.12Q - 2 samples)

138 KV System

The inspector performed a review of maintenance issues associated with the 138KV

system dating back to 2002 by evaluating past condition reports and work orders

associated with the system. The inspector focused on work order IP2-02-63749

completed on May 25, 2004, which calibrated and replaced a synchronous check relay

for 138KV bus section 4-5 to evaluate work practices associated with the system. The

inspector reviewed the maintenance rule basis document to determine system

boundaries and verified that the system was being properly tracked in accordance with

the requirements of 10 CFR 50.65, Requirements of Monitoring the Effectiveness of

Maintenance. The inspector also reviewed the quarterly system health report for the 1st

quarter of 2004 and evaluated the system performance monitoring criteria for scope and

accuracy.

12

Enclosure

EQ Limit Switch ZC-PCV-1190-1 replacement

The inspector performed a review of maintenance issues associated with the

containment isolation valve (CIV) system dating back to 2002 by evaluating past CRs

and work orders associated with this system, and on valve performance test data. The

inspector focused on WO IP2-02-65939 completed on May 28, 2004, which replaced the

open limit switch ZC-PCV-1190-1 on relief valve PCV-1190, and WO IP2-04-18766,

which performed the post-maintenance stroke test of the valve. The inspector reviewed

the maintenance rule basis document to determine system boundaries and verified the

system was being properly tracked in accordance with the requirements of 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance.

b.

Findings

No findings of significance were identified.

1R13

Maintenance Risk Assessment and Emergent Work Activities

a.

Inspection Scope (71111.13 - 4 samples)

The inspector observed selected portions of emergent maintenance work activities to

assess Entergys risk management in accordance with 10 CFR 50.65(a)(4). The

inspector verified that Entergy took the necessary steps to plan and control emergent

work activities, to minimize the probability of initiating events, and to maintain the

functional capability of mitigating systems. The inspector observed and/or discussed

risk management with maintenance and operations personnel for the following activities.

CR-IP2-2004-01894, Generex Regulator Trouble Alarm.

Work Order (WO) IP2-04-19548, Replace GT-1 black start diesel jacket water

temperature switch.

WO IP2-04-09050, 22 SG level indicator, current repeater card replacement.

WO IP2-03-07175, 24 Battery Charger Ground Troubleshooting.

b.

Findings

No findings of significance were identified.

1R14

Personnel Performance During Non-Routine Plant Evolutions and Events

a.

Inspection Scope (71111.14 - 1 sample)

The inspectors reviewed operator response during a 13.8KV distribution system

automatic voltage reduction annual test on April 27, 2004. The inspectors reviewed

operator logs, system operating procedure (SOP) 27.1.3, Operation of 13.8KV

System, and discussed interactions between the on-shift crew and the grid operator to

determine if appropriate actions were taken based on the system conditions.

13

Enclosure

b.

Findings

No findings of significance were identified.

1R15

Operability Evaluations

a.

Inspection Scope (71111.15 - 5 samples)

The inspectors reviewed the condition reports listed below and associated operability

evaluations to ensure operability was properly justified and that the component or

system remained available, without a significant degradation in performance or

unrecognized operability issue. As appropriate, the inspectors used Technical

Specifications (TS), Updated Final Safety Analysis Report (UFSAR), and design basis

documents. The inspector also conducted a physical walk down of the affected

equipment (when practicable), reviewed applicable drawings and operating procedures,

and discussed the operability evaluation with the responsible systems engineer.

Operability evaluations associated with these condition reports were also reviewed.

CR-IP2-2004-01384, Charging pump reliefs back pressure compensation.

CR-IP2-2004-01353, 13.8 KV breaker B2-2 after control power fuse

replacement.

CR-IP2-2004-01716, SW pump/system operability post-LOCA during transition

to cold leg recirculation.

CR-IP2-2004-02017, 13.8KV system during voltage reduction test.

CR-IP2-2004-02648, GT-1 trip on compressor journal bearing high temperature

following monthly surveillance test.

b.

Findings

. The 13.8 KV system is one of two off-site electrical circuits required by

Technical Specifications (TS).

Description. In May 2003, the NRC identified that Entergy had not adequately evaluated

the potential impact of a reduced voltage test on the operability of the 13.8 KV system

(CR IP2-2003-3470). The annual test, conducted by the transmission operator, reduces

the voltage of the TS required alternate power supply by eight percent. The inspectors

determined that Entergy's operability determination, completed after the test, was

inadequate based on the absence of an evaluation of in-plant accident electrical loads to

determine a minimum acceptable voltage required to be supplied by the 13.8 KV system

and the absence of communication protocols between Entergy and the transmission

operator for the control of degraded voltage testing. The NRC issued a Green Finding

(FIN 50-247/2003-007-01) based on the inadequate operability evaluation.

On April 27, 2004, the transmission operator again performed the annual voltage

reduction test on the 13.8 KV system. After discussion with the inspectors, the control

14

Enclosure

room operators made a late entry into TS LCO 3.8.1, condition A, for the 13.8 KV

system being out-of-service. The operators declared the 13.8 KV system inoperable

based upon the absence of procedural guidance on whether the system was operable at

the reduced voltage. TS LCO 3.8.1, condition A, was in effect for eight minutes and the

total duration of the test was 30 minutes. After further discussions with Entergy

personnel and a review of circumstances and documentation associated with the May

2003 finding, the inspectors determined that Entergy had not taken appropriate

corrective actions following the May 2003 event to provide the control room operators

with criteria for making an operability determination while the 13.8 KV system was under

test.

Analysis. The inspectors determined that the performance deficiency associated with

this event was Entergys failure to implement appropriate corrective actions, including an

evaluation of the minimum acceptable voltage requirement for the 13.8 KV off site

power source, to prevent a recurrence of the May 2003 event. Entergy had not

corrected their May 2003 operability evaluation and had not provided appropriate

guidance to plant operators in the event the 13.8 KV electrical power feed became

similarly degraded. Traditional enforcement does not apply since there were no actual

safety consequences or potential for impacting the NRCs regulatory function, and the

finding was not the result of any willful violation of NRC requirements or Entergys

procedures. This finding was determined to be greater than minor because it impacted

the mitigating systems cornerstone objective, and was associated with the cornerstones

procedure quality attribute.

TS bases state that the 13.8 kV system is a delayed access power source since

operator action is required to align the 13.8 KV system to supply the plant. The UFSAR,

Chapter 8, "Electrical Systems," states that the 13.8 KV system should be available in

sufficient time following a loss of onsite power, and the other offsite power circuits (138

KV), to ensure that fuel design limits and design conditions for the reactor coolant

system are not exceeded. After the 13.8 KV system operability questions were raised

by the inspector on April 27, 2004, Entergy determined that the minimum required

voltage to ensure reliable ECCS operation was 13.4 kV (<3 percent reduction). Based

upon this criteria, the inspectors determined that the licensee failed to ensure the

reliability and capability of mitigating systems supplied by the 13.8 KV system. This

finding relates to the cross-cutting issue of problem identification and resolution. The

inspectors conducted a Phase 1 SDP screening and determined that the failure to

implement appropriate and timely corrective actions was of a very low safety

significance since there was no loss of the normal offsite power supplies and the 13.8

KV system was not providing power to any safety-related loads during the degraded

condition. This issue has been placed in Entergys CAP as CR-IP2-2004-2766.

Enforcement. No violation of regulatory requirements occurred. The inspector

determined that the failure to perform timely corrective actions occurred on a non-safety

related system and therefore did not fall under the requirements of 10 CFR 50,

Appendix B. (FIN 50-247/04-06-04; Failure to implement adequate corrective

actions for low voltage conditions on the 13.8 KV system)

15

Enclosure

1R19

Post Maintenance Testing

a.

Inspection Scope (71111.19 - 5 samples)

The inspector reviewed post-work test (PWT) procedures and associated testing

activities to assess whether: 1) the effect of testing in the plant had been adequately

addressed by control room personnel; 2) testing was adequate for the maintenance

work order (WO) performed; 3) acceptance criteria were clear and adequately

demonstrated operational readiness consistent with design and licensing documents; 4)

test instrumentation had current calibrations, range, and accuracy for the application;

and 5) test equipment was removed following testing.

The selected testing activities involved components that were risk significant as

identified in the IP2 Individual Plant Examination. The regulatory references for the

inspection included Technical Specification 6.8.1.a. and 10 CFR 50, Appendix B,

Criterion XIV, Inspection, Test, and Operating Status. The following testing activities

were evaluated:

WO IP2-03-24066, PWT for pressure control valve PCV-1139 (22 ABFP Steam

Supply) following diagnostic testing.

WO IP2-04-19810, PWT for 22 CCW Pump after motor replacement.

WO IP2-04-19539, PWT for 21 SG Atmospheric Steam Dump (PCV-1134)

following actuator maintenance.

WO IP2-03-28334 & 22618, PWT for 22 Charging Pump after internal valve

replacement.

WO IP2-04-09383, PWT for GT-1 after flame detector failure.

b.

Findings

No findings of significance were identified.

1R22

Surveillance Testing

a.

Inspection Scope (71111.22 - 7 samples)

The inspector reviewed surveillance test procedures and observed testing activities to

assess whether: 1) the test preconditioned the component tested; 2) the effect of the

testing was adequately addressed in the control room; 3) the acceptance criteria

demonstrated operational readiness consistent with design calculations and licensing

documents; 4) the test equipment range and accuracy was adequate and the equipment

was properly calibrated; 5) the test was performed per the procedure; 6) test equipment

was removed following testing; and 7) test discrepancies were appropriately evaluated.

The surveillance tests observed were based upon risk significant components as

identified in the IP2 Individual Plant Examination. The regulatory requirements that

provided the acceptance criteria for this review were 10 CFR 50, Appendix B, Criterion

V, Instructions, Procedures, and Drawings, Criterion XIV, Inspection, Test, and

16

Enclosure

Operating Status, Criterion XI, Test Control, and Technical Specifications 6.8.1.a.

The following test activities were reviewed:

PT-Q27A 21; Auxiliary Boiler Feedwater Pump Functional Test

PT-Q51; Nuclear Power Range Analog Test

PT-SA13, Cable Spreading Room Halon Functional Test

PT-D001, Control Room Operations Surveillance Requirements

PT-M48, 480 Volt Undervoltage Alarm Test

PI-M-2, Containment Building Inspection

PT-Q62, High Steam Flow / 1st Stage Pressure Bistable Setpoint Test

b.

Findings

Introduction. A Green NCV was identified for Entergys failure to properly implement a

surveillance required by the Technical Specifications (TS). Entergy had not performed

channel checks on the feedwater flow instrumentation since implementing the Improved

Standard Technical Specifications (ITS) on December 12, 2003. This was determined

to be a violation of Technical Specification Surveillance Requirement SR 3.3.1.1, which

requires that a channel check be performed on the feedwater flow instrument every

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Description. On June 4, 2004, Entergy noted that one channel of feedwater flow to the

21 steam generator was reading 0.3 million pounds mass per hour less than the other

channel. The inspector discussed this condition with a licensed operator to determine if

this was less than the maximum deviation allowed for the instrument channel check.

The operator informed the inspector that no channel check was performed on the feed

flow instrumentation and that none was required. Upon further review, the inspector

found that SR 3.3.1.1 required that a channel check for feedwater flow was required to

be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This requirement had not been met since Entergy

implemented ITS in December of 2003. Entergy documented this deficiency in CR-IP2-

2004-2656 and implemented actions to perform the appropriate surveillance on the

required periodicity.

Analysis. The inspectors determined that this was a performance deficiency since

Entergy failed to perform the required surveillance. Control room operators perform

surveillance procedure 2-PT-D001, Control Room Operations Surveillance

Requirements, every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, which captures the channel checks required by ITS in

the control room; however, the feedwater flow instruments were omitted from this

procedure. Traditional enforcement does not apply since there were no actual safety

consequences or potential for impacting the NRCs regulatory function, and the finding

was not the result of any willful violation of NRC requirements or Entergy procedures.

This finding was determined to be greater than minor because it represents the

conditions similar to those described by example 1.c in Appendix E of IMC 0612,

involving the failure to perform a TS surveillance test for an extended period of time.

The feedwater flow signal is used in conjunction with steam flow and steam generator

(SG) level to ensure protection is provided against a loss of heat sink, and actuates the

17

Enclosure

auxiliary feedwater (AFW) system prior to a low level that could uncover the SG tubes.

The channel check surveillance is a qualitative assessment performed by observation of

channel behavior during operation which includes a comparison of multiple channel

indications. This is used to help assure that the system will operate properly when

required to perform its safety function. The failure to perform the required surveillance

impacted the mitigating systems cornerstone objective, and was associated with the

cornerstones procedure quality attribute. Entergys failure to include this surveillance in

their test procedure prevented them from ensuring the reliability of a system that

responds to initiating events to prevent undesirable consequences. The inspectors

conducted a Phase 1 SDP screening and determined that the failure to perform the

required surveillance was of a very low safety significance since the feedwater flow

instruments met the surveillance criteria when subsequently performed, and did not

render the mitigating equipment inoperable.

Enforcement. ITS SR 3.3.1.1 requires, in part, that a channel check of feedwater flow

instrumentation be performed every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to this requirement Entergy

failed to perform this surveillance requirement from December 12, 2003 to June 8, 2004.

This was determined to be a violation of Entergys Technical Specifications. Because

this violation is of very low safety significance and has been entered in Entergys

corrective actions program (CR IP2-2004-2656), this violation is being treated as an

NCV consistent with Section VI.A of the NRC Enforcement Policy: (NCV 50-247/04-06-

05; Failure to implement a Technical Specification Surveillance Requirement).

1R23

Temporary Plant Modifications

a.

Inspection Scope (71111.23 - 2 samples)

The inspector reviewed temporary alterations associated with the recirculation sump and

the containment sump that were initiated to prevent sump screen bypass flow via gaps

around piping and associated equipment penetrations in the deck plating directly above

the sumps. The inspector reviewed: 1) the individual temporary alteration control

packages to ensure these plant modifications were performed in accordance with ENN-

DC-136, Temporary Alterations, Revision 7, dated 3/29/04; and 2) to ensure

compliance with 10 CFR 50.59 screen-out evaluations associated with each of these

modifications. To verify compliance, the inspector also conducted a visual examination

of each of the temporary alterations in containment on June 19, 2004, in conjunction

with Entergys monthly containment entry and inspection at power conditions. The

inspector reviewed the following documents associated with temporary modifications of

the recirculation sump and the containment sump:

Recirculation Sump

TA-04-2-078, Install clamps on pipe collars around recirculation pump 21 and 22

bypass lines, WO No. IP2-04-18017; installed April 22, 2004.

TA-04-2-080, Install clamp on 2-inch pipe (line No. SI-601R-293) above the

collar at the recirculation sump, WO No. IP2-04-18146; installed April 28, 2004.

18

Enclosure

TA-04-2-081, Install a temporary clamp on the identified pipe above the collar at

the recirculation sump, WO No. IP2-04-18178; installed April 28, 2004.

TA-04-2-083, Install a clamp on No. 22 recirculation pump one-inch drain line

from seal leak-off and motor cooler to the recirculation sump above the collar,

WO No. IP2-04-18321; installed April 28, 2004.

Containment Sump

TA-04-2-082-001, Reduce gap around components penetrating the containment

sump deck plate, WO No. IP2-04-18268, installed April 28, 2004.

The inspector also referenced station procedure ENN-LI-101, 10 CFR 50.59 Review

Process.

b.

Findings

No findings of significance were identified.

1EP6

Emergency Plan Drill

a.

Inspection Scope (71114.06 - 1 sample)

On May 12, 2004, the inspectors observed Entergys emergency response organization

during an announced emergency preparedness training drill initiated at IP3 and

extending to the entire site. The simulated emergency included the activation of the

Operations Support Center (OSC),Technical Support Center (TSC), Emergency

Operations Facility (EOF), and the Joint News Center (JNC) after an Alert (simulated)

was declared by the simulator control room operators.

The inspectors observed the conduct of the exercise in the TSC and the EOF. The

inspectors assessed licensed operator performance, Entergys adherence to Emergency

Plan Implementing Procedures, and their response to simulated degraded plant

conditions. The inspectors verified licensee performance in the classification,

notification, and protective action recommendations. In addition to the drill, the

inspectors observed Entergys controller critique and evaluated Entergys self-

identification of weaknesses and deficiencies. CR-IP2-2004-00599 concluded that three

of four performance indicator opportunities (classifications, notifications, and protective

action recommendations) were successful. The inspectors compared Entergys

identified findings against their observations.

b.

Findings

No findings of significance were identified.

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety (OS)

19

Enclosure

2OS3 Radiation Monitoring Instrumentation and Protective Equipment

a.

Inspection Scope (71121.03 - 9 samples)

During May 10-14, 2004, the inspector conducted the following activities to evaluate the

operability and accuracy of radiation monitoring instrumentation, and the adequacy of

the respiratory protection program for issuing self-contained breathing apparatus

(SCBA) to emergency response personnel. Implementation of these programs was

reviewed against the criteria contained in 10 CFR 20, applicable industry standards, and

Entergys procedures. Nine inspection activity samples were selected consistent with

Sections 02.01 through 02.06 of Inspection Procedure 71121.03. The inspector also

reviewed the Condition Reports involving radiation protection relate matters initiated

between April and May 2004.

Plant walkdowns of accessible plant radiation monitors, review of the calibration

methods and review of the most recent calibration records were performed for the

following instruments:

R-28, 29, 30, 31, main steam line radiation monitors

R-41, 42, gaseous and particulate containment radiation monitors

R-2,7, refueling floor area radiation monitors

R-49, steam generator blow down radiation monitor

The inspector selected in-use portable radiation survey and continuous air monitor

instruments for operable condition, source response checks, and reviewed the most

recent calibration records for the following instruments:

PRM-7 micro-R meter #315

RO-2 ion chamber #05250

RO-2A ion chamber #10193

Teletector # 05177

Gilian lapel air samplers # 05266 and 05269

NMC continuous air monitor #05277

RM-14 contamination monitor #05161

The inspector evaluated the adequacy of the respiratory protection program regarding

the maintenance and issuance of self-contained breathing apparatus (SCBAs) to

emergency response personnel. Training and qualification records were reviewed for

42 licensed operators from each of the six operating shifts, who would be required to

wear SCBAs in the event of an emergency. Emergency plan specified SCBA

equipment and air bottle inventory, for the IP2 control room and technical support

center, were verified. Selected SCBAs and air bottles were verified to be operable.

Maintenance records were also reviewed.

b.

Findings

No findings of significance were identified.

20

Enclosure

4.

OTHER ACTIVITIES (OA)

4OA1 Performance Indicator (PI) Verification

a.

Inspection Scope (71151 - 5 samples)

The inspectors reviewed Entergys Performance Indicator (PI) data for five indicators to

verify whether the data was accurate and complete. The inspectors compared the PI

data reported by Entergy to information gathered from control room logs, condition

reports, and work orders for the four quarters of 2003 and the first quarter of 2004. In

addition, the inspectors compared the PI data against the guidance contained in NEI 99-

02, Revision 1.

Reactor Safety Cornerstone

Unplanned Power Changes per 7,000 Critical Hours

Safety System Unavailability - Auxiliary Feedwater

Safety System Unavailability - Emergency AC Power

Reactor Coolant System Activity

The inspector observed an RCS activity sample in progress and the subsequent

laboratory analysis on June 25, 2004, and compared the results and trend to the PI data

reported for the fourth quarter of 2004.

Scrams with Loss of Normal Heat Sink

The inspector noted that the three unplanned scrams and loss of normal heat removal

events that occurred in 2003 (April 28, August 3, and August 14) were all attributed to

loss of offsite power events. However, consistent with Regulatory Issue Summary 2001-

25, which endorses NEI 99-02 guidance, and NRCs response in Frequently Asked

Questions 354, posted September 25, 2003, these three loss of normal heat removal

events are not counted under this PI.

b.

Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

1.

Baseline Procedure Problem Identification and Resolution Review (71152)

As required by Inspection Procedure 71152, "Identification and Resolution of Problems,

and in order to help identify repetitive equipment failures or specific human performance

issues for follow-up, the inspectors screened each item entered into Entergys

Corrective action program. This review was accomplished by reviewing hard copies of

each condition report.

21

Enclosure

2.

Semi-annual Trend Review

a.

Inspection Scope (71152 - 1 sample)

The inspectors reviewed Entergys corrective action program database over the last two

calendar quarters of 2003 and the first two quarters of 2004 in order to assess the total

number and significance of CRs written in various subject areas such as equipment and

processes. The results were evaluated on a per quarter basis to identify any notable

trends. The assessment specifically consisted of CR reviews in the following areas:

Level A CRs: which required a full root cause analysis and review by the

Corrective Actions Review Board (CARB) prior to closeout; and Level B CRs:

which required an apparent cause evaluation and an optional CARB review.

The number and significance of CRs associated with plant equipment previously

identified as having reliability issues.

A review of the corrective action database to assess trends in the number of

CRs written in the previous four quarters that were related to subject areas that

reflect the quality of maintenance, work controls, operations, procedures, etc.

A review of the Indian Point Energy Center Quarterly Integrated Self-

Assessment/Trend Reports for 3Q03, 4Q03, and 1Q04 written by the IPEC

Quality Assurance Department, which contained Entergys assessments of CR

trends during those quarters.

22

Enclosure

b.

Findings

No findings of significance were identified.

3.

Quarterly Problem Identification and Resolution Review

a.

Inspection Scope (71152 - 2 samples)

CR-IP2-2003-6247: Negative trend in Operations Department configuration

management and controls, potentially impacting mitigating systems operability

and availability. The inspector reviewed the adequacy of the corrective actions

associated with this condition report. The inspector also reviewed CR-IP2-2004-

01746 which identified a similar adverse trend in the number of mispositioning

events. The corrective actions for the latter CR were found to be significantly

more robust and far reaching than the former CR. The inspector determined that

corrective actions were appropriate to address the determined causal factors and

that Entergy was identifying the discrepant issues at a low threshold.

CR-IP2-2003-7219: Negative trend on overdue preventive maintenance activities

at both IP2 and IP3, potentially having an adverse impact on mitigating systems.

The inspectors assessed the corrective actions documented in related condition

reports CR-IP2-2003-07155 and CR-IP2-2003-07156, and reviewed the trend in

overdue preventive maintenance activities at IP2 for the first six months of 2004.

b.

Findings

No findings of significance were identified.

4.

Cross-References to PI&R Findings Documented Elsewhere

Inspection findings in previous sections of this report also had implications regarding

Entergys identification, evaluation, and resolution of problems, as follows:

Section 1R07.2 - Failure to promptly identify and take actions to address a

condition adverse to quality concerning a recirculation sump screen bypass

flowpath and containment debris.

Section 1R07.3 - Engineering failed to promptly identify and take actions to

address a condition adverse to quality concerning EDG HX fouling.

Section 1R15.1 - Failure to take adequate corrective actions to resolve issues

associated with voltage reduction on the 13.8 KV system.

23

Enclosure

4OA3 Event Followup

a.

Inspection Scope (71153 - 4 samples)

1.

(Closed) Licensee Event Report (LER) 2003-004, Automatic Turbine/Reactor Trip Due

to 345kV Grid Disturbance.

NRC inspection observations and findings associated with the event discussed in LER

2003-004, dated October 2, 2003, are documented in Sections 4 and 5 of Inspection

Report 50-247/03-013, dated December 22, 2003. This LER is closed.

2.

(Closed) LER 2003-001, Plant in an Unanalyzed Condition due to Cable Routing Non-

Compliance with Appendix R Separation Criteria.

Initial NRC inspector review of the non-conforming condition documented in LER 2003-

001, dated April 2, 2003, was documented in Inspection Report 50-247/03-03, dated

May 13, 2003. Pending further inspector review, an unresolved item was assigned to

this issue (URI 50-247/03-03-01). The unresolved item was reviewed and closed as a

licensee-identified finding in Inspection Report 50-247/04-05. The non-conforming cable

separation condition was identified as low safety consequence, consistent with Appendix

F, Fire Protection SDP. This LER is closed.

3.

(Closed) LER 2002-006, Two of Three Emergency Diesel Generators Inoperable Due

to Component Failures: A Condition Prohibited by Technical Specifications.

NRC observations and findings associated with the event discussed in LER 2003-006,

dated December 4, 2002, are documented in Inspection Report 50-247/02-07, dated

February 11, 2003. Entergy appropriately adhered to the Technical Specifications

limiting conditions for operation and there were no violations of NRC requirements

associated with this event. This LER is closed.

4.

(Closed) LER 2002-005, Central Control Room Wall Identified as Being in Non-

Conformance with Design Drawings.

NRC inspector review of this licensee-identified original construction/design deficiency

was documented in Inspection Report 50-247/02-07, dated February 11, 2003.

Entergys discovery of this condition was prompted by their extent of condition review for

associated control room west wall fire barrier deficiencies. Entergys corrective actions

for this construction deficiency were determined to be appropriate (reference Inspection

Report 50-247/03-10, dated August 4, 2003). This non-conforming condition was

dispositioned as a licensee-identified violation (see Section 4OA7). This LER is closed.

b.

Findings

No findings of significance were identified.

4OA5 Other Activities

24

Enclosure

1.

Offsite Power System Operational Readiness

Cornerstones: Initiating Events, Mitigating Systems

a.

Inspection Scope (2515/156)

The inspectors performed Temporary Instruction 2515/156, Offsite Power System

Operational Readiness. The inspectors collected and reviewed information pertaining

to the offsite power system specifically relating to the areas of the maintenance rule

(10 CFR 50.65), the station blackout rule (10 CFR 50.63), offsite power operability, and

corrective actions. The inspectors reviewed this data against the requirements of

10 CFR 50 Appendix A General Design Criterion 17, Electric Power Systems, and

Plant Technical Specifications. This information was forwarded to NRR for further

review.

b.

Findings

No findings of significance were identified.

2.

(Closed) URI 05000247/200402-04: Evaluation of the Frequency limits associated with

the 118 VAC instrument bus and determination of the impact of operating at 60.7 Hz on

risk significant loads.

The inspectors reviewed Entergy evaluation of operating the instrument busses at 60.7

Hz due to an inoperable inverter and the impact this could have on risk significant loads.

It was determined that the acceptable operating range based on the most limiting

components was 57.0-63.0 Hz. Within that frequency range all component output

signals would still be within the required tolerance. It was found that based on original

purchase documents, the most limiting component would only tolerate a +/- 0.6 HZ

deviation but the as delivered equipment was more tolerant of frequency variations and

could therefore maintain its required accuracy over a +/- 3.0 Hz deviation. It was

determined that there was no adverse impact from operating the instrument bus at 60.7

Hz. No violation of NRC requirements was identified. This unresolved item is closed.

4OA6 Meetings, Including Exit

1.

Routine Exit Meetings

On

the inspectors met with Indian Point 2 representatives to review the

inspection activities. At that time, the purpose and scope of the inspection were

reviewed, and the preliminary results were presented. Entergy acknowledged the

preliminary inspection results.

The inspectors asked Entergy whether any materials examined during the inspection

should be considered proprietary. No proprietary information was reviewed during this

inspection.

25

Enclosure

The inspectors for the Operator Requalification Program presented the inspection

results to members of licensee management at the conclusion of the inspection on

May 28, 2004, and obtained pass/fail results from a licensee representative on

July 6, 2004. No materials reviewed were identified by Entergy as proprietary.

2.

Management Site Visits

On July 14, 2004, Ellis Merschoff, Deputy Executive Director of Reactors and Brian

Holian, Deputy Director, Division of Reactor Projects, visited the Indian Point Energy

Center, toured IP2 and IP3 plant areas, and met with senior members of Entergy

Nuclear Northeast, Inc.

4OA7 Licensee-Identified Violation

The following violation of very low safety significance (Green) were identified by the

licensee and is a violation of NRC requirements which meet the criteria of Section VI of

the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a non-cited

violation:

10 CFR 50, Appendix B, Criterion III, states that measures shall be established

to assure that applicable regulatory requirements and design basis for

structures, systems, and components are correctly translated into specifications

and drawings to ensure essential safety-related functions are established and

maintained. Contrary to this requirement, Entergy identified the central control

room south masonry wall did not meet the specific design basis earthquake

requirements as described in the IP2 Final Safety Analysis Report. However, the

seismic qualification of the wall was evaluated by the licensee and determined to

have remained operable, but degraded. This issue was documented in CR

2002-09027 and LER 2002-005, dated February 11, 2003. This licensee-

identified violation was of very low safety significance.

ATTACHMENT: SUPPLEMENTAL INFORMATION

A-1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel:

W. Axelson

Radiological Engineering Supervisor

T. Barry

Security Superintendent

T. Beasley

System Engineering

F. Bloise

PI-10 Project Manager

T. Burns

NEM/Respiratory Protection Supervisor

R. Christman

Supervisor, Nuclear Operator Training

P. Conroy

Licensing Manager

F. Dacimo

Site Vice President

G. Dahl

Senior Licensing Engineer

R. Deschamps

Radiation Protection Coordinator

R. DeCensi

Technical Support Manager and Radiation Protection Manager

C. English

Unit 1 Project Coordinator

D. Gainer

Risk Analyst

D. Gately

Assistant Radiation Protection Manager

D. Gray

Environmental Engineer

P. Gropp

Manager DBI Project

G. Hocking

Instruments and Dosimetry Supervisor

F. Inzirillo

Emergency Preparedness Manager

T. Jones

Nuclear Safety/Licensing Specialist, Licensing

M. Kerns

Chemistry Manager

R. LaVera

ALARA Supervisor

L. Lee

System Engineering Supervisor, Support Systems

T. McCaffrey

Manager of System Engineering

D. Mayer

Unit 1 Project Manager

R. Milici

Senior Engineer, Electrical Design Engineering

K. Naku

Unit 2 Instrumentation and Controls Assistant Superintendent

J. ODriscoll

System Engineer (CCW)

D. Pace

Vice President - Engineering Northeast

J. Peters

Unit 2 Plant Chemist

S. Petrosi

Manager, Design Engineering

J. Raffaele

Design Engineering Supervisor - Electrical

R. Robenstein

Simulator Support Leader

B. Rokes

Senior Licensing Engineer

A. Singer

Supervisor, Nuclear Operator Requalification Training

R. Sutton

Maintenance Rule Coordinator

J. Toscano

System Engineering

J. Tuohy

Manager Engineering Support

M. Vasely

Engineering Supervisor

R. Walpole

Nuclear Manager

C. Wend

Radiation Protection Superintendent

D. Wilson

Chemistry Assistant Superintendent

A-2

Attachment

B. Young

Senior Mechanical Engineer

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened/Closed

NCV 50-247/04-06-01

Failure to implement appropriate design controls during

modifications to the recirculation sump.

NCV 50-247/04-06-02

Failure to identify and correct deficiencies associated with the

recirculation sump.

NCV 50-247/04-06-03

Failure to identify a condition adverse to quality which could

impact EDG reliability.

FIN 50-247/04-06-04

Failure to implement adequate corrective actions for low voltage

conditions on the 13.8 KV system.

NCV 50-247/04-06-05

Failure to implement Technical Specification Surveillance

Requirement SR 3.3.1.1 for channel checks of the feedwater flow

instrumentation.

Closed

LER 2003-004

Automatic Turbine/Reactor Trip Due to 345kV Grid Disturbance.

LER 2003-001

Plant in an Unanalyzed Condition due to Cable Routing Non-

Compliance with Appendix R Separation Criteria.

LER 2002-006

Two of Three Emergency Diesel Generators Inoperable Due to

Component Failures: A Condition Prohibited by Technical

Specifications.

LER 2002-005

Central Control Room Wall Identified as Being in Non-

Conformance with Design Drawings.

URI 50-247/04-02-04

Static inverter frequency specification for operability.

A-3

Attachment

LIST OF BASELINE INSPECTIONS PERFORMED

71111.04

Equipment Alignment

1R04

71111.05

Fire Protection

1R05

71111.06

Flood Measures

1R06

71111.07

Heat Sink Performance

1R07

71111.11

Operator Requalification

1R11

71111.12

Maintenance Effectiveness

1R12

71111.13

Maintenance Risk Assessment and Emergent Work Activities

1R13

71111.14

Personnel Performance During Non-Routine Plant Evolutions

1R14

71111.15

Operability Evaluations

1R15

71111.19

Post Maintenance Testing

1R19

71111.22

Surveillance Testing

1R22

71111.23

Temporary Plant Modifications

1R23

71114.06

Emergency Plan Drill

1EP6

71151

Performance Indicator Verification

4OA1

71152

Problem Identification and Resolution Sample

4OA2

71153

Event Followup, LERs, Open Items

4OA3

LIST OF DOCUMENTS REVIEWED

Section 1R04: Equipment Alignment

Clearance 2C16

Tagout 2-480V-MCC26B-6MR (MOV887B) Bucket PM

Tagout 2-480V-MCC26B-4DR (MOV851B) Bucket PM

Tagout 2-480V-22SIP 2A Breaker EM

CR-IP2-2004-02898

Section 1R05: Fire Protection

Fire Protection Implementation Plan, Pre-Fire Plans

Station Administrative Order (SAO)-700, Fire Protection and Prevention Policy,

SAO-703,

ENN-DC-161, Transient Combustible Program.

Section 1R06: Flood Protection Measures

IPEEE, Section 5

2AOP-FLOOD-1, Flooding

Background Document for 2AOP-FLOOD-1

Operations Document Feedback IP2-4826

WO IP2-03-06699

A-4

Attachment

Section 1R07: Heat Sink Performance

89-13 Program and Design Basis Documents

WCAP-12313, Safety Evaluation for an Ultimate Heat Sink Temperature Increase to 950F at

Indian Point Unit 2, Rev. 2, dated January 2004

Consolidated Edison Letter, Stephen B. Bram to the NRC, dated February 2, 1990, Service

Water System Problems Affecting Safety Related Equipment

Consolidated Edison Letter, Stephen B. Bram to the NRC, dated July 19, 1991, Implementation

Status of Generic Letter 89-13 Required Actions

EPRI NP-7552, Heat Exchanger Performance Monitoring Guidelines, December 1991

EPRI TR-107397, Service Water Heat Exchanger Testing Guidelines, March 1998

Corrective Action Documents (CR-IP2-20XX)

01-05679

02-05311

02-05637

02-06897

02-06905

02-07065

02-08272

02-09667

02-10749

02-10853

03-00860

03-00886

03-00912

03-02592

03-03166

03-03741

03-04192

03-04618

03-06197

03-06539

04-00277

04-00341

04-00450

04-00998

04-01416

04-01781

04-01820

04-08597

04-08931

Engineering Evaluations and Calculations

TA-03-2-111-001, Remove Internals From S.W. Strainer Blowdown Valves

TA-04-2-078, Install Clamps on Pipe Collars Around Recirc Pump 21 and 22 Bypass

PGI-00186-00, Test Data and Analysis for IP2 Safety Injection Pump Lube Oil Cooler

Performance, Rev. 0

PGI-00219-00, RHR Heat Exchangers Performance - 1996, dated 11/8/96

PGI-00354-02, Generic Letter 89-13 Heat Exchanger Performance Assessment Program,

dated 1/11/01

FMX-00295-00, Tube Plugging Limits for EDG Lube Oil Coolers and Jacket Water Coolers, Rev.

0

FMX-00142-00, Study the Effect of LOCA Generated Debris on ECCS Performance, dated

12/22/1999

EDG Testing and Inspections

SE-330 Inspection Report for 21 EDG HXs, dated 2/16/03

SE-330 Inspection Report for 21 EDG HXs, dated 6/16/03

SE-330 Inspection Report for 21 EDG HXs, dated 2/24/04

SE-330 Inspection Report for 22 EDG HXs, dated 10/27/02

SE-330 Inspection Report for 22 EDG HXs, dated 4/23/03

SE-330 Inspection Report for 22 EDG HXs, dated 3/23/04

SE-330 Inspection Report for 23 EDG HXs, dated 1/7/02

SE-330 Inspection Report for 23 EDG HXs, dated 5/19/03

A-5

Attachment

Record of Eddy Current Inspection of Emergency Diesel Generator 21 Lube Oil Cooler & Jacket

Water Cooler at IP2, dated 2/25/03

Record of Eddy Current Inspection of Emergency Diesel Generator 22 Lube Oil Cooler & Jacket

Water Cooler at IP2, dated 10/2/02

Record of Eddy Current Inspection of Emergency Diesel Generator 23 Lube Oil Cooler & Jacket

Water Cooler at IP2, dated 11/6/02

PT-R84A, 21 EDG 8 Hour Load Test, dated 11/18/02

PT-R84B, 22 EDG 8 Hour Load Test, dated 11/19/02

PT-R84C, 23 EDG 8 Hour Load Test, dated 11/17/02

2-PT-M021A, Emergency Diesel Generator 21 Load Test, dated 3/22/04

2-PT-M021B, Emergency Diesel Generator 22 Load Test, dated 3/23/04

2-PT-M021C, Emergency Diesel Generator 23 Load Test, dated 3/24/04

Miscellaneous

Unit 3 Service Water Intake Pump Bay Silt Mapping, dated 7/23/01

Unit 3 Service Water Intake Pump Bay Silt Mapping, dated 2/9/04

NRC Information Notice 2004-07: Plugging of Safety Injection Pump Lubrication Oil Coolers With

Lakeweed, dated 4/7/04

PI-M2, Containment Building Inspection, Rev. 18

QS-2004-IP-004, Quality Assurance Surveillance Report, Preparations Review for NRC Heat

Sink Inspection, dated 4/12/04

IP3-LO-2004-00167, IPEC Focused Self-Assessment, Indian Point Unit 2 Ultimate Heat Sink,

dated 4/09/04

IP2 Chlorination Sample Results 1/1/03 - 9/11/03

Indian Point 2 - NRC Inspection Report No. 50-247/02-03

2003 Indian point Zebra Mussel Monitoring program Report, dated 12/18/03

2-PT-Q90, Component Cooling Water System Quarterly Alignment Verification, dated 2/22/04

Safety Assessment of the Recirculation and Containment Sumps for Indian Point Station Unit 2,

dated May 1995

Risk-Informed Inspection Notebook for Indian Point Nuclear Power Plant, Unit 2, Revision 1

Procedures

STR-P-004A, IP2 Zurn Service Water Strainers (Preventive Maintenance), Rev. 5

STR-B-003A, IP2 Zurn Spare Service Water Strainer Overhaul, Rev. 11

SOP 27.3.1.2, Emergency Diesel Generator Manual Operation, Attachment 1, Post-Run Line-up

Verification, Rev. 14

SE-330, Service Water Inspection Standard, Rev. 3

SAO-213, Containment Entry, Egress and Inspection, Rev. 5

2-AOP-SW-1, Service Water Malfunction, Rev. 2

2-COL 24.1.1, Service Water and Closed Cooling Water Systems, Rev. 36

2-COL 4.1.1, Component Cooling System, Rev. 20

COL 24.1.2, Service Water Essential Header Verification, Rev. 14

OSP 24.1, Support Procedure - Service Water System Operation, Rev. 4

SOP 24.1, Service Water System Operation, Rev. 52

SOP 24.1.1, Service Water Hot Weather Operations, Rev. 9

A-6

Attachment

2-CY-3172, Zebra Mussel Monitoring, Rev. 0

SOP-RW-007, Circulating and Service Water Sodium Hypochlorite Injection System, Rev. 26

RHR & SI Pump Testing

PT-Q28A, 21 Residual Heat Removal Pump, dated 3/30/04

PT-Q28B, 22 Residual Heat Removal Pump, dated 1/24/04

PT-Q29A, 21 Safety Injection Pump, dated 3/1/04

PT-Q29B, 22 Safety Injection Pump, dated 3/29/04

PT-Q29C, 23 Safety Injection Pump, dated 1/20/04

SW Testing

PT-Q26A, 21 Service Water Pump, dated 2/16/04

PT-Q26B, 22 Service Water Pump, dated 3/8/04

PT-Q26C, 23 Service Water Pump, dated 3/15/04

PT-Q26D, 24 Service Water Pump, dated 4/5/04

PT-Q26E, 25 Service Water Pump, dated 2/5/04

PT-Q26F, 26 Service Water Pump, dated 2/13/04

PT-3Y9, Flow Test For Underground Service Water Line 408, dated 8/21/02

PT-3Y10, Flow Test For Underground Service Water Line 409, dated 9/3/02

System Health

Maintenance Rule Program Quarterly Report (First Quarter 2004)

Unit 2 Service Water System Health Report (Fourth Quarter 2003)

Unit 2 Safety Injection System Health Report (Fourth Quarter 2003)

Unit 2 Residual Heat Removal System Health Report (Fourth Quarter 2003)

Unit 2 Emergency Diesel Generators Health Report (Fourth Quarter 2003)

Work Orders (IP2)

01-23308

02-48726

00-14369

03-10440

03-13430

03-16606

04-17509

03-16602

03-17921

Section 1R19: Post-Maintenance Testing

WO IP2-03-24066

WO IP2-04-19810

A-7

Attachment

Section 1R22: Surveillance Testing

WO No. IP2-03-21761

WRT No. IP2-04-20762

CR-IP2-2004-02644

Section 1R23: Temporary Plant Modifications

ENN-LI-101, 10 CFR 50.59 Review Process

WO No. IP2-04-18017

WO No. IP2-04-18146

WO No. IP2-04-18178

WO No. IP2-04-18321

WO No. IP2-04-18268

Section 4OA1: Performance Indicator Verification

1PC-S-009-S

Primary Sampling System Sentry

NL-04-036

Indian Point Unit 2 - 1Q2004 - PI Data Elements (QR)

NL-04-008

Indian Point Unit 2 - 4Q2003 - PI Data Elements (QR) and Change Report

(CR) for 2Q2003 and 2Q2003

NL-03-163

Indian Point Unit 2 - 3Q2003 - PI Data Elements (QR)

NL-03-122

Indian Point Unit 2 - 2Q2003 - PI Data Elements (QR)

NL-03-065

Indian Point Unit 2 - 1Q2003 - PI Data Elements (QR)

Indian Point 2 Narrative Operating Logs for 1Q2003 through 1Q2004

Section 4OA2: Identification and Resolution of Problems

CR-IP2-2003-07219

CR-IP2-2003-07155

CR-IP2-2003-07156

A-8

Attachment

LIST OF ACRONYMS

AFW

auxiliary feedwater

CAP

corrective action program

CARB

Corrective Actions Review Board

CCW

component cooling water

CFR

Code of Federal Regulation

COL

check off list

CR

condition report

CS

containment spray

ECCS

emergency core cooling system

EDG

emergency diesel generator

EOF

emergency operations facility

EP

emergency planning

EPRI

Electric Power Research Institute

GT

gas turbine

HX

heat exchanger

IMC

inspection manual chapter

IP

Indian Point

IP2

Indian Point Unit 2

IPEC

Indian Point Energy Center

IPEEE

Individual Plant Examination for External Events

ITS

improve technical specifications

JPM

job performance measures

JW

jacket water

LOCA

loss-of-coolant accident

NCV

non-cited violation

NEI

Nuclear Energy Institute

NRC

Nuclear Regulatory Commission

OA

other activities

OE

operating experience

OS

occupational radiation safety

OSC

operations support center

PAB

primary auxiliary building

PI

performance indicator

PWR

pressurized water reactor

PWT

post work test

RCS

reactor coolant system

RHR

residual heat removal

SAO

station administrative orders

SCBA

self-contained breathing apparatus

SDP

significance determination process

SE

safety evaluation

SI

safety injection

SOP

system operating procedure

SW

service water

TA

temporary alteration

TS

technical specifications

TSC

technical support center

UFSAR

Updated Final Safety Analysis Report

A-9

Attachment

VC

vapor containment

WO

work order